BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

CHAPTER 1
FIELD WIRELINE OPERATIONS
TABLE OF CONTENTS

WS-301-A Standard General Requirements for Wireline Operations ........................................... 2

WS-301-B General Safety ............................................................................................................ 2
WS-301-C H2S Safety .................................................................................................................. 4
WS-301-D Planning and Preparation ........................................................................................... 6
WS-301-E Required Wireline Surface Equipment ...................................................................... 22
WS-301-F Rigging Up of Surface Equipment ............................................................................. 23
WS-301-G Report Writing .......................................................................................................... 24
WS-301-H Function Test of Hydraulic BOP ............................................................................... 28
WS-301-I Lubricator & BOP Testing with Well Pressure ............................................................ 29
WS-301-J Annual Pressure Testing & Inspection of Surface Equipment ................................... 30

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WS-301-A STANDARD GENERAL REQUIREMENTS FOR WIRELINE

OPERATIONS

General Introduction:

1) In order to ensure that the Well Services – Wireline Crew are fully informed
about a required well intervention, detailed information has to be provided by
the Well Services Wireline Supervisor.

2) Field staff of the various concerned Sections shall be aware about the
consequences of each job in view of Production, Safety or other activities.

Field Procedure:

1) A detailed program, originated by TSW 4111, shall be available with the

Wireline Supervisor TSW 4113 / 411X

2) TSW 4113 / 411X will check the well status to verify that the requested well
intervention can be carried out correctly.

3) If in doubt, TSW 4113 / 411X shall contact TSW 4111 for further clarification.

4) TSW 4113 / 411X shall discuss with TSW 411/ 414 / 4112 the actual timing
and other details.

5) The Wireline Supervisor TSW 4113 / 411X provides the Wireline Operator
with the program, including Well status sheet, Completion diagram and / or
job related handover notes i.e. in case of crew change.

6) The Wireline operator completes a Permit to Work as per standard

procedure and holds a Tool Box meeting with his crew, discussing the
program and Safety related subjects.

7) It is the Wireline Operators responsibility to check the following:

All surface equipment on location.
All down hole equipment required available.
Test dates on pressure equipment still valid.
Check state of Wireline Unit.
Check state of K-Lift.
All relevant hoses and connections are hooked up properly.
Verify well shut in or flowing depending on type of BHP/T survey to be
carried out.
Check crew wearing proper PPE (Personal Protection Equipment)

8) At the end of his shift the Wireline Operator shall write out his reports with
observations and return these to TSW 4113 / 411X who in turn will check the
reports, enter all information, changes etc. into the computer and the
Individual well file.

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WS-301-B GENERAL SAFETY

Safe Working Procedures / Practices

Each employee is responsible for their own actions and those of other personnel
around them. A safe approach to all aspects of your work is essential and should be
made a habit.

Think and Plan Ahead

To be able to visualize potential hazards in all working environments, so as to prevent

the occurrence of undesirable or hazardous conditions and situations.

Housekeeping

• Keep your work environment clean and tidy.

• Respect and maintain the environment in which you work. Dispose of waste
correctly.
• Stairways, passages and escapes routes must be kept clear at all times.

Personal Protective Equipment should be used as required and when

appropriate. (Ref: WS-203)
• Hard hats of approved type.
• Overalls or suitable work clothing.
• Safety boots.
• Eye protection.
• Ear muffs or plugs.
• Work gloves.

Hand Tools

• Use the right tools for the task.

• Inspect tools before use and report any damaged tools immediately.
• Replace all worn parts or tools before use.
• Portable power tools must only be used by trained competent personnel.
• No electrical tools should be used in an explosive environment unless specifically
rated for such use.
• Pneumatic power tools should be used in an explosive environment.
• Do not leave tools lying in any place that may pose a hazard to others.

Lifting / Moving Equipment

• Use correct personal lifting techniques to prevent spinal or muscular injury.

• Check the weight of the item to be moved.
• Get help if the load is too heavy for one person.
• Use approved slinging equipment in the correct manner.
• Adhere to the Safe Working Loads (SWL) of cranes, slings and shackles.
• Wear a safety helmet when lifting loads by crane.

Work Permits

Always observe the permit to work procedures in place at your work site. They have
been designed to protect you and your fellow workers, and it is your responsibility to
see that the established guidelines are followed (Ref: GEN-101).
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WS-301-C H2S SAFETY

Hydrogen Sulphide (H2S) is a poisonous gas which can be present in oil and gas
producing zones. It requires special safety precautions to be taken by personnel and
the use of H2S rated equipment.

Characteristics

• H2S is heavier than air so it will be thicker at ground level.

• H2S in dangerous concentrations can kill your sense of smell instantly, so your
nose is not an adequate warning device (Refer to the chart below).
• H2S is flammable and burns with a blue flame. Sulphur dioxide (SO2) which is
also poisonous, is produced.
• H2S is soluble in fresh water. [In the correct proportions, sulphuric acid (H 2S04)
would be formed.]

Precautions

• Use your H2S monitors / alarms when the possibility of H2S exists
• Check your personal monitor and fixed alarms regularly.
• Observe the wind sock to be aware of wind direction. (A wind sock should be
visible from all areas of art H2S work location.)
• Ensure all personnel involved with H2S operations are properly trained and
certified.
• Trained personnel should carry valid H2S cards.
• It is recommended that you should be familiar with mouth to mouth resuscitation
and Cardiac Pulmonary Resuscitation (CPR) when working in an H2S area.

Emergency Response (May vary at different locations as per specific company

procedures.)

If the H2S alarms go off:

• PUT ON BREATHING APPARATUS BEFORE ENTERING THE DANGER AREA
TO RESCUER VICTIM OF H2S.
• Move the victim to fresh air as soon as possible.
• If the victim is not breathing, start artificial respiration and keep it up until he starts
breathing or until a doctor arrives.
• Summon medical help.
• If available, use a resuscitator.

H2S Safety Equipment

There are several categories of safety equipment available:

Escape System Hood or disposable filter type (approximately 5 minutes
duration).

Escape System Breathing apparatus (BA set) with face mask

(approximately 7 minutes duration from a belt mounted air
bottle).

Working / Rescue BA Face mask system (approximately 45 minutes duration

with a back-pack air bottle).

Reel Pack System For extended work durations with a face mask system
supplied from a twin bottle rack via reel mounted hoses. A
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belt mounted backup air bottle serves as an emergency

supply if hoses are cut.

Toxicity Table ppm % Symptoms

1 .0001 Can smell.

10 00I Allowable exposure - 8 hours.

Personnel Danger Level Threshold Limit Valve (TLV)

Level at which most detectors will sound the alarm.

100 .01 Kills smell in 3 to 15 minutes.

Burns eyes and throat.
500 .05 Loses sense of reasoning and balance.
Respiratory disturbances in 2 to 15 min.
700 .07 Become unconscious quickly.
1,000 .l Unconscious at once.
Permanent brain damage can occur.

POISONOUS GAS - Wear your breathing apparatus.

Move out of the area, upwind.

It is recommended that you should be familiar with mouth-to-mouth resuscitation and

Cardiac Pulmonary Resuscitation (CPR) when working in H 2S areas. Courses are
available on H2S safety, and in many cases are compulsory prior to working in an H 2S
risk area.

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WS-301-D PLANNING AND PREPARATION

The correct planning and preparation of wire line operations are essential components
in a successful wire line operation.

Preparation

Preparation should cover:

1) Liaison with production and / or drilling departments for work permits.

2) Well sketch showing the current status with all relevant sizes of tubing,
casing, down hole accessories, and flow controls.
3) Xmas tree dimensions and characteristics, tree connection threads, SCSSV
and SSV lock out features should appear on the work programme.
4) Check the well file / history for previous problems such as blockages, tight
spots, corkscrewed tubing and any other areas of potential concern.
5) It is essential that at least the last wire line well report is read and checked.
6) Transport and lifting requirements to / from / at / location.

Planning can be divided into 2 basic areas:

1. Equipment Required • Wireline units powerful enough to do the job.

Wire is torsion and tensile tested.

• Surface equipment is pressure tested and well

maintained. The tree connection, BOP's,
lubricator, weight indicator, and control panel
should comply with specifications.

• Check spare parts for all equipment is on hand or

available at a convenient location. Smaller items
such as fan belts, filters, counter cables, O-rings,
etc. should be in the toolbox.

• Redress kits for wireline tools, backup toolstrings,

wire cutting tools, hand tools, diesel, hydraulic oil,
water, etc. are available.

2. Sequence of Operations •The job should be planned on a logical and

conservative basis. A list of steps to achieve the
programme objective e.g. Run gauge cutters /
rings whenever running in the hole for the first
time or when going deeper. Run pulling tools
with no dogs to equalise plugs; set gaslift
catchers; take time to equalise when opening
SSD's etc.

Introduction to Well Services Execution Database (WSED)

WSED is a multi-user program developed to support the BSP well services executor
group TSW/4 to manage the execution of a range of well specific well service activities.
These range from collection of reservoir performance optimisation services as well as
providing supporting services for drilling work over and completion activities.
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The program has been developed to provide user with familiar Graphical Unit Interface
(GUI) features with data stored in ORACLE database. Information is presented
graphically for viewing or updating in form, tabular or spreadsheet format.

Starting Application

WSED is accessible by double clicking on the WSED shortcut. The WSED system is
started up and will automatically logging into the system using Window NT workstation
logging in user id. No password is required. If successfully, WSED Main Window is
then displayed.

WSED Main Window

After the logging in process is successfully completed, the WSED Main window will be
displayed. It has both menu bar as well as toolbar for the user to select the function to
be performed. As part of the security feature of the system, dependent on the menu
class of the user logging in, some of the menu/commands and icons will be greyed-out
and not accessible.

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File Menu
The File menu in the WSED Main window contains the sub-menu Open and command
exit WSED.
File, Exit Command
This command will allow user to ended the current session and exit WSED system.

Data Entry Menu

File, Open sub-menu

This sub-menu will allows the user to update the data pertaining to specific type of
activities, reporting,
Maintaining reference data as well as viewing activities.
It consists of the following commands or sub-menu:

Activities sub-menu
Maintenance sub-menu
Data loading, sub-menu

Request Authorisation
Planned Work Authorisation

Reports sub-menu

Explore Activities
View All

Activity Deferment

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Window Menu

The commands on this menu allow the user to change the views of the WSED
windows. With these commands, the user can arrange the opened windows in different
layouts.

Window, Cascade Command

This command will rearrange all the opened windows (MDI sheet) in the WSED Main
window (MDI frame) in cascading layout.
Window, Tile Horizontal Command
This command will rearrange all the opened windows (MDI sheet) in the WSED Main
window (MDI frame) in tile horizontal layout.

Window, Tile Vertical Command

This command will rearrange all the opened windows (MDI sheet) in the WSED Main
window (MDI frame) in tile vertical layout.

Window, Layer Command

This command will rearrange all the opened windows (MDI sheet) in the WSED Main
window (MDI frame) in layer layout with each window occupied maximum area of the
WSED Main window workspace. Only the current active window is visible.

Window, Minimize All Windows

This command will minimize all the windows.

Window, “Active window List”

The last portion of the window menu shows the list of numbered opened windows (MDI
sheets) with the current active window has a “tick” on the left. To make an opened
window active/current, simply click on the required window on the list.

Help Menu

The help facility functions in a similar way to the standard Microsoft Windows help
screen. Mouse/keyword sensitive words are displayed in green and are fully or dotted
underlined.
Selection of a fully underlined green word causes the relevant topic to be shown.
Selection of a green word with a broken underlined causes a pop-up window to appear,
displaying the definition of the word
Also, help on the current active window can be displayed by pressing the F1 key.

Help, About Command

This command displays the WSED system version number and the owner.

Help, Content Command

This command invokes the online help for the currently active window. It works in the
same way as Windows help. Plesae consult the standard windows documentation for
more information.

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File Sub-menu
The File Sub-menu in WSED Main window allows the user to update the data. It
consists of the following commands:

Open
Activities Request
Activities Planning
Activities Actual

Activities Request

The ACTIVITY REQUEST menu in WSED Main window allows the user to request for
a new activity. The SELECTION CRITERIA will be displayed for user to select which
AREA, COMPLEX, LOCATION or ACTIVITY CODE he/she needs to request. Once the
REQUEST screen is displayed, the user needs to insert a new row for a new activity
requested.

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REQUEST Selection Criteria Screen

Activity REQUEST screen

Activities Planning

The PLANNING menu in WSED Main window allows the user to plan an activity which
already been authorised. The SELECTION CRITERIA will be displayed for user to
select which AREA, COMPLEX, LOCATION or ACTIVITY CODE he/she needs to plan.
Once the PLANNED screen is displayed, the user needs to select the activity /
activities to be planned by changing the priority and/or the date.

PLANNED SELECTION CRITERIA SCREEN

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Activity PLANNED screen

Activities ACTUAL

The ACTUAL menu in WSED Main window allows the user to update an activity.
The SELECTION CRITERIA will be displayed for user to select which AREA,
COMPLEX, LOCATION or ACTIVITY CODE he/she needs to plan. Once the ACTUAL
screen is displayed, the user needs to select the activity / activities to be updated which
is Completed / Cancelled / Suspended / In Progress or Not Entered in the Status Code
or where appropriate.

ACTUAL SELECTION CRITERIA SCREEN

ACTIVITY ACTUAL SCREEN

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Maintenance Sub-menu

The Maintenance Sub-menu in WSED Main window allows you to maintain the
reference data. It consists of the following commands:
Activity Code
Activity Type
Cost Code
Resources

Activity Code

This command will open a pick list window which displays list of activity codes eg,
Request, Planned and Actual.

ACTIVITY CODE SCREEN

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Activity Type

This command will open a pick list window which displays list of activity type that have
corresponding data stored in WSED database. This command allows you to maintain
the activity type defines for an activity. The commands and icons available for

navigating and manipulation of data is as documented earlier in the WSED Common

Data Entry window section.

Cost Code

This command allows you to maintain the cost code defines for an activity
type. The commands and icons available for navigating and manipulation
of data is as documented earlier in the WSED Common Data Entry window
section.

The information displays in List of Resource window include Cost Code, Cost Code
Description, Charge Type, and Charge Rate.

Columns Description
Cost Code Cost Code defines.
Cost Code Description Description of cost code.
Charge Type Charge Type defines. Select from the dropdown list.
Charge Rate Rate in dollar.

Resources

This command allows you to maintain the types of resources. The commands and
icons available for navigating and manipulation of data is as documented earlier in the
WSED Common Data Entry window section.

The information displays in List of Resource window includes Required Resource and
Resource Type.

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Dataloading

The Dataloading sub-menu in WSED Main window enables you to import or export the
to/from a Primavera SureTrak planning tool.

Request Authorisation

The Request Authorisation sub-menu in WSED Main window enables you to authorise
an activity to be planned and executed.

Report Sub-menu

The Report sub-menu in WSED Main window enables you to produce the required
standards report to assist in monitoring and control of individual progress of the activity.
The created report will be previewed on a Report Preview window with the
corresponding menubar and toolbar, which enable you to navigate the previewed
report.

This sub-menu consists of the following commands:

Activity Listing
Activity Plan Status
By Crew
_____________
Graph By Activity Codes
Graph By Activity Status
Graph By Area
_____________

Activity Request Window

This WSED Common Data Entry window will display the selected request activity detail
for editing.

From the popup pick list Select Activity window, highlight the required activity / activities
and click OK. The commands and icons available for navigating and manipulation of
data is as documented earlier in the WSED Common Data Entry window section.

This window consists of two sections. The top section provides a list of activity (non-
editable). For each highlighted activity, the corresponding activity detail is displayed in
the bottom section of the window that is editable. Each record/row of the activity detail
section represents the phase of the activity. The current record/row in both sections is
indicated highlight.

For columns, which are editable, the corresponding microhelp information is displayed
at the left bottom corner of the screen when it is on focus.

Click on the icon or File, Insert command to generate a new request activity into
WSED database. A new record will be inserted and ready for data entry. The view only
information for the newly inserted record will be retrieved.

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On save , a popup window will prompt you for reason of inserting or editing the
record.

On Edit menu, point to Options, and then click Resources to activate the resource entry
window for the selected activity.

On Edit menu, point to Options, and then click Tasks to activate the task entry window
for the selected activity. This option is available for wellhead only.

This window contains the following information:

Column Description
Activity Id System generated number. Not editable
Activity Type Defines the available type for an activity. Select from the
dropdown list.
Activity Type Description Activity Type Description retrieved base on the activity
type selected.
Sd Dur (Hrs) Default shutdown duration in hours base on the activity
type selected.
Conduit Asset identifier, the asset upon which the activities are
requested. Select from the dropdown list.
Description Activity Description.
Survey Zone Zone to be worked on.
Priority Assigns a priority to the activity. Select from the dropdown
list.
Request Start Date The earliest date on which the requested activity can
start. The date is displayed in DD/MM/YYYY format to
ensure year 2000 compliance. This must be later than or
equal to today’s date. If it falls on the same month as
today’s date, this activity is treated as adhoc activity.
Request End Date Date on which the activity must finish. The date is system-
calculated base on the Request Start Date and duration.
Duration (Hrs) Duration in hours the activity will last
Input Authority (Proceed) Authorisation of activity to proceed. Not editable. To be
authorised by using the Request Authorisation window.
Status Activity status. If the requested activity is planned, you are
not allowed to make changes to the record. Not editable.
Planning Dept Planning Department. Not editable.

Activity Planning Window

This WSED Common Data Entry window will display the selected request activity detail
for planning.

From the popup pick list Select Authorised Requested Activity window, highlight the
required activity / activities and click OK. The commands and icons available for
navigating and manipulation of data is as documented earlier in the WSED Common
Data Entry window section.

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This window consists of two sections. The top section provides a list of activity. For
each highlighted activity, the corresponding activity detail is displayed in the bottom
section of the window that is editable. Each record/row of the activity detail section
represents the phase of the activity. The current record/row in both sections is
indicated highlight. On saving the newly created plan activity, the status of the
requested activity will be updated to planned.

For columns, which are editable, the corresponding micro help information is displayed
at the left bottom corner of the screen when it is on focus.

Click on the icon or File, Insert command to create a new planned activity into
WSED database. A new record will be inserted and ready for data entry. The view only
information for the newly inserted record will be retrieved.

On save , a popup window will prompt you for reason of inserting or editing the
record.

On Edit menu, point to Options, and then click Resources to activate the resource entry
window for the selected activity.

On Edit menu, point to Options, and then click Tasks to activate the task entry window
for the selected activity. This option is available for wellhead only.

This window contains the following information:

Column Description
Activity Id System generated number. Not editable
Activity Type Defines the available type for an activity. Not editable.
Activity Type Description Activity Type Description retrieved base on the activity
type selected. Not editable.
Sd Dur (Hrs) Default shutdown duration in hours base on the activity
type selected. Not editable.
Conduit Asset identifier, the asset upon which the activities are
requested. Select from the dropdown list. Not editable.
Description Activity Description. Not editable.
Survey Zone Zone to be worked on. Not editable.
Priority Assigns a priority to the activity. Select from the dropdown
list.
Plan Start Date The earliest planned date on which the activity can start.
The date is displayed in DD/MM/YYYY format to ensure
year 2000 compliance.
Plan End Date Date on which the activity plans to finish. The date is
system-calculated base on the Plan Start Date and
duration.
Duration (Hrs) Duration in hours the activity will last
Work Authorisation Authorisation of activity to proceed. Not editable. To be
authorised by using the Planned Work Authorisation
window.
Status Activity status. Select from the dropdown list.
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Planning Dept Planning Department.

Activity Actual Window

This WSED Common Data Entry window will display the selected planned activity
detail for actual progression. From the popup picklist Select Authorised Planned
Activity window, highlight the required activity / activities and click OK. The commands
and icons available for navigating and manipulation of data is as documented earlier in
the WSED Common Data Entry window section.

This window consists of two sections. The top section provides a list of activity. For
each highlighted activity, the corresponding activity detail is displayed in the bottom
section of the window that is editable. Each record/row of the activity detail section
represents the phase of the activity. The current record/row in both sections is
indicated highlight.

For columns, which are editable, the corresponding microhelp information is displayed
at the left bottom corner of the screen when it is on focus.

Click on the icon or File, Insert command to create a new planned activity into
WSED database. A new record will be inserted and ready for data entry. The view only
information for the newly inserted record will be retrieved.

On save , a popup window will prompt you for reason of inserting or editing the
record.

On Edit menu, point to Options, and then click Resources to activate the resource entry
window for the selected activity.

On Edit menu, point to Options, and then click Tasks to activate the task entry window
for the selected activity. This option is available for wellhead only.

This window contains the following information:

Column Description
Activity Id System generated number. Not editable
Activity Type Defines the available type for an activity. Not editable.
Activity Type Description Activity Type Description retrieved base on the activity
type selected. Not editable.
Sd Dur (Hrs) Default shutdown duration in hours base on the activity
type selected. Not editable.
Conduit Asset identifier, the asset upon which the activities are
requested. Select from the dropdown list. Not editable.
Description Activity Description. Not editable.
Survey Zone Zone to be worked on. Not editable.
Priority Assigns a priority to the activity. Select from the dropdown
list.
Actual Start Date The earliest planned date on which the activity can start.
The date is displayed in DD/MM/YYYY format to ensure
year 2000 compliance.
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Actual End Date Date on which the activity plans to finish. The date is
system-calculated base on the Plan Start Date and
duration.
Duration (Hrs) Duration in hours the activity will last
Input Authority (Proceed) Authorisation of activity. Not editable. System default to
Status Activity status. Select from the dropdown list.

Request Authorisation

This command is only accessible to executor manager. It will open a List Requested
Activity Awaiting for authorisation to proceed window. Editing is not allowed as it is only
for selection of activity for authorisation. To authorise the activity, select the required
row and click OK button. You will be prompt to either authorise the activity (Yes button),
not authorise (No button) or cancel (Cancel button). Please refer to common selecting
and sorting features.

Planned Work Authorisation

This command is only accessible to executor manager. It will open a List Planned
Activity Awaiting for authorisation to proceed window. Editing is not allowed as it is only
for selection of activity for authorisation. To authorise the activity, select the required
row and click OK button. You will be prompt to either authorise the activity (Yes button),
not authorise (No button) or cancel (Cancel button). An Actual (Activity Code) record
will be created for each authorised activity. Please refer to common selecting and
sorting features.

By Crew

Common selecting and sorting features

These features are used in the pick list windows and data entry windows.

To select Do this
An entire row Click the row.
Adjacent rows Drag across the row or column headings. Or select the
first row or column; then hold down SHIFT and select the
last row or column.
Nonadjacent rows Select the first row, and then hold down CTRL and select
the other rows.

To sort Do this
A Column Click the column header.

WSED Common Data Entry Window

Throughout the WSED program, all the tabular, form and grid windows for data entry
and record listing were designed based on a common window template, this in turn
provides a common menubar and toolbar. This common menubar and toolbar provide
the commands for the user to navigate and manipulate the data. There are additional

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commands and icons added to the common menubar and toolbar respectively that are
applicable to a specific window. The accessibility of the commands and icons are very
much dependent on the nature of the window as well as the data displayed. For
example, is the window editable?, has the data been edited? So on

Below show the icons and/or commands available in WSED Common Menubar and
ToolBar:

Icon/Command Description

File, Insert Insert a new record/row.

File, Open Call up the picklist window for selection.

Record, Save Save the changes made into the database.

File, Close Close the current active window. If data has been
modified but not saved, you will be prompt to either save
the data (Ok button), not save (No button) or cancel
closing window (Cancel button).
File, Save Row As Activate Save As window to save the data in the currently
activate window into text file, RTF file etc.

File, Print Print the data in currently activates window to the default
printer.

File, Print Preview To display each page, as it will look when printed

File, Delete Delete the currently focus record/row. User needs to

confirm the deletion.

File, Exit Close this program after prompting you to save any
unsaved data.

Edit, Undelete Call up a pick list window prompting you to choose from a
list of deleted data to restore from.

Edit, Cut Cut the currently highlighted data onto the clipboard.

Edit, Copy Copy the currently highlighted data onto the clipboard.

Edit, Paste Paste the data in the clipboard onto the currently
highlighted column/field.

Edit, Clear Delete the currently highlighted data.

View, First Move the focus to the first record/row of the data.

View, Next Move the focus to the next record/row.

View, Prior Move the focus to the previous record/row.

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View, Last Move the focus to the last record/row.

View, Sort Call up Sort window to specify the sorting order of data.
View, Filter Call up Filter window to specify the filtering criteria. Only
the data that comply to, filtering criteria will be displayed.

Window, Cascade Arrange all the opened windows (MDI sheets) within the
WSED program (MDI frame) into a cascade layout.

Window, Tile Horizontal Arrange all the opened windows (MDI sheets) within the
WSED program (MDI frame) into a tile layout.

Window, Tile Vertical Arrange all the opened windows (MDI sheets) within the
WSED program (MDI frame) into a tile layout.

Window, Layer Arrange all the opened windows (MDI sheets) within the
WSED program (MDI frame) into a layer layout.

Window, Minimize All Windows Minimise all windows within the WSED program (MDI
frame) at the bottom of the WSED Main window.
Window,“Active windows” List of opened windows are shown at the bottom of the
Window menu. The checked window is the currently
active window. Click to make the required window
current.
Help, About Display a dialogue box which show the general
information of the program.
Help, Content Display the online help information for the currently
active window.

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WS-301-E REQUIRED WIRELINE SURFACE EQUIPMENT

Wireline service is a method whereby various well maintenance, remedial, control and
safety functions are accomplished under pressure in the wellbore. This is done by
using a `toolstring' to run and pull the tools and equipment into and out of the wellbore
by use of a small diameter wireline from a wireline unit at the surface.

To enable the tools to be run into the well under pressure, we require the surface
equipment shown below:

1) Stuffing box (alternate sealing wiper box, grease injector head).

2) Lubricators with bleed off valves.
3) BOP.
4) Tree connection.
5) K-lift, crane or rope blocks.
6) Lifting clamp.
7) Wireline clamp.
8) Hay pulley.
9) Weight indicator.
10) Wireline Unit with Counter assembly

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WS-301-F RIGGING UP OF SURFACE EQUIPMENT

The lubricator, stuffing box, wireline and wireline toolstring, are assembled. With the
pressure released from the wellhead, the proper wellhead connection is installed on the
wellhead. The box end of a quick union on the top end fits the pin end of the union on
the bottom of the wireline valve (BOP)

The wireline valve is installed onto the wellhead connection using the K-Lift, rope falls,
crane, or other hoisting means to lift the valve. Do not man handle.

The union is made up to the union on the wellhead connection, the rams closed and
the closed valve on the wellhead opened allowing full well pressure to be applied to the
wireline valve rams and connections. If no leaks appear the wellhead valve is closed,
the pressure released, and the rams opened.

The lubricator assembly is now raised to a point level with the union on top of the
wireline valve, the hoisting device secured, the wireline placed into the hay pulley, and
the slack in the wireline taken up with the wireline unit. The clamp holding the wireline
toolstring suspended in the lubricator can now be removed, allowing the toolstring to be
lowered out of the lubricator controlled by the wireline unit to a point convenient for
attaching the required service tool. With this tool attached and the odometer of the
measuring head set on zero feet, the tools are pulled back up into the lubricator and
the assembly installed onto the wireline valve.

Note : Reset the counter to zero, with the bottom of the wireline tool level with one of
the following reference points (as per the well schematic):

(i) BTHF Below Tubing Hanger Flange.

(ii) BDF or RDF Below Drill Floor or Rotary Drill Floor (if the rig is in
position).

Safety:

Injury can occur easily through the use of unsafe practices, and lack of commonsense
and concentration.

1) Maintain equipment in a safe condition.

2) Make safe work practices your habit.
3) Be aware of dangerous situations.
4) Protect your colleagues.

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WS-301-G REPORT WRITING

The accurate recording of the sequence of activities and operations performed on the
well is essential to the correct monitoring and long term life of the well.

While actual wireline report formats and data required will vary in different locations, it
should contain much of the following information:

• Date • Tubing pressure

• Well number • Casing pressure
• Field / Location • Gas injection
• Tubing size(s) • Time gaslift shut in
• Single / Dual • Time well shut in
• Tree type • Toolstring components - Diameter
- Length
• Tree connection - Size
- Type • Any tools left in the well
• Back pressure valve profile • Length of any wire left in hole
• Operator's name • Time job - Started- Completed
• Crew name • Runs and miss runs.

NOTE: Miss runs are not caused by well conditions but through HUMAN ERROR
only!!!

Work Carried Out Including all nominal dimensions and sufficient information
describing the equipment for future reference (e.g. Lock size -
nominal and seal bore; flow control type - to permit use of the
correct equalizing prong for recovery etc.)

In addition to the Daily Wireline Report, a Wire line Check

List must be completed.

When a SC-SSSV has been changed out, the SC-SSSV

Pulling / Setting Record must be filled out and returned or
faxed to the Wireline Supervisors office.

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WS-301-H FUNCTION TEST OF HYDRAULIC BOP

Test Procedure

1) Fit the BOP on the well with its hydraulic connections facing the Wireline Unit, so
that any leaks can be observed by the Wireline Operator.
2) The hydraulic hose snap couplings are fitted with a female half coupling on the outer
(closing) end of each BOP hydraulic cylinder and make half couplings on each
inner (opening) end.

The two closing and two opening couplings are respectively connected together by
a hose tee and then by the hydraulic hoses to the hydraulic connections on the
wireline unit.

3) The BOP rams can now be opened or closed by changing the vent valve
arrangement.

Note : Before operation, the manual wing screws should be wound fully open.

A visual inspection of the rubber ram seal faces for damage shall be made.

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WS-301-I LUBRICATOR & BOP TESTING WITH WELL PRESSURE

Test Procedure:

1) Ensure that lubricator is properly rigged up and secured with clamps and guy lines.
2) Ensure that stuffing box hydraulic gland nut is tight enough to seal off well pressure.
3) Ensure that a pressure gauge of the correct range is installed on the lubricator
block and bleed valve.
4) Check that the block and bleed valve on the lubricator is closed.
5) Check that the rope socket is against the stuffing box.
6) Check that all valves on the Xmas tree are closed. This should be carried out prior
to rigging up.
7) If necessary equalise the pressure across the master valve.
8) Open the master valve slowly.
9) Open the swab valve very slowly.
10) Observe test pressure for 15 minutes.
11) Close the wireline BOP rams and bleed the pressure above the BOP to zero.
12) Observe wireline BOP test for 15 minutes. Ensure that the bleed valve remains
open for the duration of the test, or install a pressure gauge into the bleed valve to
observe any leaks and rate of pressure build-up.
13) Close the bleed valve.
14) Equalise the pressure across the wireline BOP.
15) Open the wireline BOP.
16) The test is now complete, lubricator A and BOP are ready for operation.

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WS-301-J ANNUAL PRESSURE TESTING & INSPECTION OF SURFACE

EQUIPMENT

Pressure Testing

Pressure testing is to be carried out on all pressure equipment after service, and prior
to it being used offshore. For convenience, several sections of the lubricator are
assembled and subjected to pressure in the test bay up to the test pressures (TP)
required.

Test Pressure (TP) = Working Pressure (WP) x 150%.

Pressure is applied to 50% and then 100% of the test pressure, and observed for 5
minutes at each pressure.

Pressure Testing Area

A test bay area should be set up to safely test all equipment as required. It should be
designed with the following points in mind:

• Personnel safety - both of the personnel testing the equipment and other
personnel in the area.
• Warning signs and lights to advise of pressure.
• Interlocks to prevent personnel moving into the area surrounding the items
under test.
• An adequate means of viewing the items safely to inspect for leaks. This can be
safety glass panels or closed circuit TV systems.
• Reinforced walls or pit area to contain any blast effects if the equipment fails.
• Trained personnel familiar with the pumps and effects of pressure.

Testing with nitrogen (N2) requires additional care and attention to safety, as the
expansion effects of compressed gas is more dangerous and often lethal in the event
of equipment failure.

Inspection

Once a year all pressure equipment is to be inspected by a third party inspection

service and certified. The report of these inspections is kept on file by the workshop
supervisor. The following tests are to be applied for detection of cracks or flaws:

• Magnetic Particle Inspection spray (MPI) - on both connections.

• Magnafluxing (MF) - on both end connections.
• Radiographic Testing x-ray (RT) - on the collar / nut of the union.
• Hardness Test (HT or HRC) for H2S equipment - on the connections and body.
• Wall thickness - at 90° intervals around the body.

After inspection and testing, the item is equipped with a stainless steel band stating test
date, test pressure and working pressure. This information is then logged into a
designated computer file and checked on a regular bases. Items due for anannual test
will be recalled before its expired test date.

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CHAPTER 2
WIRELINE UNIT, K-LIFT, WIRE SPOOLING AND
HANDLING, HP PUMPS
TABLE OF CONTENTS

WS-302-A ASEP K-WINCH FLYLINE MODEL OPERATION MANUAL………………………… 2

WS-302-B ASEP K – WINCH FLYLINE MODEL MEASUREHEAD SYSTEM…………………. 41
WS-302-C ASEP K – LIFT GIN POLE MAST………………………………………………………. 67
WS-302-D WIRELINE INFO AND SPOOLING OF WIRE…………………………………………. 76
WS-302-E ASEP WIRE SPOOLING UNIT OPERATION MANUAL……………………………… 79
WS-302-F WIRE HANDLING…………………………………………………………………………. 91
WS-302-G TORSION TESTING OF WIRE………………………………………………………….. 93
WS-302-H TENSILE TESTING OF WIRE…………………………………………………………… 95
WS-302-I FORCE VERSUS LINE SIZE………………………………………………………………96
WS-302-J PORTABLE WELL–CONTROL PANELS, HASKEL, MO AND SSR PUMPS………. 96
WS-302-K SSR TRIPLEX PUMPING UNIT, HP - 0017……………………………………………101
WS-302-L ELMAR TEST BENCH 15,000 PSI, L-69039…………………………………………...106

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WS-302-A ASEP K-WINCH FLYLINE MODEL OPERATION MANUAL

General safety precautions

Keep these safety precautions in mind while working with our equipment. This will
prevent to the equipment and help prevent dangerous situations.

While working with ASEP equipment follow the field’s rules and regulations.

Read and understand this manual before operating ASEP equipment.

Use this manual as a guide for system operation in conjunction with common
sense and operator experience.

While working with ASEP equipment wear appropriate work clothing and
personal protective equipment as required.

Let only qualified and experienced personnel operate ASEP equipment. This
will help prevent damage to the equipment and reduce the possibility of
dangerous situations arising.

While working with ASEP equipment wear appropriate hearing protection as

required. (unit internal sound level is above 65 dB)

Before starting the diesel engine, check that the environment in which you
are about to work, is suitable for the emission of the mixture of toxic exhaust
gases.
Note: the exhaust gases contain carbon monoxide which is a colorless,
odorless and poisonous gas.

Do not restart ASEP equipment after an emergency stop without verifying

that the cause of this stop has been removed or rectified.

The equipment has been designed and built for particular purposes. Do not
attempt to use the equipment for other purposes outside its design scope.
This may lead to damage and / or dangerous situations.

During wireline operations consider the zone in front of the wireline unit as a
danger zone. For safety reasons keep the following points in mind.

•• In this zone there is always a danger

•• Never stop over the wireline
•• Never allow spectators to stand near the working area.
•• If possible, rope off this area with signs and/or bright tape.
•• If the wireline is rigged up but not run for a period. Clamp the wire and
“flag” the wire with signs.
•• When the wireline unit is tied down on deck using rope/line, “flag” the
ropes/lines with signs.

While opening hatches and/or doors on the unit beware of wind conditions.
The hatches and/or doors might swing open with force and cause damage or
injury.

When the wireline operation is finished, shut down the engines and close all
hatches and doors.

When lifting the unit by crane, make sure that you cannot get trapped
between the load and a wall, fixed object etc. If possible, position yourself so
that you are visible to the crane operator. If not, make sure to have a
flagman to give signs to the crane operator.

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Never walk under a hanging load!

Make sure that lifting gear to be used is sufficiently dimensioned and

certified.

Never leave an "operation-ready" unit unattended.

Do not operate damaged equipment. This may lead to further damage

and/or dangerous situations.

Respect and maintain your working environment. Dispose of waste correctly.

Keep all safety guards in position while operating ASEP equipment.

Removal of any safety guards may lead to accidents.

When engaged in maintenance and / or performing checks on the unit

•• First consider your safety and that of others.

•• Make sure that the equipment is switched off completely and use a
decal or similar to prevent unauthorized starting during maintenance or
check up.
•• Never work on a hydraulic and for pneumatic system under pressure.
Always relieve the system to prevent dangerous situations.
•• Never attempt to move heavy parts without aid of a mechanical device.
•• Do not allow heavy objects to rest in an unstable position.
•• Use the right tools for the task.

Let only qualified personnel with the right tools perform maintenance on

ASEP equipment. This will prevent damage to the equipment and prevent

the dangerous situations.

Parts that have not been approved by ASEP cannot be relied upon to be of

the correct material strength, correct dimensions, finish or quality. ASEP

cannot be held responsible for any damage arising from the use of such

parts.

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Safety signs

For reasons of safety the ASEP equipment is marked (if applicable) with safety signs.
Each sign indicates a possible danger zone. Keep the meaning of these safety signs in
mind while working with ASEP equipment. This will prevent dangerous situations and
personal injuries.

This sign warns for a general danger.

This sign warns for automatically starting and stopping machinery.

This sign warns for moving machinery.

Make sure that no body parts and/or clothing can get caught in the
machinery.

This sign warns for hot surfaces. Do not touch the indicated parts with
bare hands while the unit is running or has run for a time.

This sign warns for high voltage electrical parts.

Do not touch electrical components while energized.

Also all safety instructions in the manual have been earmarked with caution signs. Please
observe!
An explanation of the used earmarks is:

Used to earmark a piece of text which may be vital to ensure safe unit
operation, ignoring a WARNING! may result in unsafe and potentially
dangerous situations.

Used to earmark a piece of text which gives additional, important

information.

Used to earmark a piece of text which gives a summary of things to check.

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Unit positioning

Using a crane

The units can be lifted using the single point lifting beam. Each set of units is equipped
with one lifting beam. Each lifting beam is in turn equipped with a shackle.

Check!
This shackle is secure using a safety clip. Before commencing
lifting operations ensure proper and secure installation of the
shackle. Also inspect the lifting assembly (lifting beam, shackle
and 2 locking pins) and the lifting lugs on the unit for signs of
structural damage and or deformations. DO NOT use the lifting
assembly if structural damage and or deformations are detected.

To lift the unit install the lifting beam unto the appropriate unit. When
installing the lifting beam onto a winch frame notice the possible setup
points on the units. Move the lifting beam from front to back (3 options)
to select the correct balanced position. (Depending on the drum
configuration)

With the lifting beam into position lock the lifting beam using the
supplied pins. After pin insertion secure the pin using the safety clip.

WARNING!
DO NOT lock the lifting beam with
anything else but the supplied
locking pins. This is ensure that the
structural strength of the locking
pin can withstand the weight of the
unit.

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Using the wheels

To make it possible to move the units without use of a crane, each set of units is
equipped with a set of wheels. These wheels are stored inside the power pack.

To setup the unit, remove the wheel assemblies from the door. Attach the jack
assembly to the front side of the unit. Use the locking pin to secure the assembly into
position (secure position is as shown on picture). Loosen the tow handle and move to
the front. Use the crank handle to lift the front side of the unit. Lift the unit far enough to
make is possible to slide in the side wheel assemblies. With the side wheel assemblies
inserted lower the front side of the unit until the unit is level. The unit can now be towed
to another position. To rig down, follow the rig procedure in reverse order.

Note!
DO NOT use the unit (power pack and / or winch frame) for wireline
Operations with installed wheel assemblies.

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Before start

Unit Rig-Up

To prepare the unit for operations, do the following:

•• Position the unit on a flat and firm surface.
•• Position such that it is exactly in line with the anticipated line of operation.
The distance from the front of the unit to the lower hay pulley should not be less
than 15 m (50 ft) for optimum line spooling
•• Unlock measure head

•• Raise roof / cover (REFER PICTURE SEQUENCE FOR COVER OPEN/CLOSE)

•• Connect hoses between power pack and control/winch unit. Use the marking on
the quick connector to connect the appropriate hose to the appropriate connector.

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Before start inspection

The pre-start checklist consist of the following sections and form a procedure to be
used daily before placing the units in operation. Also, careful attention should be paid
during actual operation of the unit to observe any defects which might appear between
regular inspections especially those conditions which could possibly constitute a safety
hazard.

Warning!
DO NOT OPERATE THE EQUIPMENT UNTIL CORRECTIVE
MEASURES HAVE BEEN TAKEN AND MALFUNCTIONS HAVE
BEEN CORRECTED.

Note!
On new units, those recently overhauled, or after changing
hydraulic oil, operate all systems a minimum of two complete
cycles and recheck for oil leaks.

WARNING!
Never handle cables, chains or hoses with bare hands, as broken
or frayed armour wire strands can cause severe cuts. Always
wear protective gloves in such cases.

Prior to starting the unit, the following should be checked/inspected:

Others:

➢ Visually inspect the equipment for loose or missing parts, foreign objects,
hydraulic leaks from lines or components, and structural damage.
➢ Check for tanks and hoses leakage and for other visible (transport) damage.
➢ Check all mounting bolts on winch module (reel bearings/reel supports)
➢ Inspect main hydraulic pump group and lines for damage, evidence of leakage
and security of attachment.
➢ Check for evidence of leakage of hydraulic oil filters.
➢ Check filter indicator for element condition. Clean and/or replace element as
necessary.
➢ Ensure that cooling air intake / exhaust venting openings are not obstructed.
➢ Check for freedom of movement on the cooling fan and the proper seating of the
v-belts.
➢ Check that all components requiring lubrication are serviced as necessary.
➢ Check that no unauthorized modifications have been made to the unit.

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Fluid levels:

➢ Check the engine fuel level (fuel level indicator power pack)

➢ Check the diesel engine coolant level (radiator, upper engine compartment)

➢ Check the hydraulic oil level to be approx. 1 (cm) below tank top with
completely pressure relieved hydraulic accumulator. If not fill with Tellus T46.

➢ Check wire line lubrication oil level. Refill with thin surface lubricate. (for example
normal engine lubrication oil mixed with diesel oil)

➢ Ensure oil level drum drive gear has been checked according to maintenance
schedule as mentioned in the manual covering the “Drum Drive”-section. The
level should be half way the level eye.

Drum selection ( if applicable)

If the unit is equipped with a double drum assembly the drum selection can be
achieved using the ball valve as indicated on the pictures. Move the handle to the side
of the unit to select the front drum. Move the handle to the direction of the dashboard to
select the rear drum.
Do not forget the select the winch brake accordingly using the switch (item 07) on the
dashboard.

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WARNING!
Only perform winch selection with shut down power pack.

Note!
Ensure to open or close valves completely to prevent unwanted
valve throttling

Check!
Check that the proper outlet on the counter gear on the
measurehead is selected. If not move the counter cable the proper
outlet.

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Dashboard function explanation

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ITEM DESCRIPTION FUNCTION

NO

01 Main Pressure This gauge (0-400 bar) gives an indication of the hydraulic
Gauge pressure generated by the main hydraulic pump.

02 Control Pressure This gauge (0-40 bar) gives an indication of the control
Gauge pressure in the system. This pressure is required to control
all the functions within the hydraulic system.

03 Hydraulic Oil This gauge (0-120-C) gives an indication of the hydraulic oil
Temperature temperature. This valve is measured in the main hydraulic oil
Gauge reservoir.

04 Dual Control Use this dual control handle to control two functions:
Handle
Using the left handle the velocity and/or torque obtained from
the hydraulic motor can be changed.

Using the right handle the direction and the flow of the
hydraulic pump can be changed. Push the handle forward to
spool of wire, pull the handle towards to spool on wire. For
both functions, the outmost handle position will generate the
biggest flow.

05 Engine Stop trigger Pull on this trigger to stop the diesel engine. Pulling this
trigger will close down the diesel supply to the diesel engine
which will result in a engine shut down.

06 Engine Start Pull on this trigger to start the diesel engine. The trigger will
Trigger open a valve and activate the hydraulic starter.

Release the trigger as soon as the engine has started.

07 Brake select switch Use this switch to select the proper brake of the used drum.
front/rear drum

08 Brake on/off switch Use this switch to select the proper brake for the used drum.

09 Throttle Control Use the handle control to change the diesel engine rrpm.

Pull or push the throttle control for rigorous rpm change.

Turn the throttle control for fine adjustment.

10 Safety Valve Use this control to change the required maximum torque.

WARNING!
DO NOT use the safety valve as a speed
regulator when P.O.O.H.

11 Air Inlet Valve Use this handle to control the engine safety air inlet control
valve.

Push the handle up to bypass the diesel engine motor oil

pressure safety system to allow the engine to be started. Hold
the handle in the upper position until the motor oil pressure
has risen to approx. 2 bar.

Pull the handle down to emergency stop the diesel engine.

Pulling the handle down will close the diesel air inlet valve.

For restart wait for the engine derived vacuum to disappear.

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12 Horn Push Button Push this button to activate the air horn.

13 Engine RPM This gauge gives an indication of the engine RPM’s 14

counter

14 Engine This gauge (0-120-c) gives an indication of the engine

Temperature temperature. This valve is measured on the engine at the
Gauge radiator side.

15 Exhaust This gauge (0-250-C) gives an indication of the exhaust

Temperature temperature. This valve is measure head on the water cooled
Gauge exhaust manifold.

16 Engine Oil This gauge (0-10 bar) gives an indication of the motor oil
Pressure Gauge pressure. The engine safety device will shut down the diesel
engine when this valve drops below approx. 0.5 bar. During
normal working conditions the pressure will read approx. 2.3
bar, at maximum engine RPM the oil pressure will be approx.
4 bar.

17 Air pressure Gauge This gauge (0-10 bar) gives an indication of the air pressure
generated by the air compressor and present in the
pneumatic system.

18 Start Pressure This gauge (0-250 bar) gives an indication of the start
Gauge pressure. The start pressure is the pressure of the hydraulic
pressure stored in the hydraulic pressure at 170 bar the unit
can be started approximately 6 times.

19 BOP Pressure This gauge (0-250 bar) will indicate the pressure stored in the
Gauge BOP control accumulator, the maximum pressure will be
approx. 170 bar.

20 BOP Open/Close Use this valve to open or close the BOP.

Valve

21 Mast Supply This gauge (0-250 bar) gives an indication of the pressure
Pressure supplied for mast operations.

22 Pressure Dump Use this valve to dump the pressure available within the
Valve hydraulic bop system to the hydraulic oil reservoir. The
pressure needs to be dumped when the quick connector is to
be connected or disconnected. When operating the valve
ensure that the accumulator isolation valve is close and when
operating the valve ensure to open the valve slowly.

23 Mast Supply Valve This control valve is used to initiate mast operations. Move
the handle to the lower position to start with mast operations.
Move the handle back up with finished mast operations.

When operating the mast the winch system remains in full

working condition because of the use of the two hydraulic
pumps connected to the diesel engine.

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How to start the unit

➢ Ensure both filter valves on hydraulic tank (engine compartment) to be open. (On
the pictures both valves are in the “open” position.

Note!
Handle of valve in direction of flow = open.
Handle of valve perpendicular to flow = Closed.

Note!
Ensure to open or close valves completely to prevent unwanted
valve throttling.

➢ Ensure pressure dump valve to be completely closed (item 63). (With the valve
open pressure from the accumulator will be dumped)

➢ Ensure BOP control valve handle (item 22) to be in mid = neutral position.

•• Slowly open the hydraulic accumulator valve (lower engine compartment)

on the picture the valve is in the “closed”
position.

•• Ensure the diesel reservoir isolation valve is in

the “open” position.

•• Check accumulator starting pressure (operator

panel) to be minimum 130 bar.
If pressure is below 130 bar charge accumulator
using the charge procedure for air powered or
hand pump charging as described in the ‘How to
charge the hydraulic starter accumulator’
paragraph on page 28.

➢ Activate the diesel safety system by turning the red colored lever on the main
monitoring unit located in the lower engine compartment (top of diesel).
Turn lever in clockwise direction against spring force

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

Note!
Activation of the diesel safety system must be checked at
every start attempt. The lever will return to shutdown position
after engine lubricate oil level has reached normal operating
pressure.

➢ Ensure both hydraulic pump and motor control handles to be in mid position (item
04)

➢ Ensure reel brake control to be in "brake on" position (item 08)

➢ Open diesel air inlet valve (item 11)

➢ Pull out diesel rpm control to halfway up position (item 09)

➢ To start the diesel, pull start control (item 06).

➢ As soon as diesel has fired up, release/return start control immediately.

➢ Release air inlet valve control (return to mid position) as soon as engine oil
pressure is 2 bar minimum.

After-start check up

➢ Check the hydraulic control pressure to stabilize between 20-30 bar. (Item 02).

Note!
Control pressure will vary accordingly with engine revs.

Note!
If the control pressure is below 15 bar, switch off the diesel engine
using item 05 Figure 24, and check the following:

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➢ Hydraulic oil level is above minimum mark

➢ Check for leakage’s

Note!
IF the control pressure remains low when the diesel engine is
running with the above checked and rectified, consult ASEP.

➢ If the control pressure is above 30 bar consult ASEP.

Pre-operational checks

With the unit operating and before starting actual work site applications, inspect the
following :

➢ Smooth and proper operation of all unit functions

➢ Inspect control levers, hoses/fittings for proper installation and operation

➢ Ensure that operator site is free from oil, fuel, mud and other debris

Pressure test

Prior to starting wireline operations with the unit, the following checks should be
performed on the hydraulic drive system and brake system.

➢ Ensure that the brake on the drum is applied by moving the brake control switch
to full forward position. (Item 08)
➢ Ensure line pull safety valve is screwed all the way out / open. Item 10.
➢ Move the hydraulic control handle for pump (= reel) directional control and lock in
half-way backward position. Item 04.
➢ Use the line pull / safety (= hydraulic system pressure) adjust knob to slowly
increase the main hydraulic system pressure. Item 10 . (Turn in)
➢ Check the main system pressure gauge indication. Item 01.
➢ The pressure should increase up to maximum value 200 bar approx.
➢ Hold this pressure for approx. 30 seconds.

Note!
When reeling in hole the position of the safety valve is of no
Influence on system performance.

➢ Return all control handles and knobs to initial position and repeat the above
procedure, this time move the hydraulic control handle for pump directional
control toward the full forward position until the 200 bar pressure is reached.
➢ When during the above testing, the main system pressure does not reach 200
bar, increase the position of the hydraulic control handle to full position and
repeat procedure.
➢ If the control pressure falls below 15 bar during testing, then consult ASEP.
➢ After testing, check the hydraulic system hoses and couplings for leakage.

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Running test

➢ Prior to starting wireline operations, the following checks should be performed on

the hydraulic and mechanical drive system.
➢ Ensure that the brake on the drum is released, by moving the brake control
switch to full forward position. Item 08 Figure 24.
➢ Put engine revs at medium range.
➢ Ensure that the line pull safety valve is screwed all the way in. Item 08 Figure 24.
➢ Move the hydraulic control handle for pump (= reel) directional control and lock in
half-way backward position. Item 04 Figure 24.
➢ Slowly move the hydraulic control handle for motor (= speed) control either
forward or backward to obtain higher drum speed.
➢ Slowly return motor control handle to neutral mid position.
➢ Return all control handles and knobs to initial position and repeat the above
procedure, this time with hydraulic control handle for pump directional control
locked in full forward position.
➢ If during testing, the control pressure falls below 15 bar, then consult ASEP.
➢ After testing, check the hydraulic system hoses and couplings for leakage.
➢ Check mechanical winch components for loose bolts/nuts.

How to stop the unit

Normal stop procedure

➢ Check hydraulic starter accumulator pressure to be minimum 170 bar. Item 18.
➢ Recharge as necessary, refer to charge procedure on page 28.
➢ Ensure both hydraulic pump and motor control handles to be in mid position.
➢ Ensure reel brake control to be in "brake on" position. Item 08.
➢ Turn-in diesel rpm control to full down (idling) position. Item 09.
➢ Pull-out diesel stop control and maintain until diesel has fully stopped. Item 05.
➢ Release (push back in) stop control.
➢ Close the hydraulic accumulator valve (if also BOP operations are no longer
required).

Emergency stop procedure

Pull down air inlet valve control handle to choke the diesel air inlet. Item 11.
Note!
After the diesel engine has come to full stop, the air inlet valve
can not be opened immediately due to the engine created
vacuum. Allow approx 2 minutes for vacuum to disappear, then
open the air-inlet valve for renewed start.

Automatic emergency stop procedure

➢ Upon a diesel system alarm, the diesel will shutdown automatically. This
shutdown system can be triggered by a high exhaust gas temperature (>200 o
C), a high coolant temperature (>90 o C) or a low lube oil pressure (< 0.5 bar).
➢ To reset the alarm shutdown system, turn lever on sentinel master control unit
against spring pressure (lower engine compartment, top of diesel engine). Refer
to Figure 30.

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Note!
Before restart ensure that the initial cause of the emergency shut
down has been identified and solved. (Refer general safety
procedures)

How to operate the reel

At normal reel rotation speeds

➢ Ensure that diesel engine is running

➢ Release the reel brake
➢ Make sure the safety valve is completely turned in, right hand side control panel
item 10.
➢ Ensure that wire can not snag in or behind level wind when reel rotates
➢ To spool-off wire, move (left side control panel located) pump control lever
forward. Reel speed will increase with gradually pushed forward control lever.
➢ To spool-on wire, move the pump control lever backward. Reel speed will
gradually increase with bringing handle more backward

Note!
If during operations the diesel engine revs go down, increase the
engine rpm’s to increase the power output from the diesel engine.
At high reel rotation speeds

At high reel rotation speeds

➢ With the pump control lever in any position:

➢ Move (left side panel located) motor control lever back/forward for high speeds.
Reel speed will gradually increase with bringing handle more back/forward.

Note!
High speeds will be obtained at proportionally reduced line pull.
High speed = low torque, Slow speed = high torque.
Under varying line pull

Under varying line pull

Under normal operation the safety valve must be screwed completely in.
The safety valve can be adjusted for short periods of time to limit the line pull, i.e.
where pulling through sub-assemblies / SSSV etc. After this the valve must be returned
to the screwed in position.

How to operate the reel brake

➢ The reel brake is operated by the spring, incorporated in the brake cylinder. The
spring force tightens the brake band around the reel (brake band area).
➢ Each reel has its own brake system and operation is selected by the setting of
the control panel left hand side toggle switch (forward is front reel).
➢ To release the brake completely, move the brake control toggle forward. For full
braking action, set the brake control toggle in rearward position.

How to charge the hydraulic starter accumulator

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The hydraulic accumulator operates the hydraulic engine starter and the accumulator
can be charged by using 2 methods:

1 Using the main hydraulic system

2 Using a hand pump assembly

Note!
Maximum charging pressure is factory preset at 170 bar.

➢ Open the accumulator valve (engine compartment).

➢ Check accumulator system pressure on front control panel. Item J Figure 24.
With pressure below 130 bar, charge up accumulator system using one of the
following methods:

Note!
The accumulator charging via the engine (hydraulic system)
charging method is the preferred option, prior to unit shut down
after running always ensure that the accumulator is charged for
future starts, and close the shut off valve to store the charge.

Hydraulic system charging

➢ The accumulators are normally charged from main hydraulic system.

➢ Ensure that diesel engine is running.
➢ Apply the winch brake.
➢ Fully turn in the left hand side safety valve.
➢ Slowly move the pump control lever (right hand lever) to the front position.
➢ Observe raising of accumulator system pressure until maximum pressure is
reached.

WARNING!
While moving the pump control handle to the front the main
pressure in the system will increase. This pressure may never
exceed 400 BAR for long periods, peak pressure may get unto
450 BAR max. (Check on the main pressure gauge, full scale
deflection.) When you move the pump control handle too far to
the front system pressure will exceed these limits and might
cause damage to the hydraulic oil and the hydraulic
components.

Note!
If during accumulator charge the drum start to break free from
the brake. Move the motor control handle (Left hand over)
forward and lock in position.

Note!
Where the accumulator is not left with enough pressure to start
the unit the following method can be used to increase the
pressure.

Hand pump charging

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➢ Locate hand pump handle situated on the radiator side (engine compartment).
Locate the hand pump (lower engine compartment)

➢ Insert pump handle in pump

➢ Commence pumping and continue to pump until minimum pressure is reached.

(Charge accumulator to approx. 130 Bar for 1-2 start attempts)

How to operate the wire spraying system

The wire oiling system uses gravity to drip lubricating oil, stored in the reservoir, onto
the wire on the reel. Take off tanktop (threaded cap), refill if necessary.

➢ Ensure that wire lube oil tank is full and filled with light viscous oil.
➢ Open oil supply line valve.

Closed loop hydraulic system

The ASEP closed loop hydraulic system provides infinite control over the winch
performance through the use of a superior hydraulic circuit. This system does not
require any clutches or gear boxes and offers a constant speed to torque relationship
via a constantly variable hydraulic pump and constantly variable displacement motor.

The system offers continuous line pull and speed at the touch of the levers without the
requirement to reselect gears. Typical open loop hydraulic systems incorporate a 3 or 4
speed manual gearbox transmission requiring that the winch drum stops rotating before
changing from gear to gear. The hydraulic system is simple, safe and responds
immediately on demand in both forward and reverse directions.

The ASEP© system is ideal for all slickline operations yet can provide, slow constant
speeds for slickline logging and caliper runs and can be made suitable for using with
conducting slickline.

The system is already capable of high line pulls for the modern .125" slicklines that
may be required in the future. The system has incorporated into the winch control a
brake action which is a one-handed intuititive operation. The mechanical or air brake
system provided on the K-Winch© is required only as a parking brake or to supplement
jarring performance.

The reduction in the number of leak paths and the efficiency of the closed loop system
allows the power to be delivered to the winch drum with the minimum of fluid power
loss through the hydraulic circuit. Typically, an open loop hydraulic system is only 45%
efficient. The ASEP© ClosedLoop© hydraulic system is 75% efficient so enabling an
engine with smaller power output to be utilised.

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The ClosedLoop© system is built for longevity and is supplied with long life hydraulic
components, life time hydraulic oil and is designed for minimum maintenance.

Hydraulic system fluid level check

WARNING!
ENSURE THE HYDRAULIC OIL TANK IS FITTED WITH THE
FACTORY SUPPLIED VENTING FILLER CAP

➢ Ensure that the diesel engine is shut down.

➢ Unscrew tank top. Hydraulic oil level should be at maximum level i.e. 15 mm
below tank top (if accumulators are present in hydraulic system; with pressure
released accumulators).

Note!
Always take in account temperature based fluid edxpansion
when filling up the hydraulic system. (On 1000 litres hydraulic
oil the volume will expand with 1 litre on every degree Celsius)

➢ Fill up or replace and fill up as necessary using a mineral oil with a “46" or “68"
viscosity grade.
The viscosity grade used depends on the average ambient operating
temperature. In areas with average temperature above 30 degrees Celsius we
advise use of a “68"-grade oil, with average temperatures below 30 degrees
Celsius we advise a “46"-grade oil. (It is allowed to mix two different viscosity
grade oils, this will result in an average viscosity between these two values) The
minimal permissible viscosity grade of the hydraulic oil in an ASEP unit is “32".
Since the viscosity of the hydraulic oil decreases with a higher oil temperature
each grade hydraulic oil has a maximum permissible oil temperature. For “46"-
grade hydraulic the maximum hydraulic oil temperature is approximately 65
degrees Celsius (149 degrees Fahrenheit) and for the “68"-grade hydraulic oil the
maximum oil temperature is approximately 80 degrees Celsius (176 degrees
Fahrenheit). With an unit in a environment subjected to high temperature
variation between summer and winter it is recommended to adapt the viscosity of
the hydraulic oil to this temperature variation. Eg use a thin viscosity oil, grade
“46" in winter and a thick viscosity oil, grade “68" in summer. (Eg if the unit is
equipped with a hydraulic starter system, this starter system might not function
properly when using a high grade hydraulic oil, “68", in cold ambient
temperatures.)

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Region In general, used viscosity grade in

ASEP units
North Sea 46
Former Soviet Union 46
North America 46
Africa 68
Middle East 68
South America 68
Far East 68
South East Asia 68

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Hydraulic oil suppliers

Supplier Brand name Viscosity

AGIP OSO 46 or 68
API API CIS 46 or 68
ARAL ARAL VITAM 46 or 68
ARCO DURO OIL 46 or 68
BARELI TIA/RO 46 or 68
BELLINI SPRINTER ADPV 46 or 68
BERGOLINE PARATER 46 or 68
BP ENERGOL 46 or 68
BRYTOL AROS 46 or 68
CASTROL HYSPIN AWS 46 or 68
COMLUBE OLEOL HM 46 or 68
ELF ELFOLNA 46 or 68
ESSO NUTO 46 or 68
EURAL HYDER 46 or 68
FINA HYDRAN 46 or 68
FUCHS RENOLIN 46 or 68
IGLEA FILETE V 46 or 68
IP IP HYDRUS OIL 46 or 68
ISAOIL EP HYDRAULIC OIL 46 or 68
KLUBER LAMORA 46 or 68
LUBRA OLEODIN 46 or 68
MILLOIL TELEDINAX 46 or 68
MOBIL MOBIL DTE 46 or 68
OLEOBLITZ OLIO EHT 46 or 68
OLIO FIAT HTF 46 or 68
PERSIAN OIL HTF 46 or 68
Q8 HAYON 46 or 68
ROL LI 46 or 68

Hydraulic Oil Replacement

Note!
Please dispose of used and excess fluids and used filters in a
respomsible manner!

➢ Remove hose from first filter unit and attach a seperate, open ended hose.
➢ Place a receiving tank underneath, open filter valve and drain the tank.
➢ If applicable, clean inside hydraulic oil tank.
➢ Fill tank with appropriate type hydraulic oil.

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Replacement interval

Subject Every 2 years of operation

Hydraulic oil x

Hydraulic Hoses and Couplings

➢ Start up the diesel engine or electric motor and with all controls in neutral, check
all connections and hoses for visible leakage.

➢ With diesel engine or electric motor running , operate each system to (possible)
maximum operating pressure level and recheck for oil leaks. Particular attention
should be paid to all hose/coupling sleeves for signs of visible hose "sweating" or
"swelling".

WARNING!
ON NO ACCOUNT SHOULD SUSPECTED OR CONFIRMED
LEAKAGES BE REPAIRED WHILE THE DIESEL ENGINE OR THE
ELECTRIC MOTOR IS IN OPERATION. DO NOT ATTEMPT TO
TIGHTEN ANY LOOSE COUPLING WHICH FORMS PART OF A
CIRCUIT, WHICH COULD BE UNDER PRESSURE.

BEFORE ATTEMPTING A LEAKAGE REPAIR, SHUTDOWN THE

DIESEL ENGINE OR ELECTRIC MOTOR AND CYCLE ALL
CONTROL HANDLES SO THAT SYSTEMS ARE PRESSURE
ZEROED. CONFIRM ZERO SYSTEM PRESSURE ON GAUGE(S).

How to drain condensation water

Water can accumulate in the hydraulic oil tank.

To remove accumulated water from oil tank;

➢ Remove hex-bolt from bleed-off valve point at bottom of tank.

➢ Place a receiving tank underneath and open valve to drain tank.
(Hydraulic oil is a lighter substance than water and thus “floats” on top of the
accumulated water.)
➢ Drain until hydraulic oil escapes.
➢ Close tap.

Troubleshooting

General

This chapter contains troubleshooting information to be used for locating and

correcting most of the operating problems, which may develop with the
equipment.
If a problem should develop which is not presented in this section or which is
not corrected by listed corrective actions, technically qualified guidance should
be obtained before proceeding with any maintenance.

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Troubleshooting Information

➢ Each malfunction or trouble within an individual group or system is followed by a

listing of probable causes which will enable determination of the applicable
remedial action. The probable causes and the remedial actions should, where
possible, be checked in the order listed in the tables.

➢ It should be noted that there is no substitute for a thorough knowledge of the

equipment and related system. Reference should be made to the applicable
maintenance portion of the manual for troubleshooting tables.

➢ It should be recognized that the majority of the problems arising in the equipment
will be centered in the hydraulic and electrical systems. For this reason, every
effort has been made to ensure that all likely malfunctions in these areas are
given the fullest possible treatment. In the remaining groups, only those
malfunctions which are symptomatic of greater problems or which have more
than one probable cause and remedy are included. This means that problems for
which the probable cause and remedy may be immediately obvious are not listed
in this chapter

Pressure control equipment

To get the wireline and the tool string into the well in a safe and practical manner it is
required to use pressure control equipment. This pressure control equipment consists
normally of a gate / cutting valve, a wireline valve, a lubricator and a stuffing box. To
control this equipment ASEP units can be equipped with a set of control instruments. In
this manual a description is given how to use the ASEP equipment in cooperation with
the well equipment.

Note!
Each set of equipment in the unit depends on the unit
configuration and is application if present.

BOP (hydraulic wireline valve) system

System explanation

The BOP is a device which offers protection against undesired well fluids escaping
from the well during wireline work. If i.e. jar action is lost and a decision to drop a wire
cutter is taken, the wireline valve will offer a mean to achieve this sealing off and still
maintain the line in one piece.

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Two hydraulic cylinders actuate Ram Assemblies that close around the wireline without
damaging this. The ASEP unit is connected to the cylinders via hydraulic hoses. The
hydraulic pressure pushes the integral piston which in turn closes the rams together
and forms a seal around the wireline.

The hydraulic bop control system inside an ASEP unit is completely separate from the
main hydraulic system to protect the main hydraulic system from contamination.

The hydraulic pressure for controlling the BOP is generated using the main hydraulic
system. To charge the accumulator use the “Accumulator Charge procedure” as
described in the general Flyline operations manual. The pressure generated with the
hydraulic pump is stored in a hydraulic accumulator (10 litres). This accumulator can be
isolated from the system using a high pressure ball valve.

The hydraulic oil for the BOP system is taken from the hydraulic oil reservoir. This
reservoir is filled with hydraulic oil using a minimum viscosity grade 46. The size of the
hydraulic oil reservoir depends on the unit configuration and the BOP applicable.

On the suction side of the oil reservoir a main

isolation valve is fitted. Ensure the oil reservoir
main isolation valve is open operating the BOP
functions.

Note!
Ensure the accumulator main isolation valve is open when
operating the BOP functions.

The hydraulic oil inside the accumulator is the

actual amount of oil used to operate the BOP.
During the normal working situations the BOP
is not operated with a direct oil flow from the
pump. The pressure inside the accumulator is
visualised on the gauge in the main
dashboard (item 19).

To control the BOP open or close the valve in

the main dashboard (item 22). When moving
the handle to the close position a pressurized
hydraulic oil flow will actuate the hydraulic
cylinder inside the BOP closing the BOP.
When moving the handle to the open position
a pressurized hydraulic oil flow will actuate
the hydraulic cylinder inside the BOP opening
the BOP.

The BOP control hoses are connected to the BOP quick connectors. In general these
connectors can be found at the front of the unit, lower left corner of the winch
compartment. A decal explains the connection function for each quick connector.

Between the hydraulic open and the hydraulic close port a gauge is fitted. This gauge
gives and indication of the A/B port pressure (item 20 main dashboard).

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How to operate the BOP control system

To operate the BOP system:

➢ Check components for proper installation and for leakages.

➢ Ensure BOP control valve is in the neutral (=mid ) position, item 22 main
dashboard.
➢ Ensure accumulator isolation valve to be closed.
➢ Ensure pressure dump valve to be closed.
➢ Connect BOP control hoses to the unit.
➢ Ensure BOP hydraulic oil reservoir isolation valve to be open.
➢ Check the BOP pressure gauge for hydraulic oil pressure inside accumulator,
item 19 main dashboard.
➢ Open the BOP accumulator main isolation valve. (Valve lever in direction of flow)
➢ Start the unit using the start procedure.
➢ Perform the charge procedure if required, check for a raise in hydraulic oil
pressure.
➢ Move the BOP open / close handle and verify proper system functioning;
* movement on the BOP hydraulic cylinder accordingly.
* change in pressure indication on the A/P port pressure gauge (item 20 main
dashboard)
➢ After testing recharge the accumulator, unit is operation ready.

Drum system

Inside the wireline unit the wireline is spooled on a

drum. This drum can be either driven directly using a
hydraulic motor (and reduction gear) or using a drive
chain between drum and hydraulic motor (and
reduction gear). The unit can be equipped with one
hydraulic motor or with two hydraulic motors. If the
unit is equipped with one hydraulic motor drum
selection change is possible by changing the drive
chain to the required drum. With two hydraulic motors
the drum selection change can be performed using a
hydraulic ball valve.

Note!
DRUM SELECTION CHANGE MAY ONLY PERFORMED WITH
SHUTDOWN POWER PACK.

The size of the drum depends on the wireline used. The minimum bending radius of the
wire requires a certain minimum core diameter of the drum. The outer dimensions of
the drum are restricted to the unit used and the length of wireline required. To make the
K-winch wireline units as versatile as possible the drums can be easily exchanged.

The reduction gear between the hydraulic motor and the drum reduces the hydraulic
motors revolutions to the necessary revolutions with the required torque. Depending on
the design specifications of the unit the reduction ratio can vary.

The hydraulic motor is driven using the hydraulic flow from the main hydraulic pump.
This pump can be driven using a diesel engine or electric motor. The hydraulic power
delivered to the hydraulic motor is controlled using the right handle of the dual control
valve (located on the left hand side dashboard). This lever controls both direction and
the amount of power available to the motor by controlling the angle of the swash plate
in the pump. To vary the speed of the motor the left hand lever of the dual control valve

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can be used, allowing the pressure to move the swash plate in the motor, increasing
the torque/ speed to the drum.

To hold the drum in a required position the unit is equipped with a drum brake system.
This brake can be either applied by manual force or using a pneumatic released brake
cylinder. This cylinder is based on a spring incorporated inside this cylinder. With
pneumatic power loss the brake will automatically be applied holding the drum in
position.

WARNING!
A brake cylinder must not be dismantle by unqualified personnel
as it is spring loaded and it could be extremely dangerous where
disassembly is attempted.

The brake band holding the drum in position applies directly on the wireline drum.
Using an angular setup the brake band will automatically increase its breaking force
when applied (with force on drum down hole). To ensure proper functioning of the
brake it is required that the brake band is properly positioned and adjusted.

Drum Selection Change

Hydraulic selection (units with two hydraulic motors)

ASEP units can also be equipped with two hydraulic motors, each hydraulic motor
drives its own drum. With this setup drum selection change does not require a chain
exchange, required is only a change of setting on the hydraulic ball valve located in the
winch compartment.

The valve setting required for front eg rear drum is shown on the decal near the
ball valve.

Note!
To select brake operation move (control panel right hand side)
toggle switch to the appropriate position (forward = front drum /
backward = rear drum), item 07 main dashboard. (Only on units
with air brakes)

Note!
Ensure to select the appropriate line pull indicator and dept
counter splitter box outlet for correct line measuring.

Note!
Use grease gun with high quality multipurpose grease to lubricate
the drum bearings after drum selection.

WARNING!
Drum selection change with the hydraulic ball valve may only be
performed with shut down power pack.

Note!
When moving the ball valve ensure the valve is set in its outmost
position. This prevent unwanted valve throttling causing power
loss.

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Pre-operations check

To ensure that the drum will remain in position even with the highest forces generated,
eg during jarring, the following check needs to be performed on the drum:

➢ Check the drum alignment bolts (4 for each drum) to be screwed out against the
bearing housing.
➢ Perform pre-start check up and start unit as described in the operations manual.
➢ With wire on the drum (not through measurehead) simulate a jarring action.
➢ After jarring action shut down the power pack and check the drum bearing bolt
tension. Tighten as secure as possible.
➢ Repeat this action twice to ensure that the drum will remain in position even with
the highest forces generated.

Check!
Recheck for proper installation, and secured bolts.

WARNING!
Unsecured pillow block and hydraulic motor support flange bolts or
incorrect alignment or the drum and drive sprockets may lead to
serious damage and/or injury!

Note!
To select brake operation move (control panel right hand side)
toggle switch to the appropriate position (forward=front drum /
backward=rear drum), item 07 main dashboard. (Only) on units with
air brakes)

Note!
Ensure to select the appropriate line pull indicator and dept counter
splitter box outlet for correct line measuring.

Note!
Use grease gun with high quality multipurpose grease to lubricate
the drum bearings after drum selection.

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Brake band maintenance

The brake band should be checked on a regular basis for wear. The brake band should
be replaced just before the rivets come into contact with the drum.

Periodic Inspection

WARNING!
This equipment requires periodic safety and maintenance
inspections.

The equipment must be thoroughly inspected periodically so as to detect in a timely

manner the possibility of defective, damaged or improperly installed parts. Frequency
of inspection will to a large extent depend upon unit activity and severity of service but
under no circumstances should the interval for the below listed inspections exceed one
month where the unit is regularly used. These inspections should also include those
listed in the daily checklist and lubrication schedule.

What to check/inspect;

General

➢ Inspect unit frame for any signs of deformation, damage and leakage
Inspect attaching hardware for security and/or missing items.
Particular attention should be paid to areas of potentially high material stress
such as bearings, drum drive shaft flange and bolts etc.

Drum / drive chain

➢ Check proper tightness on drum connection bolts. (each bearing 2 bolts)

➢ Check lubrication on drum gears. If required use grease gun with high quality
multi purpose grease.
➢ Check chain tension. If required increase tension using chain tension adjust
procedure.
➢ Check chain lubrication.
➢ Check chain guard to be properly positioned.

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Reduction gear / hydraulic motor

➢ Check reduction gear oil level.

➢ Check reduction gear mounting bolts to be properly tightened.
➢ Check hydraulic motor mounting bolts to be properly tightened.
➢ Check reduction gear for lubrication oil leakage.

Hydraulic pump

➢ Check hydraulic pump connection bolts to be properly tightened.

➢ Check flywheel housing bolts to be properly tightened.

Electrical system

The electrical system comprises a

•• alternator
•• main connection box
•• fuse box
•• batteries
•• main switch box
•• Power output sockets

Note!
All electrical components are certified explosion proof with class
Eexd IIA/B T3/5.

The required power supply for the components in the unit is taken from the explosion
proof generator powered by the diesel (24 VDC). This 24 (VDC) is used for a lighting
system which can be connected to the power output sockets.

The power is not taken directly from the generator, as a buffer supply, the power for the
components is taken from the battery unit inside the power pack compartment. The
batteries are in turn charged from the generator.

Power out put

With 24 VDC power required a connector can be connected to the connector on the
power pack. Refer to the figure.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

Ground connection

To ensure proper and safe unit functioning it is required that the unit is connected to a
ground point at the point indicated.

Generator / battery box

The batteries are charged with the diesel engine running from the EX generator. Each
battery connection is sealed ensuring that the battery is according Cenelec regulations.
On a regular basis the batteries should be checked for proper water level. The electric
connection to each battery is sealed. This seal may not be removed to ensure EX
safety.

Open the hatch in the operator cabin (as indicated) Open caps of batteries and check
water level, if required fill up to mark with distilled water.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

Main connection box

Inside this connection box the electric input signals from the generator are redirected to
the batteries, the switch and the sockets. When performing maintenance on the battery
boxes or on the unit itself the batteries needs to be disconnected inside this box.

To access the box remove the cover from the power pack on the other side than the
radiator.

Primary switch box

This switch box holds the following functions:

Main power selection and ”OFF” SWITCH

Generator fault indicator.

To activate the power to the sockets turn the switch to the “ON” position.
With finished operations ensure to turn the switch to the “OFF” position.

If the electrical system is activated with no

running engine the generator fault indicator will
light up. With proper generator functioning the
light will NOT be illuminated.

Note!
If generator is damaged and
does not supply any power with
running engine this light will be
illuminated.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

WARNING!
Ensure that main power supply to the switch box is
disconnected before attempting to perform maintenance or
repair work on the electrical system components.

WARNING!
NEVER OPEN AN EX-COMPONENT IN A ZONE ENVIRONMENT.
ALWAYS PERFORM MAINTENANCE IN A SAFE AREA.

Note: The systems contain two batteries, which supply a total of 90 aH at 24 volts when
they are fully charges. With an energy drainage of 200 watt the batteries will last
(90/(200/24)) approximately 10.5hours without recharge.

Fuse box

This box holds the following functions:

➢ Fuses for each electric group (2 X 20 & 1 X 3 Ampere)

With a certain electrical component not working and with the component not damaged
check the appropriate fuse. Have the fuse replaced in whole if tripped.

WARNING!
Before resetting a fuse determine the cause of fuse trip and take
appropriate action to prevent future system failure.

WARNING!
Ensure that main power supply to the switch box is disconnected
before attempting to perform maintenance or repair work on the
electrical system components.

WARNING!
NEVER OPEN AN EX-COMPONENT IN A ZONE ENVIRONMENT.
ALWAYS PERFORM MAINTENANCE IN A SAFE AREA.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

Electrical system maintenance

Maintenance

Note!
This equipment requires periodic safety and maintenance
inspections.

•• The equipment must be thoroughly inspected periodically so as to detect in a

timely manner the possibility of defective, damaged or improperly installed parts.
Frequency of inspection will to a large extent depend upon unit activity and
severity of service but under no circumstances should the interval for the below
listed inspections exceed one month. These inspections should also include
those listed in the daily checklist.
•• Items modified or removed and reinstalled by or so recommended by ASEP
during installation of the unit (where applicable) is covered in the following
inspection procedures.
•• Inspect unit frame for any signs of deformation, damage and leakage Inspect
attaching hardware for security and/or missing items. Particular attention should
be paid to areas of potentially high material stress.
•• Inspect electric components (cables, glands) for security, wear and tightness.
•• Check that no unauthorized modifications have been made to the unit.

Use the maintenance schedule to determine action points.

Maintenance schedule
CODES USED:

1. Check for proper and secure installation

2. Check for visible damage and legibility
3. Check for proper fluid level
4. Check for any structural damage; cracked or broken welds; bent or warped
surfaces; condition of corrosion protection
5. Check for leakage
6. Check for excessive dirt or foreign material
7. Check for proper operation and freedom of movement
8. Check for excessive wear or damage
9. Check for proper tightness and adjustment
10. Drain, clean and refill
11. Check for proper operation while engine is running
12. Check for proper lubrication
13. Check for evidence of scratches, nicks or rust and straightness of rod
14. Check condition of item, replace as necessary
15. Clean or replace
16. Replace
17. Drain or Clean
18. Check continuity / insulation resistance
19. Pressure test
20. Check for proper and secure installation of sub-components
21. Re-certification units electrical system with third party witnessing (hard stamping
on name plate)

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

ITEM DAILY MONTHLY 3 MONTHLY 6 MONTHLY YEARLY

10 H 300 H 600 H 1200 H

1 Electrical 1 4 18
cables/earthing/glands/mct

2 Electrical junction boxes 4 20

3 Tags/decalls/placards 1&2

4 Electrical armatures controls 1

5 Complete electrical system 21

Trouble shooting

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

WS-302-B ASEP K – WINCH FLYLINE MODEL MEASUREHEAD SYSTEM

Safety signs

For reasons of safety the ASEP equipment is marked (if applicable) with safety signs.
Each sign indicates a possible danger zone. Keep the meaning of these safety signs in
mind while working with ASEP equipment. This will prevent dangerous situations and
personal injuries.

This sign warns for a general danger.

This sign warns for automatically starting and stopping

machinery.

This sign warns for moving machinery.

Make sure that no body parts and/or clothing can got caught in
the machinery.

This sign warns for hot surfaces.

Do not touch the indicated parts with bare hands while the unit is
running or has run for a time.

This sign warns for high voltage electrical parts.

Do not touch electrical components while energized.

Also all safety instructions in this manual have been earmarked with caution signs.
Please observe! An explanation of the used earmarks is:

Used to earmark a piece of text which may be vital to ensure safe

unit operation, ignoring a WARNING! May result in unsafe and
potentially dangerous situations.

Used to earmark a piece of text which gives additional, important

information.

Used to earmark a piece of text which gives a summary of things

to check.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

Measure head

This K-REC measure head is suitable for the depth and tension measurement of most
wirelines.

The ASEP K-REC measure head can:

➢ be fitted to most existing wireline units levelwind devices

➢ includes measurement of both depth and tension
➢ accept different wire sizes without modification
➢ be fitted with electronic depth and tension measurement sensors
➢ increase wire longevity and decrease operating costs

Independent testing has demonstrated that the 3-wheel wrap around measure head
reduces bending induced line fatigue. Use of the measure head eliminates the need for
a separate hay pulley line tension measurement and connector hose. Optional fitting
equipment will allow the measure head to be fitted most existing units. The unit utilizes
flat measure wheel surfaces, and as such is not recommended for co-axial cables.
The measure head may be equipped with a digital depth encoder and a line tension
sensor. These devices are suitable inputs for the ExPC computerized display unit.

Technical specifications - MP16 Measure head –

Frame;
➢ corrosion resistant aluminium
➢ dimensions (LxWxH) : 530 x 265 x 1040 mm (1.7 x 0.9 x 3.4 ft)
➢ weight : 65 kg (143 lbs)
➢ mono arm type
➢ three wheel wrap around type; 2 top wheels, 1 bottom wheel

Wheels
➢ high accuracy stainless steel
➢ Measure wheel diameter 411.84 mm (16.214 Inch)
➢ flat surface wheel

Suitable For
➢ slickline : 0.072", 0.082", 0.092", 0.105", 0.108", 0.125"
➢ braided line : 3/16", 7/32", 1/4"

Depth Output
➢ Bowden type cable connector
➢ angle drive ratio depending upon wire size

Pull Output
➢ sensitive hydraulic membrane
➢ suitable for pressure rating A, B and C

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

How to operate the measure head

When operating the measure head it is important to understand its primary operating
principals. The measure head is suitable for measuring two things:

1 1 The length of wireline spooled through the measure head

2 The tension on the wire

Explanation:

1 The length of wireline passing through the measure head is measured using a
measure wheel. This measure wheel is connected to a counter. With each
rotation of the wheel the counter will add or subtract a digit from the displayed
value, this depending on spooling in or out the hole. To have the measure wheel
rotating while wire spooling it is important that;
➢ the wheel can rotate freely
➢ the wireline is properly seated in the wheel ‘groove’ and led around the
measure head wheels

To have the wheel rotating freely it is important that no structural damage of the
measure head prevents rotation, the bearings are not damaged and are properly
lubricated, measure wheel outlet counter cable or splitter gear functions properly.
This can easily be tested by rotating the measure wheel by hand before wire
installation. The measure wheel is the right wheel indicated (looking from the
front of the unit).

Proper installation of the wire through the measure head is achieved during unit rig up.
Use the following procedure:

➢ To load wireline through the measure head, thread the wireline using the
following sequence:

1) from the top of the required drum, between drum side guide rollers,
2) over top measuring wheel no. 1 / behind upper front guide,
3) behind lower front guide / underneath bottom wheel,
4) lower rear guide / behind upper rear guide,
5) over top wheel no. 2 / between well side guide rollers, out to well site.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

2 The tension on the wire is measured using the loop created when installing the
wire onto the measure head. When a pull is generated on the wire the loop wants
to close itself but is contained by the measure head, and thus a pressure is
generated on the measure head construction.

The top half and the bottom half of the measure head are two separate
constructions. On the rear of both halves the halves are connected using a hinge.
On the other side a hydraulic bellow is mounted. With the generated pressure on
the measure head the bellow is pushed in creating a hydraulic pressure. The
higher the force on the measure head, the higher the hydraulic pressure will be.
When attaching a hydraulic gauge to the bellow a read out can be obtained of the
line tension.

To ensure proper read out it is important that the bellow and measure system is
sufficiently filled with hydraulic oil and that no air exists in the system. It is also
important that the piston of the bellow sticks out from the main body.
If this is not the case the measure head bottom half will not apply pressure on the
bellow but on the bellow body. This will result in no change on the gauge read out
with increasing line tension. (Refer to paragraph “Measure head –hydraulic
bellows” for detailed information.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

How to make the MP16 measure head operation ready

With fixed position glide shaft

On certain ASEP units the measurehead glide shaft is in a fixed position. If this
configuration is applicable a minimal rig-up action is required. The only requirement is
to unlock the measurehead from its storage point using the measurehead lock.
During rig down ensure to lock the measurehead to prevent equipment damage.

With non-fixed position glide shaft

On most ASEP units the measurehead glide shaft is suspended between two
moveable support arms. This is required to enable storage of the measurehead within
the frame during transport. If the measurehead shaft is not in a fixed position perform
the following procedure:

WARNING!
Use two persons to install the measure head assembly. One to
manually lower the levelwind assembly and one to guide the
measure head assembly into position.

In stowed position the MP 16 measure head is suspended from the levelwind guide
shaft on the left hand top side of the double drum frame.

➢ Put the levelwind guide into position and lock in position. (Stored in bottom half of
front door)
➢ Loosen the assembly lock (refer picture on next page).
➢ Loosen the measure head lock (refer picture on next page)

WARNING!
Take in mind never to open the left hand side winch bay door
(front view) with the measurehead in stored position. The
measurehead is suspended on a bracket attached to this door.
With door opening the measurehead will not longer be hold in
position and might drop down with a damaged gas strut.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

Measure head - hydraulic bellows

Check!
CHECK THE GAP BETWEEN THE HYDRAULIC PISTON AND THE
MEASURING HEAD FRAME PRIOR TO OPERATION’S.

Check!
BEFORE OPERATIONS ENSURE THAT THE SYSTEM IS
CORRECTLY BLED BY PERFORMING THE WT SYSTEM BLEED
PROCEDURE AS FOUND IN THE PARAGRAPH “HOW TO BLEED
THE WT SYSTEM” ON PAGE 37

To measure the tension on the wire a hydraulic bellow is incorporated in the system.
This hydraulic bellow has two connection points; one for the hydraulic pressure signal
to the CombiGauge and one for connection of a hand pump for system fill up / system
air bleed. The hydraulic bellow itself is connected to a stainless steel plate which in turn
is connected to the measure head top half.
(Use allen key metric size 5 to remove complete assembly)

When a pressure is applied on the piston this pressure will be transferred to a gauge.
The piston is mounted in a housing using a flexible membrane.
To transfer the hydraulic pressure to the CombiGauge a standard hydraulic hose is
used. At the highest point in the hose system a bleed valve is incorporated. Air inside
the measure system will generally accumulate here and can be bled from this point.

WARNING!
Use only high grade ATF-F type oil to fill up the hand pump.

At the connection point for the hand pump the factory supplied hand pump can be
connected. This hand pump is used for filling the measure system with hydraulic oil.
When filling and bleeding the system a pressure is generated inside the measure
system. This pressure ensures that the piston will stick out and can generate pressure
within the system.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

Note!
Before connecting the quick connector ensure both make and
female part are scrupulously cleaned to prevent system
contamination.

For the system to operate correctly, it is very important that hydraulic piston does not
come in to contact with the lower part of the measure head frame with no load applied.
(Where this occurs ambient temperature changes could expand the system fluid and
create internal pressure giving false readings.)

To check this gap make sure that;

➢ No load is applied on the measurehead i.e. no cable is tightly wrapped around

measurehead.
➢ Ensure bolt on bottom half retainer is properly tightened.

➢ The measurehead bottom half is in the outmost bottom position, to verify this pull
the bottom half of the measurehead down. (Due to friction at the joining point
between top and bottom half of the measurehead, the bottom half might not be in
the outmost bottom position)
➢ Visually check for a gap between the piston and the frame. If visually no gap can
be detected move the bottom half up and check the movement possible. If the
bottom half can not be moved there is no gap present.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

WARNING!
There should always be a gap between 1 millimeter and 2
millimeter to allow the system to work correctly. Refer figure.

To generate the gap:

➢ Connect the hand pump to the quick connector.

➢ Open the valve on the hand pump connection.
➢ Close the valve on the hand pump connection and re-check for a gap.
➢ If this gap is still not present re-open the valve and simulate a pressure on the
piston by pushing the top and bottom part of the measure head towards each
other. This will generate an extra pressure inside the system which will bleed oil
to the hand pump.
➢ Close the valve and recheck for a gap.

If the gap is too large:

➢ Open the valve and introduce some hydraulic oil into the system using the hand
pump.

Note!
THE SYSTEM MAY STILL NEED TO BE BLED COMPLETELY
WHERE AIR SO INTRODUCED DURING THIS OPERATION.

Measure head maintenance

WARNING!
Never use a solvent or a high pressure cleaning tool to clean the
complete measure head assembly. This might cause severe
damage to the bearings inside the measure head.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

Bearing lubrication

For proper measure head functioning it is required that the bearings on the
measurehead equipped with a grease nipple have grease applied on a regular basis.

Removing and installing bottom wheel

In contradiction to the other wheels on the measure head the bottom wheel does not
require periodic lubrication. Inside the wheel a closed bearing is mounted which will
ensure smooth wheel rotation without extra lubrication. However it is required to
remove the wheel on a regular basis and clean the bearing, shaft, bushings etc. It
might also be required to remove the wheel when the wheel or the bearing is damaged.

For removing the wheel:

➢ Use metric size spanner 17 to loosen the bolts holding the containment washers
on both sides of the shaft. Store the bolts, the spring washers and the
containment washers in a safe place.
➢ Support the wheel in position and slide out the shaft. The bushings might come
out with the shaft if not, remove the bushings by hand after the wheel is removed.
After removal store the bushings (2) in a safe place. Where the shaft locked in
position, gently tap the shaft with a rubber mallet to loosen the shaft.

The bearing:

➢ The bearing is secured in position using two circlips on both sides of the bearing.
To prevent the bearing from slipping a combination of H7 tolerance and glue
(Loctite 641) is used.
➢ Use a cir slip spanner to remove the circlips.
➢ To remove the bearing; slightly warm up the bearing using hot air to weaken the
glue. Use a rubber mallet to gently remove the bearing in combination with the
use of a bushing which fits inside the wheel bushing and large enough to have
contact with the outside of the bearing. Never apply any force on the side of the
inside bush of the bearing also be careful not to damage the inside of the wheel
bushing.
➢ To install a bearing; scrupulously clean the inside of the bushing, de-grease the
inside surface of the bushing and the outside of the bearing.
➢ Use Loctite 641 to glue the bearing into position.
➢ Reinstall the two circlips to secure bearing.
➢ Apply grease to both sides of the bearing to prevent bearing oxidation.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

To reinstall the wheel:

➢ Scrupulously clean all parts and measure head frame before reinstalling the
parts. DO NOT USE A SOLVENT TO CLEAN THE BEARING. After cleaning
apply (bearing) grease to all part surfaces to prevent wear. Also apply a thick
layer of grease on both sides of the bearing to prevent oxidation of the bearing
(leading to internal bearing damage).
➢ Insert the bushings inside the measure head frame.
➢ Put the wheel into position inside the frame. Keep the largest diameter of the
flange on the bushing on the right hand side (front view).
➢ Slide in the shaft and secure shaft into position using the shaft containment
washers and the two bolts. Ensure that the spring washers are also put into
position. When tightening the bolts do not apply extreme force. This might
damage the bolts and the shaft.

Removing and installing the top wheels

On the top half of the measure head two wheels are mounted. The measure wheel and
a second guide wheel. The guide wheel can independently rotate from the measure
wheel. The measure wheel is fitted onto a shaft, this shaft rotates inside two flange
bearing which are mounted inside the measure head frame. The guide wheel rotates
around the shaft using a bearing mounted inside the wheel. The shaft is also used to
connect a counter cable and / or a encoder for the depth counting system.
The two flange bearings require lubrication on a regular basis. It is also required to
remove the wheels on a regular basis to clean the bearings, shaft, bushings etc. It
might also be required to remove the wheel when the wheel or the bearing is damaged.

To remove the wheels:

➢ Remove the wire retainer using allen key,

metric size 5. Note; retain nut on other side of
bolt.

➢ Remove the wire guide rollers on the front

side of the measure head. Use metric
spanner size 19.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

➢ Support the counter outlet assembly and loosen the bolts holding the plate using
metric spanner size 13. With the bolts removed it is possible to remove the plate
with the counter assembly attached. When removing the assembly ensure to
store the counter coupling key (steel connection between shaft and gear or
encoder) and the bolts in a secure place.
➢ Loosen the clamp bushing on the right hand side (front view) using allen key
metric size 5. Do not loosen the clamp on the left hand side, this clamp can
remain installed on the shaft to ensure proper reinstallation (distance).

These clamp bushings hold the complete shaft assembly in place between the two
flange bearing.

➢ Remove the grease nipple inlet on the flange bearing.

➢ Loosen the flange bearing on the right hand side (front view) using allen key
metric size 6 and slide bearing of shaft.
➢ Now the clamp bushing inside the measure wheel becomes visible. This clamp
bushing clamps the measure wheel onto the shaft.

Loosen the clamp bushing by;

- loosen the 4 allen bolts using allen key metric size 6

- move the two allen bolts nearest to the slot to the middle holes
- carefully tighten the two allen bolts to loosen the clamp

➢ It is now possible to remove the shaft by sliding it out the assembly (from right to
left). When removing the shaft ensure to store the anti-meshing distance ring (in
between the wheels) and the stainless steel ring in a safe place.
➢ With the shaft removed it is possible to remove the wheels.

WARNING!
Beware of fingers getting trapped when removing the wheels.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

The guide wheel (bearing):

➢ The bearing is secured in position using two circlips on both sides of the bearing.
To prevent the bearing from slipping a combination of H7 tolerance and glue
(Loctite 641) is used.
➢ Use a cir slip spanner to remove the circlips.
➢ To remove the bearing; slightly warm up the bearing using hot air to weaken the
glue. Use a rubber mallet to gently remove the bearing in combination with the
use of a bushing which fits inside the wheel bushing and large enough to have
contact with the outside of the bearing. Never apply any force on the side of the
inside bush of the bearing also be careful not to damage the inside of the wheel
bushing.
➢ To install a bearing; scrupulously clean the inside of the bushing, de-grease the
inside surface of the bushing and the outside of the bearing.
Use Loctite 641 to glue the bearing into position.
➢ Reinstall the two circlips to secure bearing.
➢ Apply grease to both sides of the bearing to prevent bearing oxidation.

Distance plate (anti-meshing)

➢ In between the two wheels an anti-meshing plate prevents the two wheel
touching each other and thus preventing wear.

➢ Scrupulously clean the plate, after cleaning cover the plates surface with grease.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

Flange bearing

If a flange bearing is damaged have the bearing replace in whole.

To reinstall the wheels:

➢ Scrupulously clean all parts and measure head frame before reinstalling the
parts. DO NOT USE A SOLVENT TO CLEAN THE BEARINGS. After cleaning
apply (bearing) grease to all part surfaces to prevent wear except for the inside of
the measure wheel, the ends of the shafts and the clamps (3x). Also apply a thick
layer of grease on both sides of the bearings to prevent oxidation of the bearing
(leading to internal bearing damage).

➢ Insert the shaft (with on one side still a clamp installed) through the left flange
bearing. Push the shaft through until the shaft sticks out enough to slide over the
shaft the distance bushing.

Check!
DO NOT forget to install the distance bushing and the anti-
meshing plate. Insert the wheels both with the flanges pointing to
the outside.

➢ Insert the guide wheel into the frame and push the shaft through the guide wheel
bearing. Move the shaft enough to give room for the anti-meshing plate to also be
installed on the shaft. With the anti-meshing plate installed insert the measure
wheel into the measure head frame. Ensure the clamp is properly inserted into
the measure wheel (bolt heads pointing to the right). Push through the shaft until
clamp on the left hand side touches the flange bearing on the left hand side.
Since the clamp on the left hand side has not been removed the complete shaft
should be in proper position.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

➢ Push the measure wheel to the left to ensure that there is no room between the
separate components.
➢ Now the clamp inside the measure wheel can be tightened. Ensure that the front
of the clamp is aligned with the front of the measure wheel bush.
➢ Do not tighten one bolt complete without tightening the other bolts.
➢ Turn each bolt one count and then switch to another bolt.
➢ With the clamp inside the measure wheel tightened, install the flange bearing on
the right hand side. Use allen key metric size 6 to tighten the allen bolts. Do not
forget to install the grease nipple assembly.
➢ After installation, lubricate bearings on both sides with grease gun.

Check!
With all components installed check for smooth wheel rotation.
Also check that the measure wheel and the guide wheel can rotate
independently.

With the wheels rotating correctly, reinstall the counter assembly, the wire retainer and
the wire guide rollers. When installing the counter assembly ensure that the steel key is
properly inserted into the shaft end. Where this is installed there must be a small
amount of free lateral movement possible.

Servicing

Subject 600 1200 Yearly If required (according to

hours hours experience)
Wheel removing and x x
Cleaning

Trouble Shooting
Top wheels measure head
SIGNS CAUSES REMEDIES
Wheel does not rotate Friction level in the Replace the bearing
smoothly bearing is too high.
Accumulated dirt Removed wheel, clean
parts and reinstall

Wire guide rollers

➢ To ensure proper wire guidance to the drum and out to the well without wire
wear. The measure head is equipped with 4 wire guide rollers. If a roller is
damaged have the roller replaced in whole.

Slide bearing with shaft

The measure head slides over a hardened shaft using two bearings mounted inside the
top frame. The bearings require periodic lubrication (refer lubrication paragraph).
Besides lubricating the bearings it is also required to clean and lubricate the slide shaft
on a regular basis.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

To replace the bearings if worn;

➢ Remove the complete measurehead from the level wind shaft.

➢ Use a circlip spanner to remove the circlips on both sides of the measure head
frame.
➢ Remove the old bearings and replace with new bearing.
➢ Lock bearing into position using the circlips.
➢ Use a grease gun to pre-lubricate the bearings.
➢ Reinstall the measure head onto the slide shaft. Ensure the slide shaft is properly
mounted in position and all bolts are secured.
➢ Use a grease gun to lubricate the bearing while moving the measure head across
the shaft.

Depth and line tension measure system

For accurate depth and tension read out the measure head is connected to an ASEP
CombiGauge using a hydraulic pressure hose and a counter cable. This gauge
incorporates a combined depth and tension read out.

CombiGauge - depth indication

The CombiGauge depth indication is based on the measure head being equipped with
a measure wheel suitable for the wireline size being used. For other wire sizes or
change between metric and imperial read out, a splitter box change and a different
counter may be required to provide a step-up or step-down ratio. If other wire sizes are
used without the splitter box, the indicated depth will be out by a factor represented by
the measure wheel size and wireline diameter.

Operation of the CombiGauge depth counting relies on proper connection of the

mechanical drive cable to the operator module.

Check!
Before starting the operation, check the functioning of counting
system. Rotate the measuring wheel by hand and observe
correct (up/down) counting.

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Chapter 2 Wireline Unit, K-Lift, Wire Spooling and Handling HP Pumps Page 55 of 110
BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

Depth counting calculation

The length of wireline passing through the measure head is calculated using the
following calculation:

With the measure wheel rotating once the wheel surface

covers a distance equal to the diameter of the wheel times
phi. Since the wheel diameter is extended with the wire
diameter (refer figure), the actual wheel diameter is equal
to the wheel diameter plus the wire diameter. (On both
sides of the wheel half the wire diameter)

FOR EXAMPLE;
The length of wireline passing through with one wheel
rotation is : (with the measure wheel of a MP16, 0.108”
wire and in metric units)

Length of wireline =
(diameter wheel + wire diameter) x phi =
(411.84+ ((2.743x2)/2)) x phi =1302.45 millimeters

The counter inside the CombiGauge is connected to the measure wheel. When it is
connected directly, one rotation of the measure wheel is indicated with one unit on the
counter. We have calculated that one rotation of the measure wheel does not equal
one meter (one unit on the counter). With one rotation of the measure wheel the
counter needs to visualize the same indication (1.302). To obtain this the signal /
rotation from the measure wheel to the counter needs to be increased with an
approximate factor of:

1.30245 / 1 = 1.30245

This signal acceleration is achieved using angled and straight gearboxes. For this case
an 0.658:1 gearbox is used on the measure wheel outlet and an 1:0.857 gearbox is
used on the CombiGauge. This results in an acceleration of the signal leaving the
measure wheel outlet to (1 / 0.658=) 1.519757 and a deceleration of 0.857.

(1 / 0.658) x 0.857 = 1.30243

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Chapter 2 Wireline Unit, K-Lift, Wire Spooling and Handling HP Pumps Page 56 of 110
BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

As noticed there is a difference between these figures, however the difference can be
neglected because this ratio difference is only 0.00002 with every rotation, which is
only:
deviation per 10000 rotations =
length of wire with 10000 rotations x ratio difference
(1.30245 x 10000) x 0.00002 = 0.25 meter
(taking in account that the length of wire is 13024.51 meter the variation of 0.25 meter
can be neglected)
Thus using a MP16 measure head and 0.108" wire and a CombiGauge in metric read
out (meters) two gears will be used to ensure proper depth read out.

Combining different wireline sizes

On most units two different sizes of wireline is used. This means that for the difference
in wireline diameter this needs to be adjusted. (The measure wheel diameter remains
the same). This adjustment is achieved using a splitter gear. This gear has one inlet
and two outlets. By connecting to the appropriate outlet the selected drum / wire can be
chosen.
When using 0.108" wire and 0.125" wire the difference in wireline diameter is:
Length of one measure wheel rotation with 0.125" =
(411.84 + 3.175) x phi = 1303.808 millimeters
For each rotation this is a ratio deviation of:
ratio difference =
length with 0.125 / length of wire with 0.108" =
1303.808 / 1302.450 = 1.001
Thus the input signal needs to accelerated to get a correct visualization of the depth
read out on the counter. Due to the use of standardized splitter gears in this case
ASEP units are equipped with a splitter gear with ratio (1:0.99913=)1.001.

Rules to follow

Acceleration and deceleration of the output signal can only be obtained within some set
rules.

➢ It is not possible to use more than 2 gears connected directly to each other and
only a total of 3 gears may be used in the external counter system. (Not taken in
account is the internal ratio of the counter inside the CombiGauge)

➢ When using an imperial read out on the CombiGauge the counter inside the
CombiGauge does not use an 1:1 counter but uses a 1:5 counter.

This internal counter ratio is used to reduce the stress on the counter cable when
accelerating the signal.

Using a metric system one rotation of the measure wheel requires an acceleration of
approximately 1.3, since 1 meter is 3.281 feet, the signal with the imperial system
needs to be accelerated approximately 4.25 (1.3 x 3.281) times.

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Chapter 2 Wireline Unit, K-Lift, Wire Spooling and Handling HP Pumps Page 57 of 110
BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

Calculation example using imperial system:

length of wire line =

(diameter wheel + wire diameter) x phi=
(411.84+ ((2.743x2)/2)) x phi =1302.450 millimeters
1302.450 mm = 4.273 ft

Thus with one rotation of wheel the counter needs to indicate 4.273.

imperial system uses 1:5 counter inside the CombiGauge = ratio = 1: 5, with no gears
installed one rotation on measure wheel counter indicates 5. This needs to be 4.273.

Deceleration required is 0.855 (4.273 / 5). This is achieved with standard gears with
ratio 1.002 :1 and ratio 1.166:1.

Total deceleration =
(1/1.002) x (1/1.166)= 0.855

Measure wheel

Note!
The mechanical depth measurement system can not be adjusted
for measuring wheel wear. The wheel diameter should be
checked regularly to assure adequate measurement accuracy.
Replace the measure wheel in case of excessive wear.

CORRECT MEASURING WHEEL DIAMETERS:

For MP16 measure head

411.84 mm
16.214 inch

The depth counting system

As described the measure system can be adapted for

use with different wire line sizes. On most unit
configurations the described angled gear and /or
splitter gears are used. When a splitter gear is
incorporated into the measure system it is always
marked to ensure proper connection when switching
between wireline sizes.

Figure 24, Splitter gear 0.99359

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Chapter 2 Wireline Unit, K-Lift, Wire Spooling and Handling HP Pumps Page 58 of 110
BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

COUNTER SYSTEM ON MP 16 MEASURE HEAD

IMPERIAL METRIC
PRIMARY SECONDARY 1:5 COUNTER IN COMBIGAUGE 1:1 COUNTER IN COMBIGAUGE
WIRE WIRE GEAR ON GEAR ON SPLITTER GEAR FOR GEAR ON GEAR ON SPLITTER GEAR FOR

MEASURE HEAD COMBIGAUGE SECONDARY WIRE USE MEASURE HEAD COMBIGAUGE SECONDARY WIRE USE

0.092 1.021 0.872

0.108 1.002 0.857 0.658 0.857
0.125 0.903 0.772 0.483 0.630
0.108 0.125 1.002 0.857 0.99913 0.658 0.857 0.99913
0.108 3/16 1.002 0.857 0.994897 0.658 0.857 0.994897
0.108 7/32 1.002 0.857 0.99359 0.658 0.857 0.99359
0.125 3/16 0.903 0.772 0.99642 0.483 0.630 0.99642
0.125 7/32 0.903 0.772 0.99489 0.483 0.630 0.994897

CombiGauge - How to operate for depth read out

The mechanical depth counter may be reset to zero by pulling out the zero set knob
until all numbers have been reset to zero. Refer to figure. The input signal is connected
to the depth counter connection. Usually on this connection first an angled gear box is
connected. To this gearbox the counter cable is connected.

CombiGauge - line tension indication

Note!
Prior to operating the wireline unit the gap between the measure
head and the piston inside the bellow must be checked. Where
the gap is to large, i.e. not enough oil is in the system or where
too much air is in the system, the system could cease to operate
due to zero travel left in the bellow. This could result in tension
being placed on the wire without this being registered on the
CombiGauge.

The line pull measurement of the CombiGauge is factory supplied scaled in kilograms
or lbs. depending on customer requirements. The units used are described on the
CombiGauge scale. The line pull is indicated using the black arrow. Depending on the
required scale the CombiGauge is equipped with a boudin coil suitable for the required
read out. With pressure build up inside the coil the coil wants to straighten itself. This
value will change in direct accordance to the pressure build up and thus an indication
of the pull can be given. The boudin coil can not be changed out to change the scale
on the CombiGauge.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

The boudin coil assembly is mounted on a swivel plate which can be rotated to adjust
the line tension zero setting. (With no pull on wire set the black arrow on zero lbs / kgs
pull). It should be noted that boudin coil assembly can not be rotated completely, to
prevent damage to the system.

Operation of the CombiGauge line pull measuring relies on proper connection of the
hydraulic bellows sensing hose to the operator module.
Most important, however, is the requirement for the complete system, which comprises
of the hydraulic bellows, the connecting hose and the CombiGauge, to be properly air-
bled.

CombiGauge - How to operate line tension read-out

The line tension may be reset to zero, or offset by any value, by rotating the zero set
knob. Refer to Figure 27. The fixed line tension indicator needle may be set to any
value by rotating.

Use the pull dampening valve to adjust the sensitivity of the pull indication.

WARNING!
NEVER CLOSE THE PULL DAMPENING VALVE COMPLETELY.
Closing the valve completely will shut off hydraulic oil supply to
the boudin Coil. This will result in tension being placed on the wire
without this being registered on the CombiGauge.

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Chapter 2 Wireline Unit, K-Lift, Wire Spooling and Handling HP Pumps Page 60 of 110
BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

CombiGauge - line tension accuracy verification

➢ Thread the wireline through the measure head and pay out cable.

➢ Attach wireline to calibrated auxiliary load measuring device and secure to fixed
point.

➢ ENSURE THAT THE SYSTEM IS CORRECTLY BLED BY PERFORMING THE

WT SYSTEM BLEED PROCEDURE AS FOUND IN THE PARAGRAPH “HOW
TO BLEED THE WT SYSTEM” ON PAGE 37.

WARNING!
Before commencing, and during, all line pull testing, ensure that
the operating area is adequately marked and cordoned off. Do not
allow personnel to cross the wireline under tension. Do not use
wireline of inferior of substandard condition.

➢ Start with the line pul at zero, ie with cable laying on the groundRe-install the line
pull zero-set knob and adjust the needle to read zero (0)
➢ Operating the winch, apply a moderate pull to the line (approx. 500 lbs). Note the
actual reading on calibrated auxiliary load measuring device and that of the
CombiGauge.
➢ Increase the pull to approximately 1,000 lbs. Note the actual reading on
calibrated auxiliary load measuring device and that of the CombiGauge.

If there is a linear discrepancy between the CombiGauge reading and that of the
auxiliary device, the CombiGauge may require re-calibration.
If the discrepancy is non-linear, the most likely cause is remnant air trapped in the
CombiGauge or the hydraulic bellows and pressure line.

Note!
This line tension accuracy verification procedure can also be used
to calibrate the K-REC ExPC (if present).

How to bleed the WT system

Connect the filled hand pump to the free connection point on the hydraulic bellows on
the measure head and open valve.

WARNING!
Use only high grade ATF-F type oil to fill up the hand pump.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

At the bleed-off point on the level wind support arm

➢ Open bleed-off point screw and start pumping hydraulic fluid into thesystem.
➢ Continue pumping until only air-free hydraulic fluid starts to come out at bleed-off
point.
➢ Close off bleed-off point, close valve at hand pump connection, stop pumping and
remove hand pump.

At the CombiGauge bleed point

➢ Loosen slightly the bleed point on the CombiGauge, refer figure Figure 27.
➢ Open the valve at the hand pump connection and start pumping hydraulic fluid
into the system.
➢ Continue pumping until only air-free hydraulic fluid starts to come out at the bleed
point.
➢ Close valve at hand pump connection.
➢ Remove hand pump.

At the CombiGauge connection (after CombiGauge exchange)

➢ Loosen the nut on the top of the left hand side dashboard using a metric size 13
spanner.

➢ Carefully lower the dashboard.

➢ Loosen slightly the hydraulic hose connection on the CombiGauge.

Do not loosen completely!

➢ Open the valve at the hand pump connection and start pumping hydraulic fluid
into the system.

➢ Continue pumping until only air-free hydraulic fluid starts to come out at the
hydraulic connection.

➢ Tighten the hydraulic hoses connection and close valve at hand pump
connection.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

•• Remove hand pump.

•• Replace left dashboard.

CombiGauge - line tension re-calibration

The CombiGauge is factory set to provide a full scale deflection at either 25, 40 or 60
bar (scale dependant). This corresponds to the 360 o of travel of the CombiGauge
scale. Re-calibration of this setting is not a recommended field maintenance activity,
and should only be undertaken by personnel trained and familiar with fine mechanical
instrumentation.

WARNING!
Incorrect handling of the CombiGauge will result in instrument
damage necessitating factory repair and re-calibration.

➢ Reduce the line tension to zero.

➢ Remove the depth zero-set knob, the line pull zero-set knob and remove the
indicator front screws (4-PCs) and remove the CombiGauge glass face plate.
Replace the zero set knob.

➢ Rotate the line tension needle using the zero set knob. As the needle moves, the
calibration set screw will appear in the access hole in the CombiGauge face. This
calibration screw allows loosening of the variable linkage which affects the
leverage from the Boudin coil.

➢ Slightly loosen the calibration screw just enough (approximately half a turn) which
will allow movement of the linkage (reading adjustment) mechanism.

WARNING!
If the calibration screw is loosened too much, the CombiGauge
will have to disassembled to correctky re-tighten the linkage
mechanism.

➢ Moving the loosened linkage will affect the CombiGauge indication as follows:
- to the inside will decrease the indicator reading,
- to the outside will increase the indicator reading.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

For example:
If the reading on the combigauge is linear too high. Move the linkage to the outside.
(Referred from the center of the combigauge)

LINE TENSION COMBIGAUGE

0 0
100 150
200 300
300 450

If the reading on the combigauge is linear too low. Move the linkage to the inside.
(Referred from the center of the combigauge)

➢ Move the linkage a nominal amount (2 or 3 mm) in the direction of the required
adjustment, and re-tighten the calibration screw.

➢ Reset the CombiGauge to zero. Pick up line tension to approximately 500 lbs and
then approximately 1,000 lbs tension, and note the respective CombiGauge
values.

➢ Further adjustment of the calibration screw setting will be proportional to the

measurement discrepancy.

➢ Repeat the above adjustment procedure until the measurements are in

conformance with the auxiliary line tension measurement.

➢ Re-install the indicator front panel and the reset knobs.

LINE TENSION COMBIGAUGE

0 0
100 75
200 150
300 225

Servicing

Servicing
Interval
Subject Daily 600 hours Yearly If required
(according to
experience)
Check gap
between x x
piston and
frame

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Chapter 2 Wireline Unit, K-Lift, Wire Spooling and Handling HP Pumps Page 64 of 110
BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

Trouble Shooting

Depth System
SIGNS CAUSES REMEDIES
Inaccurate read Wrong splitter gear outlet Check splitter gear for wire
out on selection indication and change outlet if
CombiGauge required.
Angled gear for Change gear from measure
CombiGauge installed on head to CombiGauge and vice
measurehead and vice versa
versa
Wrong counter installed Check counter ratio. Ratio
in CombiGauge should be 1:5 with imperial and
1:1 with metric read out
Measure wheel worn Check measure wheel diameter
to be correct. If deviation is too
large have wheel replaced.
Wire on unit changed Check table wire and gear
without changes being information. Check gear
made on the measure installed are correct. If not
system contact ASEP for gear change.
Measure wheel Counter cable damaged Check counter cable for nicks
does not rotate and damage. If damaged have
counter cable replace.
Gear damaged Remove gear and check input
and output rotation by hand
Damaged bearing or Remove wheel and clean. With
accumulated dirt rotation still heavy change
bearing
Wheel touching frame Check measure head for
part damage and have damage
repaired.
Measure wheel Gear damaged Remove gear and check input
rotates but and output rotation by hand
counter does not Drive key damaged or not Replace drive key
react installed
Counter cable damaged Check counter cable for nicks
and damage. If damaged have
counter cable replaced.
Counter inside Rotate CombiGauge input by
CombiGauge damaged hand and check for counter
change. If no change open
CombiGauge and check for
internal damage.

Also check that the re-zero

knob is allowing the counter
shaft to turn and engage
correctly, i.e. if not adjusted
correctly this could disengage
the counter gearing.
Measure wheel slipping Check clamp to be properly
on shaft installed and be completely
clean on the contact surfaces.

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Chapter 2 Wireline Unit, K-Lift, Wire Spooling and Handling HP Pumps Page 65 of 110
BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

Line tension system

SIGNS CAUSES REMEDIES
With line pull no Dampening valve closed Open dampening valve
read out on Not enough hydraulic oil Introduce more hydraulic oil
CombiGauge inside system which into system. Ensure gap
causes piston not to remains present between
contact the measuring piston and frame.
head lower half
Bleed off point open Closed bleed off point
Hydraulic hand pump Close valve
connection valve open
Hydraulic hose damaged Check hydraulic hose and if
which causes hydraulic damage have hose replaced.
oil leakage
Air inside system Air bleed hydraulic system
Hydraulic bellow Check hydraulic bellow if
damaged leaking or damaged have
bellow replaced.
Calibration bolt inside Check bolt to be properly
CombiGauge loose or tightened. If not present have
missing bolt replaced.

If this has occurred it is

required to re-calibrate the
CombiGauge
With line pull Air measure system Air bleed complete
inaccurate With no line pull no gap Bleed some oil out system and
readout present between piston re-check for gap
and frame
Measurehead not Calibrate measurehead
properly calibrated
With line pull Not enough hydraulic oil Introduce more hydraulic oil
increasing read inside the system which into system. Ensure gap
out remain at causes piston not to remains present between
certain value contact the measuring piston and frame.
head lower half

Level wind system

To ensure even wire spooling over the drum / reel it is required that the measure head
eq wire guide movement can be controlled from the operator cabin. This control can
either be mechanically or hydraulicly powered.

Mechanical control

For mechanic control, a steering wheel (01) in the operator cabin is fitted central
between the left and the right dashboards. This steering wheel is connected to a right
angle drive (02), from this right angle drive a shaft is connected to another right angle
drive (02), from here a spline shaft (03) is mounted to make it possible to store the
measurehead in the winch cabin. At the end of the spline shaft a chain wheel (05)
drives the levelwind drive chain (06). On the other side of the drive chain a chain
tensioner (07) is fitted. When stowing the measurehead the chain can be released
using this chain tensioner.

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Chapter 2 Wireline Unit, K-Lift, Wire Spooling and Handling HP Pumps Page 66 of 110
BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

WS-302-C ASEP K – LIFT GIN POLE MAST

The ASEP K-Lift Gin Pole mast is a portable hydraulic operated mast complete with
outriggers and stabiliser pads. The mast is movable in any direction as the main frame
is equipped with transporting wheels but needs to be positioned by manhandling.
Booming up / down, telescoping in / out and winching up /down is done hydraulicly by
using the K-Winch wireline unit,s power pack as power source.

Operator's daily checklist.

This paragraph provides a listing of these inspection procedures which must be

performed before placing the unit in operation each day. Also, careful attention should
be paid during actual operation of the unit to observe any defects which might appear
between regular inspections especially those conditions which could possibly constitute
a safety hazard.

WARNING
Do not operate machine until corrective measures have been taken and all
malfunctions have been corrected.

1. Visually inspect machine for loose or missing parts, foreign objects, hydraulic
leaks from lines or components, and structural damage.

2. With all systems shut down and machine in stowed or travel mode, check oil level
in hydraulic fluid reservoir of power pack. If necessary fill to the FULL mark on
level eye.

NOTE
On new machines, those recently overhauled, or after changing hydraulic oil,
operate all systems a minimum of two complete cycles and recheck oil in
reservoir

WARNING
Never handle cables with bare hands, broken or frayed wire strands can cause
severe cuts. Always wear protective gloves if it is necessary to handle the cable.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

3. Inspect cable for defects as follows

a) Corrosion.
b) More than one broken wire in any one strand.
c) More than one broken wire near an attach fitting.
d) Excessive wear and/or broken wires in cable sections under sheaves
where cable travel is limited.
e) Evidence of noticeable reduction in original cable diameter after allowance
for normal stretch and diameter reductions of newly rigged cable.
f) Excessive abrasion, scrubbing and peeling of outer wires; pitting,
deformation, kinking, bird caging or other damage resulting in physical
changes to the cable structure.
g) Cracked, bent, worn or improperly installed cable ends.

4. Inspect hook for security of attachment, proper swivel lubrication and for nicks,
cracks, gouges, deformation or evidence of any other damage. Check operation
of hook safety latch.

5. Check anti two-blocking ballhead for proper position and rope insertion.

6. Ensure that all components requiring lubrication are serviced as necessary.

7. Ensure that all control placards, located adjacent to the corresponding control
device, and all safety, warning and instruction placards are securely attached and
legible.

8. Using all applicable safety precautions and having checked proper connection of
quick connect couplings, start power pack.

9. With the unit operating and before starting actual jobsite applications, inspect the
following
a. Smooth and proper operation of all crane functions.
b. Check that boom and jib cable sheaves rotate freely and ensure that they
are in good condition.
c. Inspect all control levers, hoses and fittings for proper installation and
operation.
d. Ensure that deck, steps and operator site are free from oil, fuel, mud and
other debris.
e. Check anti-two block relief for proper operation. The hook block must stop
when it contacts the boom tip while winching up or telescoping out.
f. Ensure that preset components and covers have undamaged seals.

Transporting the crane safely.

a. General.

Certain precautions must be taken to ensure safety of personnel and to avoid

damage to equipment when moving the crane between jobsites. The safety
precautions provided here are not intended to replace or take precedence over
federal, state, local or company rules which govern the use of cranes. In addition,
insurance regulations should be recognized where and when applicable.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

b. Transport.

1. Never transport with a load on the hook.

2. Ensure that the boom is retracted and properly stowed in the transport
position. (0-degree horizontal).

3. Always secure the hook to the boom.

4. Ensure that outriggers stabilizers, pad pins and snap rings are secure.

5. If applicable, ensure that the jib assembly is securely stowed.

6. Disengage the hydraulic hoses from power pack.

7. Secure or remove all loose items.

8. If necessary, appoint a person to provide the proper signals when

maneuvering the unit in close quarters or when operator's visibility is
limited.

Crane Controls and Indicators.

Control over all crane functions is achieved by the use of a control lever mounted at the
operator station at side of the pedestal.

1 Telescope Control.

Extension and retraction of the boom is controlled by the boom lever. Forward
movement of the control lever provides for extension of the boom sections while
rearward movement of the control provides for retraction. When the lever is in the
center or neutral position, a hydraulic holding valve mounted on the telescope
cylinder prevents inadvertent retraction of the boom in the event of hydraulic line
failure.

2. Winch Control.

Progressive control of the crane hoist is achieved by means of the WINCH

control lever. Forward movement of the control permits lowering of the cable
while rearward movement raises the cable. A brake incorporated into the winch
assembly functions to hold the cable in the desired position when the lever is in
the center or neutral position.

3. Lift Control.

Raising and lowering of the boom is accomplished by means of the BOOM

control lever. Forward movement of the control permits lowering of the boom
while rearward movement raises the boom. A hydraulic holding valve prevents
inadvertent lowering of the boom in the event of hydraulic line failure or when the
control lever is moved from the center or neutral position with the engine stopped.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

4. Anti-Two Block.

When the lifting device contacts the mast top sheeve assembly, a hydraulic relief
valve will limit operating pressure.

5. Boom Angle Indicator.

A pendulum type boom angle indicator is mounted on each side of the base
boom and is visible from the operator station.
The indicator measures the full range of boom movement from 0 degrees
horizontal to 85 degrees above horizontal in 10 degree increments in the above
horizontal range. A green/red scale gives allowed operation angle sectors.

6. Crane Level Indicator.

A circular bubble-type level indicator is located on the top of the pedestal. This
"bulls-eye" indicator provides the operator with an indication of crane attitude
when setting the outriggers so that the operator can properly level machine.

7. Safe Load Indicator.

A hydraulic indicator located at the operator panel provides constant monitoring

of the load exerted, by the load and the boom assembly, on the topping cylinder.
A green/red scale gives indication of allowed operating condition

8. Hydraulic Pressure Indicators.

Hydraulic pressure indicators located at the operator panel provide constant

monitoring of hydraulic power in- and output. These gauges should be used as
indicators only. Use proper calibrated gauges to assist in pressure setting of relief
valves and alarms.

A green/red scale gives indication of allowed operating condition.

The hydraulic power input should be such that operation pressure is as close as
possible to maximum (red scale section) to give maximum function (lifting) power.

9. Acoustic Alarm.

An acoustic alarm provides operator warning (in combination with automatic

function cut-out) of an unsafe operating condition.

Crane positioning and operation.

Move the stowed crane unit to the desired worksite, using the crane unit transport
wheels and manually push/pull unit or hook-up crane unit to hydro-power pack and
use the crane winch and rope/hook assembly to pull unit to worksite.

1. Steering of the crane is done by the 2 pcs front wheels. The pulling assembly is
used to aid in the positioning of the front wheels. Both pulling rod-ends (slotted
parts) should be placed over the steering wheel upper shaft ends. Pulling and
steering should be done by guiding the connection bar.

Fold out the 4 pcs. outriggers and lock in position with locking pins. Remember
that all 4 outriggers should be locked in position to allow any crane function.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

2. Hook-up crane unit to hydro powerpack, using the hydraulic quick-connector.

Check connection to be correct with connector key-pin falling in hose manifold
guide hole.

3. Ensure that hydraulic input is maximum:

- flow - 12 Itr/min.
- pressure - 150 bar.

Pre-plan and anticipate the lifting operation and determine required mastlength
using the mast reach and hook height tables.

When positioning of the mast unit over the load/job site is hampered, then
operate the boom lift control and raise boom to higher angle. Further positioning
of crane unit is possible (with raised boom and locked outriggers) by steering the
front wheels independantly and pulling.

4. Level the unit using the stabiliser pads and, if necessary, cribbing.
Check machine level before and during all lifting operations.

WARNING
Before attempting to raise the boom, ensure that no loose objects that might
slide or fall of while boom is being raised, are laying on the boom sections.

Operate the crane unit, bearing in mind all previously described safety
measures/procedures. Ensure no loose objects are placed on top of mast that may fall
or slide of the mast during mast topping.

Mast telescope extension is possible only: with locked outriggers.

with boom in 80 - 85 degree.

Mast telescope retraction is possible: at all times.

Winch hoisting operation is possible only: with boom in horizontal.

with boom in 80 - 85 degree.

Winch lowering operation is possible: at all times.

Mast lifting (0 - 80) is possible only: with locked outriggers.

with fully retracted mast.
with zero load on cable hook.

Mast lowering (80 - 0) is possible only: with locked outriggers.

with fully retracted mast.
with zero load on cable hook.

Mast lifting (80 - 85) is possible: at all times.

Mast lowering (85 - 80) is possible: at all times.

The crane unit winch and telescoping functions have been factory preset to limit load
lifting to 900 kgs.

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Chapter 2 Wireline Unit, K-Lift, Wire Spooling and Handling HP Pumps Page 71 of 110
BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

When during crane unit operation, the crane unit safe workload value is exceeded
(overload situation - boom angle lower than 80°), the following functions will be
automatically de-activated with audible alarm sounding;

- load lifting using the winch

- mast telescoping (load lifting using telescope)
- mast lowering

These are functions that would further increase the crane unit load value. All functions
that will effect lowering of the crane unit load value are still free to operate i.e.;

- load lowering using the winch

- mast retracting (load lowering using telescope)
- mast lifting.

To unlock the crane unit safety system, operate the mast topping function to raise the
boom angle and bring the crane unit into safe condition.

When attempting to raise a load in excess of 900 kgs by way of winching or

telescoping, this function will be automatically de-activated.
No audible alarm will sound in this case. Check safe workload indicator.

Removing any of the outriggers from their locked position during crane operation will
result in a total crane topping function de-activation.

WARNING
Do not lift/lower any loads, neither with winch nor mast, and however small, with
mast in any angle between 0 - 82 degree. Crane unit may topple when this is
attempted.

WARNING
Do not raise/lower extended boom over mast angle 0 - 79 degree. Crane unit may
topple when this is attempted.

If, for any reason, the machine needs to be left unmanned and with boom in raised
position, always ensure the following:

- mast boom is securely fastened by guy-wires. Special guy-wire connection

points are provided on mast top section and fly-jibs.

- mast topping cylinder bottom hydraulic connection is closed by closing the

ballvalve situated on cylinder bottom connection.

- load is securely fastened to hook and with load outswing due to windforces
prevented by load tie-down ropes.

NOTE
Reach is given as measured from boom pivot to load-line.
Mast length markings A -/-F are as shown on mast mid-boom.

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Chapter 2 Wireline Unit, K-Lift, Wire Spooling and Handling HP Pumps Page 72 of 110
BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

MAST REACH TABLES

REACH (MTR) MAST WITH SHEAVE HEAD ASSEMBLY

MAST ANGLE (degree)

MAST LENGTH 79 80 81 82 83 84 85
MARKING
- 1.5 1.4 1.3 1.2 1.1 1.0 0.9
A 1.7 1.6 1.4 1.3 1.2 1.1 1.0
B 1.9 1.7 1.6 1.5 1.3 1.2 1.1
C 2.0 1.9 1.8 1.6 1.4 1.3 1.2
D 2.3 2.0 1.9 1.8 1.6 1.4 1.3
E 2.4 2.2 2.0 1.9 1.7 1.5 1.3
F 2.6 2.4 2.2 2.0 1.8 1.6 1.4

REACH (MTR) FOR MAST WITH FLY-JIB NO. 1 AND SHEAVE HEAD ASSEMBLY

MAST ANGLE (degree)

MAST LENGTH 79 80 81 82 83 84 85
MARKING
- 2.1 2.0 1.8 1.7 1.5 1.4 1.2
A 2.3 2.1 2.0 1.8 1.6 1.5 1.3
B 2.5 2.3 2.1 2.0 1.8 1.6 1.4
C 2.7 2.5 2.3 2.0 1.9 1.7 1.5
D 2.9 2.7 2.5 2.2 2.0 1.8 1.6
E 3.0 2.9 2.6 2.4 2.1 1.9 1.6
F 3.2 3.0 2.8 2.5 2.3 2.0 1.7

REACH (MTR) MAST WITH FLY-JIB NO. 1 AND 2 AND SHEAVE HEAD ASSEMBLY

MAST ANGLE (degree)

MAST LENGTH 79 80 81 82 83 84 85
MARKING
- 2.8 2.6 2.4 2.2 2.0 1.7 1.5
A 3.0 2.7 2.5 2.3 2.1 1.8 1.6
B 3.2 3.0 2.7 2.4 2.2 1.9 1.7
C 3.4 3.1 2.8 2.6 2.3 2.0 1.8
D 3.5 3.3 3.0 2.7 2.4 2.1 1.9
E 3.7 3.4 3.1 2.8 2.5 . 2.2 2.0
F 3.9 3.6 3.3 3.0 2.7 2.4 2.1

Hook height is given as measured from hook to groundleveL

Mast lenght markings A-I-F are as shown on mas mid-boom.

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Chapter 2 Wireline Unit, K-Lift, Wire Spooling and Handling HP Pumps Page 73 of 110
BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

HOOK HEIGHT TABLES

HOOK HEIGHT (MTR) MAST WITH SHEAVE HEAD ASSEMBLY

MAST ANGLE (degree)

MAST LENGTH 79 80 81 82 83 84 85
MARKING
- 5.6 5.6 5.7 5.7 5.7 5.7 5.7
A 6.6 6.6 6.6 6.7 6.7 6.7 6.7
B 7.6 7.6 7.6 7.6 7.7 7.7 7.7
C 8.5 8.6 8.6 8.6 8.7 8.7 8.7
D 9.5 9.6 9.6 9.6 9.7 9.7 9.7
E 10.5 10.5 10.6 10.6 10.6 10.7 10.7
F 11.5 11.5 11.6 11.6 11.6 11.6 11.7

HOOK HEIGHT (MTR) FOR MAST WITH FLY-JIB NO. 1 AND SHEAVE HEAD
ASSEMBLY

MAST ANGLE (degree)

MAST LENGTH 79 80 81 82 83 84 85
MARKING
- 9.8 9.9 9.9 9.9 10.0 10.0 10.0
A 9.9 9.9 10.0 10.0 10.0 10.1 10.1
B 10.9 10.9 11.0 11.0 11.0 11.1 11.1
C 1 1.9 1 1.9 12.0 12.0 12.0 12.1 12.1
D 12.9 12.9 12.9 13.0 13.0 13.1 13.1
E 13.8 13.9 13.9 14.0 14.0 14.1 14.1
F 14.8 14.9 14.9 15.0 15.0 15.0 15.1

HOOK HEIGHT (MTR) FOR MAST WITH FLY-JIB NO. 1 AND 2 AND SHEAVE
HEAD ASSEMBLY

MAST ANGLE (degree)

MAST LENGTH 79 80 81 82 83 84 85
MARKING
- 12.3 12.3 12.4 12.4 12.4 12.5 12.5
A 13.2 13.3 13.3 13.4 13.4 13.5 13.5
B 14.2 14.3 14.3 14.4 14.4 14.5 14.5
C 15.2 15.3 15.3 15.4 15.4 15.4 15.5
D 16.2 16.3 16.3 16.4 16.4. 16.4 16.5
E 17.2 17.2 17.3 17.3 17.4 17.4 17.5
F 18.2 18.2 18.3 18.3 18.4 18.5 18.5

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Chapter 2 Wireline Unit, K-Lift, Wire Spooling and Handling HP Pumps Page 74 of 110
BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

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Chapter 2 Wireline Unit, K-Lift, Wire Spooling and Handling HP Pumps Page 75 of 110
BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

WS-302-D WIRELINE INFO AND SPOOLING OF WIRE

Wireline may be referred to by a number of names. Solid single strand line may be
described as:
• Slickline.
• Piano wire.
• Solid line.
• Wireline.
• Measuring line.

Multi strand wirelines are usually described as braided line (3/16” most common).

As well depths have increased over the years since the first measuring lines were
brought into use accompanied by increased working loads, it has become necessary to
develop wireline having a high strength / weight ratio. There is a need for strength to
accomplish the operation without the wire breaking, and a need to keep the diameter of
the wire as small as possible for the following reasons:

(i) It reduces the load of its own weight.

(ii) It can be run over smaller diameter sheaves, and wound on smaller diameter
spools or reels without overstressing by bending.
(iii) It keeps the reel drum size to a minimum.
(iv) It provides a small cross-section area for operation under pressure.

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Chapter 2 Wireline Unit, K-Lift, Wire Spooling and Handling HP Pumps Page 76 of 110
BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

The sizes of solid wireline in most common use are 0.092" and 0.108" diameter.
0.062", 0.072", 0.082", and 0.105", are also available but not in common use. A larger
line of 0.125" diameter is now also available and is becoming popular for its added
strength in many locations. Solid wirelines are manufactured at the drawing mills in one
piece lengths of 10,000 / 12,000 / 15,000 / 18,000 / 20,000 and 25,000 feet.

The most popular material for wireline is Improved Plow Steel (IPS) because of its high
ultimate tensile strength, good ductility, and relatively low cost. Experience indicates
that improved plow steel usually performs better than the more expensive special steel
lines, even in corrosive conditions when used with an appropriate inhibitor (e.g. Servo
CK352 or CK356). For `sweet wells', IPS can be used with an inhibitor for high loads
and long service. For `sour wells', IPS can be used with an inhibitor for high loads and
short operating time.

When selecting or operating with wireline, various factors such as the following have to
be considered:

• Physical properties.
• Total stress.
• Resistance to corrosion .
• Care and handling.
• Effect of bending.
• Environmental conditions - Desert dust, salt water, subzero temperatures etc.
• Well pressure - Influences the effects of the H2S.
- Effects magnitude of force on the line diameter.

Due to the H2S and CO 2 content of many wells, special materials such as 0.092"
Nitronic-50 manufactured by Briden Wire or stainless steels are used. Although these
are not as strong as IPS, they have an excellent resistance to corrosion.

The bending stresses creating a weak point are the most common cause of broken
line, but are often the least considered. Bending stresses occur whenever a wireline
deviates from a straight line condition, such as when it passes over pulleys or reel
drums or when it is flexed by hand. As with all metals, continued bending at one point
will crystalise the material and lead to a `fatigue' break.

Each time the line passes over a pulley it is subjected to 2 bending stresses - when it
changes from a straight to a curved path, and again when it reverts to a straight path. It
is subject to only one when it leaves the reel drum. So for each trip in and out of the
well, the line probably suffers a minimum of 14 bending cycles.

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Chapter 2 Wireline Unit, K-Lift, Wire Spooling and Handling HP Pumps Page 77 of 110
BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

The following tables shows the relative strengths of IPS, UHT and H 2S resistant alloy
wirelines:

Approximately
Materials Diameter Breaking Recommended Weight per Characteristics
(inches) Strength Maximum Load 1,000 metres
(kgs) (lbs) (kgs) (lbs) (kgs) (lbs)
IPS 0.092 704 1547 510.0 1125 33.50 74.0 For non-corrosive wells.
0.108 956 2109 816.0 1800 46.30 102.0 Relatively inexpensive.
0.125 1288 2840 914.0 2016 62.10 137.0
Bright UHT 0.092 898 1980 673.0 1485 33.50 74.0 For higher strength than IPS
0.108 1233 2720 925.0 2040 46.30 102.0 in similar conditions.
0.125 1651 3640 1238.0 2730 62.10 137.0
Nitronic-50 0.092 658 1450 306.0 675 33.50 74.0 Good in H2S chlorides up to
390°F. More sensitive to
acid at higher temperature
than stainless.
304 0.092 703 1550 457.0 1007 21.06 68.5 Good resistance to H2S.
Stainless 0.108 952 2100 619.0 1365 42.60 94.0
0.125 1224 2700 796.0 1755 62.85 138.6
Supa-60 0.092 1260 498.8 1100 31.06 68.5 Very good resistance to H2S
Alloy 0.108 1720 748.3 1650 42.60 94.0
0.125 2220 645.4 1443 62.85 138.6

It is important to spool the new line correctly.

Tension Approximately 300 lbs (150 kgs) of tension is recommended
during spooling, to prevent the line `cutting' down into the drum
under load when in use.
Bedding Layers' Carefully aligned wraps of wire are recommended to provide a
firm base and give an indication of the wire low level.
Curvature The natural curve of the line, as shipped, should be maintained
as it is spooled onto the drum.

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Chapter 2 Wireline Unit, K-Lift, Wire Spooling and Handling HP Pumps Page 78 of 110
BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

WS-302-E ASEP WIRE SPOOLING UNIT OPERATION MANUAL

Note!
All information contained in this documentation and attachment is confidential,
proprietary and is subject to change without notice. The copyright of this
documentation and attachment are vested in ASEP, neither the whole or any part
may be reproduced in any form without prior written consent of ASEP.

*Copyright ASEP BV Netherlands. All rights reserved.

While working with ASEP equipment follow the field’s rules and regulations.

Read and understand this manual before operating ASEP equipment.

Use this manual as a guide for system operation in conjunction with common sense
and operator experience.

While working with ASEP equipment wear appropriate work clothing and personal
protective equipment as required.

Let only qualified and experienced personnel operate ASEP equipment. This will help
prevent damage to the equipment and reduce the possibility of dangerous situations
arising.

Do not restart ASEP equipment after an emergency stop without verifying that the
cause of this stop has been removed or rectified.

The equipment has been designed and built for particular purposes. Do not attempt to
use the equipment for other purposes outside its design scope. This may lead to
damage and/or dangerous situations.

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Chapter 2 Wireline Unit, K-Lift, Wire Spooling and Handling HP Pumps Page 79 of 110
BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

During wireline operations consider the zone in front of the wireline unit as a danger
zone. For safety reasons keep the following points in mind.
Z In this zone there is always danger.
Z Never step over the wireline.
Z Never allow spectators to stand near the working area.
Z If possible, rope off this area with signs and/or bright tape.
Z If the wireline is rigged up but not run for a period. Clamp the wire and “flag”
the wire with signs.
Z When the wireline unit is tied down on deck using rope/line, “flag” the
ropes/lines with signs.

When lifting the unit by crane, make sure that you cannot get trapped between the load
and a wall, fixed object etc. If possible, position yourself so that you are visible to the
crane operator. If not, make sure to have a flagman to give signs to the crane operator.

Never walk under a hanging load!

Make sure that lifting gear to be used is sufficiently dimensioned and certified.

Never leave an “operation-ready” unit unattended.

Do not operate damaged equipment. This may lead to further damage and/or
dangerous situations.

Respect and maintain your working environment. Dispose of waste correctly.

Keep all safety guards in position while operating ASEP equipment. Removal of any
safety guards may lead to accidents.

When engaged in maintenance and / or performing checks on the unit:

First consider your safety and that of others.

- Make sure that the equipment is switched off completely and use a decal or
similar to prevent unauthorized starting during maintenance or check up.
- Never work on a hydraulic and / or pneumatic system under pressure. Always
relieve the system to prevent dangerous situations.
- Never attempt to move heavy parts without aid of a mechanical device.
- Do not allow heavy objects to rest in an unstable position.
- Use the right tools for the task.

Let only qualified personnel with the right tools perform maintenance on ASEP
equipment. This will prevent damage to the equipment and prevent the dangerous
situations.

Parts that have not been approved by ASEP cannot be relied upon to be of the correct
material strength, correct dimensions, finish or quality. ASEP cannot be held
responsible for any damage arising from the use of such parts.

Safety signs

For reasons of safety the ASEP equipment is marked (if applicable) with safety signs.
Each sign indicates a possible danger zone. Keep the meaning of these safety signs in
mind while working with ASEP equipment. This will prevent dangerous situations and
personal injuries.

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Chapter 2 Wireline Unit, K-Lift, Wire Spooling and Handling HP Pumps Page 80 of 110
BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

Also all safety instructions in this manual have been earmarked with caution signs.
Please observe! An explanation of the used earmarks is:

This is warns for a general danger.

This sign warns for automatically staring and stopping machinery.

This sign warns for moving machinery. Make sure that no body parts
and/or clothing can caught in the machinery.

This sign warms for hot surfaces.

Do not touch the indicated parts with bare hands while the unit is
running or has run for a time.

This sign warms for high voltage electrical parts. Do not touch
electrical components while energized.

Used to earmark a piece of text which may be vital to ensure safe

unit operation, ignoring a WARNING! May result in unsafe and
potentially dangerous situations.

Used to earmark a piece of text which gives additional, Important

information.

Used to earmark a piece of text which gives a summary of things to

check.

Scope

The following specification provides a description of the Wire Spooler © (A.SPL). The
Wire Spooler © is designed to provide a complete spooling system for most
applications where wire requires to be spooled under controlled tension from standard
shipping drums onto wireline units or from wireline units onto shipping drums. The unit
is supplied complete with a remote control unit to enable operation from the wireline
winch unit.

In order to make the basic unit operable a reliable electrical and workshop air supply is
required. The Wire Spooler © is intended to be used in conjunction with any design of
wireline unit.

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Chapter 2 Wireline Unit, K-Lift, Wire Spooling and Handling HP Pumps Page 81 of 110
BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

Technical specifications

Spooling frame
& steel 37 construction
& forklift pockets
& 4 point lifting
& base frame tie down points
& dimensions (LxWxH)
& design temperature
& Unit weight;

: 00C to +500C (+220F to 1220F)

R = 0800 kgs
Tf = 0800 kgs
P = 0000 kgs

& Main drive;

Electric driven (5 kw)

& Operating temperature;

zero (0) degrees Celsius - forty (40) degrees Celsius

& Connections;
Air input; Jaymac crowsfoot coupling
Electrical input; 440 Volts, 3 PHASE
24 Ampere fuse socket

General

& variable spooling tension provided via capstan system

& electronically controlled electro-motor providing shipping drum to capstan back
tension
& heavy duty air ventilated disc brake providing capstan to wireline unit back
tension
& electro-motor control for efficient spooling of wire from wireline unit
& hydraulic lift arms for drum mounting
& fixing of shipping drum to hydraulic lift arms by means of support shaft and
clamping system
& approximate performance as per table below (maximum drum speed 120 rpm) :

Maximum back tension spooling Maximum back tension spooling

wireline off wireline unit wireline onto wireline unit
50 kg 110 lbs 800 kg 1763 lbs

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Chapter 2 Wireline Unit, K-Lift, Wire Spooling and Handling HP Pumps Page 82 of 110
BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

Remote Control Unit

& Line tension control

& Shipping drum speed control
& Speed alarm light and sounder
& Emergency stop control
& 15 m Electric cable

Unit operations

Note!
In case of emergency press the button on top of the remote
control or the button on the unit (as indicated). Before start check
the emergency stop buttons to be functioning properly. Be aware
the emergency stop will disconnect electrical power to the unit, it
will not immediately stop the spooler drum.

Unit Rig-Up

To prepare the unit for operations, do the following:

& Position the unit on a flat and firm surface directly in line with a wireline unit or at
a 90 degree angle to the wireline unit where a Martin Decker type load cell needs
to be positioned.
& Connect the unit to a power input (415 Volts, 3 PHASE with ground, 25 Ampere
fuse socket)
& Connect a hose to the air input. (Clean, dry and oil free air with a pressure
between 5 and 9 bar)
& Position the signaling device on the spooler such that the operator in the wireline
unit has clear visibility to this.

WARNING!
When disconnected or connecting
the air supply hose from the coupling
always first close the main air supply
valve.

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Chapter 2 Wireline Unit, K-Lift, Wire Spooling and Handling HP Pumps Page 83 of 110
BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

How to install / remove a drum to /from the wire spooler

& Ensure main power is disconnected from the unit. To make sure that nobody can
unintentionally re-connect and start the unit press the main emergency stop
button on the unit.
& Ensure cable on the drum is properly secured. (If applicable)
& Use the valve on the hand pump to lower the drum onto the work floor.
& Loosen the hand clamp holding the drum.
& Use a spanner size 19 to loosen the clamp on the shaft as indicated on the
picture.
& Slide out the shaft holding the drum while removing the drum spigot adaptors and
clamp.

Note!
When installing a smaller size drum the large size drum spigot
adapters can be stored on the pin as indicated.

•• Slide the drum off the drum drive system. It is now possible to roil the drum out of
the wire spooler and replace with other drum.

NOTICE
CONNECT UNIT TO APPROPRIATE
POWER CONNECTION: 440 VOLTS/ 3 PH

BEFORE UNWINDING THE REMOTE CONTROL

CABLE, REMOVE REMOTE CONTROL
CONNECTION FROM SOCKET UNDER MAIN
CONTROL BOX

Figure 1. Connection notice

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Chapter 2 Wireline Unit, K-Lift, Wire Spooling and Handling HP Pumps Page 84 of 110
BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

- Reinsert the drive shaft. (Ensure the appropriate size drum spigot adapter is
fitted)
- Secure the drum clamp using spanner size 19.
- Ensure the drum drive system is adjusted to the drum and secure drum using the
hand clamp system.
- Use the hand pump to lift the drum to its maximum elevation and check the hand
pump valve to be properly closed.

It is now possible to lead the wire around the spooler guide wheels. When spooling
wire from a unit to the spooler it is only necessary to wrap the wire only once around
the spooler wheels. When spooling wire onto a wireline unit it is necessary to wrap the
wire using all grooves on the spooler wheels, this to ensure that proper wire tension
can be achieved.

Note!
Before wrapping wire around the spooler wheels remove the wire
containment shaft from above and under the spooler wheels. (As
indicated on picture). After wire installation; do not forget to
reinstall the shafts and to lock them into position using the
safety pins.

Note!
After drum and wire
installation release
emergency stop on the main
unit by pulling on the button.

Before start inspection

Prior to starting the unit, the following should be checked/inspected:

- Check for hose leakage and for other visible (transport) damage.
- Check all mounting bolts on unit.
- Unit is connected to the correct power and compressed air input.
- Bearings on the spooler shaft are lubricated using a grease gun with high quality
multi purpose grease. (Also lubricate the bearings on the spooler wheels)
- Check oil level in reduction gears. Also refer to paragraph “Planetary Reduction
gear” on page 19.
- Check the drum drive chain for freedom of movement and correct tension using
the tension adjust system.

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Chapter 2 Wireline Unit, K-Lift, Wire Spooling and Handling HP Pumps Page 85 of 110
BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

& Check the position of the air brake valve (on top of air brake) to be pushed in. If
not push down air valve to activate air brake. When opening air brake ensure air valve
is pulled out. Refer figures.

How to use the unit

Item Function Description

A BACK TENSION Use this control to adjust the back tension setting. (Wire
tension when spooling onto the wire line unit). This is
achieved by adjusting the air pressure applied to the
capstan brake as can be witnessed via the pressure gauge
mounted on the control box.
This function will not be operable when using the spooling
setting (Item B, SP setting).
B SPOOLING / BACK Use this control to select the appropriate function. Back
TENSION tension is applicable when spooling the wire from the wire
spooler to the wireline unit and spooling tension is
applicable when spooling wire from the wireline unit to the
wire spooler.
C WIRE SPEED Use this setting to adjust the wire speed while spooling off a
wire line unit onto the spooler. Turn clock wise to increase,
speed turn counter clock wise to decrease speed. This
function will not be operable when using the back tension
setting.
D OVERSPEED / This signal will light up when an internal (electric) error has
FAULT occurred or when the spooling speed (on or off the
spooler) is too high for the electric controls. If the speed
is too high do not abruptly slow down the speed, slow down
speed with small increments.

Where this lights up on the indicator on the unit, the speed

must be slowly decreased until the light stops. Where this is
not performed the unit will go into override and ceased to
supply electrical control.

Note: Where the unit goes into override the control

box must be opened and the “RESET” button
pushed.

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Chapter 2 Wireline Unit, K-Lift, Wire Spooling and Handling HP Pumps Page 86 of 110
BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

Note!
Back tension is applicable when spooling wire from the wire
spooler to the wireline unit.

Note!
Spooling tension is applicable when spooling wire from the
wireline unit to the wire spooler.

Note!
After use leave the spooling unit connected to the power supply
for at least 15 minutes, this will disperse the accumulated heat in
the electric control box.

WARNING!
Always rope of the area around the spooling and wireline unit.
This secured area should be always be the distance between the
spooler unit and the wire unit to all sides of both units. (This to
ensure that in case of wire failure nobody can get hit by the wire.)

When spooling wire from the spooler to a wireline unit

WARNING!
Never cut wireline under tension. Always first release tension;
after tension release secure both ends and then cut wire.

- Start up both units.

- Turn item A counter clock wise to its minimum position.
- On the remote control put item B on the back tension setting.
- Use the controls in the wire line unit to slowly start to winch in wire.
- When winching in; use the remote control for the spooler to increase the back
tension setting. Experience with the unit will indicate the amount of air pressure
required to generate the required back tension for the wire. When increasing
winch speed the back tension (wire tension) will remain at a relatively constant
value.
- When a sufficient amount of wire in spooled on wire line unit slow down speed
and secure the wire on the drums.

Note!
The back tension between the spooler drum and the capstan
head (motor torque) must be set using the control detailed in
page 17 prior to spooling operations.

Note!
Set the back tension setting valve according to experience. But
take in mind safety and wire strength.

WARNING!
When spooling too fast the spooler unit will give a sound and light
signal. The alarm will be erratic when sometimes the spool speed
limit is exceeded, if the spool speed limit is exceeded during a
longer period the alarm will sound constantly. Remember to
decreased speed slowly and never abruptly.

WARNING!
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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

Where an increase of speed continuous after the alarm has

sounded the unit will go into override and cease to supply
electrical control and the drum will free wheel.

Note!
Where the unit goes into override the control box must be opened
and the “RESET” button pushed.

When spooling wire from the a wireline unit to the spooler

Note!
On the spooler unit the spooler head can be traversed to ensure
even wire spooling. The person needs to wear appropriate work
clothing and personal safety gear. (Coverall, eye protection, safety
helmet, gloves etc)

WARNING!
Never cut wireline under tension. Always first release tension; after
tension release secure both ends and then cuts wire.

OPERATIONS MANUAL

- Start up both units.

- Turn item C counter clock wise to its minimum position.
- On the remote control put item B on the spooling setting.
- Set item C to an appropriate value.
- Use the controls in the wire line unit to start winch out wire. The wire speed
needs to be adapted to the speed setting on the remote control unit.
When a sufficient amount of wire is spooled of wire line unit slow down speed
and secure wire on drums.

Note!
Set the spooling speed setting value according to experience.
But take in mind safety and wire strength.

WARNING!
When spooling too fast the spooler unit will give a sound and
light signal. The alarm will be erratic when sometimes the spool
speed limit is exceeded, if the spool speed limit is exceeded
during a longer period the alarm will sound constantly.
Remember to decreased speed slowly and never abruptly

WARNING!
Where an increase of speed continuous after the alarm has
sounded the unit will go into override and cease to supply
electrical control and the drum will free wheel.

Note!
Where the unit goes into override the control box must be
opened and the “RESET” button pushed.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

Electric controls

WARNING!
When cleaning the unit ensure no water can get into the electric
control box. This will damage the electric equipment and may
require re-programming of the control unit.

All spooling settings are controlled electrically using a programmable control unit. All
electrical functions are factory preset and may not be changed unless with consent of
an ASEP engineer.

Inside the control box the main components are;

ITEM DESCRIPTION

A Behind this cover the resistors are fitted for controlling the electric motor.
When the motor is used as a brake the electrical energy created is stored in
these resistors. In the resistors the electrical energy is transformed to heat
energy which will be released using the airflow created by item B. For this
reason it is important that the fan is working properly when operating the
unit. If the fan is not functioning properly the unit may not be used.
B This fan (as stated at Item A) is required for the cooling of the resistors. If
damaged do not use the unit.
C This pressure regulator is connected to an electric motor and is used to
control the airflow to the air pressured brake. More airflow to the brake will
increase the breaking force and thus create a higher wire tension when
spooling wire.
D These relays are used for controlling the electric components in the unit.
E This programmable control unit controls the unit by collecting data from the
electronic sensors and calculating the appropriate braking strength, electric
motor power output etc.
F This button and switch control the ground safety system. In case of short
circuit this switch will be triggered the system and prevent damage e.g.
dangerous situations. If triggered the system can be reset by switching the
control to the “ON” position. When resetting this safety system ensure the
cause for safety system activation has been cleared.
G This item is the main fuse system for the unit (3 phase + zero). If triggered
the system can be reset by switching the control to the “ON” position. When
resetting this safety system ensure the cause for safety system activation
has been cleared.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

H At item H the maximum spooling torque and back tension torque can be
adjusted. During normal working conditions these settings do not require
changing.

Spooling torque; this controls the air pressure supplied to the brake thus
adjusting the main spooling tension. The back tension function on the
remote control can be set between zero and the maximum value set on this
control. (e.g. when pressure in control box is set to a maximum of 2 bar the
setting on the remote control can not exceed this value and can only be set
from 0 to 2 bar)

Back tension motor torque; this controls the torque applied to the spooler
drum, this should be preset to 50 – 150 kgs to allow a sufficient amount of
back tension to allow the captan head to work and also provide sufficient
amount of torque while spooling off the wire line unit.

Spare; this can be used to replace a failed unit.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

WS-302-F WIRE HANDLING

FAULT AND CAUSE RESULT CORRECTION

Damage to reels: Bending of
the flanges and distortion of Wire snagging during Use slings when handling
the barrel, caused by unwinding. reels or use ramps.
dropping.

Do not drop.
Corrosion in store: Carbon
steel wire is oiled but if Under the worst conditions All types of wire – Store the
stored uncovered, corrosion there will be pitting of the reels upright (on edge) on a
will develop at varying rates surface abd local reduction in level solid base in dry
depending upon the climate. strength. covered conditions. If a
permanent store is not
Alloy steels are for use under
available, support the reels
corrosive conditions but they Slight damage at this stage, off the fround under a
are not completely immune, scarcely visible, may waterproof cover. The latter
and where there are wind increase the risk of alloy wire should be kept out of contact
blown salts slight damage corrosion in service. with the wire, and fastened
may occur. down just clear of the ground
to allow air to circulate and
minimise condensation.
Corrosive in service: There
are inevitable hazards of well There may be development When rewinding the wire,
condition environments. of surface pitting. At worse, wipe off the well
there may be stress contamination. If carbon steel
corrosion or hydrogen wire reels ate to be returned
embrittlemen causing brittle into store, re-oil the wire
failure. during rewind. Do not leave
any wireline downhole during
shutdown.

Wire winding practice:

Wire damage may be caused at various stages in winding onto the service reel from
the supply reel, or in rewind during use. To ensure good spooling, it is recommended
that an itnermediate capstan is used between the supply reel and wireline unit drum
to develop a high line tension without the risk of cutting down. Practises are followed
in the running of wirelines that have to strike a balance between operational
convenience and wire life. To the user some possibilities listed here may seem
unlikely to happen, but they are given so that if any should occur their significance
will not be ignored.
Uneven winding
Variable tension and/or The wire pulls down Maintain a regular traverse
poor control of the wire between adjacent turns of the wire across the full
traversing the barrel. preventing fdree running, width of the barrel to give
causing snags, and uniform build-up of the
possibly the wire breaks. layers. The coarse pitch
and tension in winding
onto the reel will minimise
the risk of the wire pulling
down. (Refer #5 overleaf.)

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

1. Loops, bends
Insufficient braking on the Overrunning with the risk Whatever the method to
supply reel. of snarls forming in looped keep the wire under
wire. Even if the snarl is tension during winding, a
straightened out by hand, brake on the supply reel is
there can be a significant desirable so that too much
reduction in strength. slack wire does not appear
Overrun wire may be between the 2 reels.
pulled over a reel flange
and be sharply bent.

2. Wire abrasion
Rubbing on the ground Reduction in wire strength Keep the tension and
Caused by slack wire. as a result of the loss of always wind from ‘top’ to
the sectional area of steel. ‘top’ of the reels. In
service, rewind on top of
the reel.

Rubbing on the reel side, Reduction in sectional Angle of the wire during
caused by incorrect area. traverse and total traverse
traversing. must be controlled.
3. ‘Wild’ wire
Cause by slack winding or The wire may be difficult to Always wind the wire in
reversing the natural control and lead to tangles the direction of its batural
curvature of the wire. and snagging. curvaure. Never wind from
the top of one reel to the
underside of the other.
4. Wire indentation
Caused by ‘crosscutting’ Reduction in strength. Avoid excessive tension in
between adjacent layers of winding and excessive
wire. jarring’ when operating
downhole tools.
5. Friction on pulleys
Possible during ‘jarring’. Embrittlement of wire Avoid excessive ‘jarring’
surface. Cutting back the wire
between uses minimises
Shock loads can produce the chance of cumulative
high surges out of all damage.
proportion to the assumed
loads on the wire, and
may cause failure.
6. Fatigue cracks
Caused by repeated Wire failure, particularly if Ratio of the pulley and
bending under high stress. other factors, noted above, wire diameters should be
are contributing. 120.1 to reduce the
significance of bending
stresses.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

WS-302-G TORSION TESTING OF WIRE

The Torsion, or Twist, Test is a valuable method of determining the condition of the
line. Carbon steel lines should reach the number of complete turns in the chart below
before failing.

Note: Stainless steel alloys have a very low resistance to twist testing, and therefore
this test cannot be applied to stainless alloys as it has no bearing on their
remaining life.

This test can also be applied in the field by gripping a sample of line in a vice and,
leaving 8" free, form a handle `grip' to twist the line and count the number of complete
turns.

Reference Table for IPS line

Based on 8” sample length between locking screws.

Line Diameter (in) 0.092” 0.108” 0.125”
Min. Breaking (lbs) 1547 2108 2823
Min. no of turns to break 23 19 17

Visual inspection of the break will provide additional

information as to the condition of the line.

GRADE 1 FRACTURES without Secondary Breaks

The torsioned test piece should show no evidence of spiral splitting along its length and
should contain a single, ductile, primary fracture which is perfectly square ended.

A wireline exhibiting this type of fracture characteristic would be considered of suitable

quality for further use, unless the number of twists to failure are very low (e.g. 30% of
the API 9A value) the line should be discarded.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

GRADE 1 FRACTURES with Secondary Breaks

It is possible, during torsion testing of wireline exhibiting exceptionally high tensile

strength values, to experience secondary wire breaks which feature stepped or helical
fracture faces. These breaks are recoil fractures, and are induced by the instantaneous
release of stored energy in the wire when the primary fracture occurs. Although such
breaks indicate a marginal reduction in wireline ductility, their presence can be
discounted. The wire quality being dictated by the characteristic of the primary fracture.

GRADE 2 FRACTURES

The torsioned test piece may show evidence of waviness and the presence of slight
splitting along its length. The primary fracture, whilst preferably square ended, may be
slightly stepped. Secondary recoil fractures may be present. This type of primary
fracture is acceptable, but is usually associated with a reduced number of twists to
failure indicating a reduction in wireline ductility. A wireline exhibiting such fracture
characteristics would generally be considered suitable for limited further service
provided the number of twists to failure exceeded say 60% of the API 9A value, and
provided ductility tests were carried out after each operation.

GRADE 3 FRACTURES

The torsion test piece may show evidence of uneven localised twisting. Spiral splitting
and waviness is invariably present, and the primary fracture will exhibit severely
stepped or helical fracture faces. Secondary, recoil fractures are uncommon. This type
of failure is unacceptable and is usually associated with a low number of twists to
failure. A wireline exhibiting such torsional characteristics should be discarded
immediately.

It is a good work practice to cut and discard 15 m of wireline each time a new knot is
made.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

WS-302-H TENSILE TESTING OF WIRE

A sample of wireline cut from the end of the line should be tensile tested at periodic
intervals. The testing frequency will vary with local conditions - work load applied to the
line, well fluids, location (sand or salt water), line material etc. The objective is to
identify potentially weak or damaged line before it breaks in the well.

Several types of tensile testers are available and they can be manually operated or
hydraulic, as per the schematic shown below. They hold a length of the line sample to
be tested between a fixed and movable point. As the distance between the points is
increased, tension is applied to the line until the Ultimate Tensile Stress (UTS) is
reached and the line parts. A display device such as a dial or an electronic strain
gauge, displays the force at which the sample failed.

This value, should be similar to the specifications for that particular size and type of
line.

Hydraulic Cylinder

Electronic Load Cell

Rope Socket

Wire under test

12” minimum length

Rope Socket

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

WS-302-I FORCE VERSUS LINE SIZE

WS-302-J PORTABLE WELL – CONTROL PANELS, HASKEL, MO AND SSR

PUMPS

A Surface Control Panel is used to supply the pressure to the control needed to keep
the downhole safety valves open.

These self-contained units provide a high pressure oil output from a low pressure air or
gas input. Through the use of various sensing devices (such as pilots and erosion
monitors) the input pressure to the safety valve is blocked, and the control line
pressure bled off allowing the downhole valve to shut.

The major components are as follows:

Sigma Valve

Senses a pressure drop in the pilot line when an abnormal pressure or condition
causes the pilot to vent the pilot line pressure. This causes the Sigma valve to close,
blocking incoming air pressure and bleeding pressure from the top of the D' valve.

To reset, the Sigma valve must be physically held open until input air has passed
through the small port to reach at least 30 psi in the pilot line.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

'D' Valve

When air pressure above the diaphragm is bled off by the Sigma valve, the spring
moves the piston upwards. This blocks incoming hydraulic pressure, and bleeds the
pressure from the control line back to the reservoir. The downhole valve then closes.

Haskel Pump

Converts input air pressure to hydraulic pressure. Air acting on the large area of the
piston is converted to high pressure oil (low volume) by the small area of the hydraulic
piston. This pump can operate under `stalled' conditions indefinitely, and pump when
required.

Regulators

Used to adjust the pilot line pressure and pump input (direct ratio to output oil
pressure).

Portable Panels

Portable units, similar to the one shown here, are used on some locations by the
wireline crew to `take control' of the well safety systems during wireline operations to
prevent automatic shut-in of the well from the central panel system.

It is essential that the wells be returned to their normal safety mode before the well is
returned to production.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

PORTABLE HASKEL PUMP UNIT

The MO air driven hydraulic pump is used to replace the existing station hydraulic
unit i.e. Control O Matic (COM) and Autocon units during wireline activities. The idea is
to prevent the wire from damage or cut which is normally occurred during the plant is in
abnormal situation such station shutdown. The MO pump should be connected to the
SCSSSV tree control line during rigging up the lubricator assembly.

The MO pump is driven by air to drive the hydraulic pump and the'air source is supplied
from the K-winch power pack. The air supply is just enough to open and maintain the
pressure on the down hole safety valves with the MO pump. The unit is not designed
as a volume of pump for pumping a large quantities of oil as the oil tank is limited to 6.5
litre. The unit cannot withstand an GLV input pressure of 6000 kPa therefore there will
be an air connection to fit the K-winch power pack only. The pump is fitted with a check
valve. All gauges and valves are protected by a stainless steel cover.

CAUTION : MO pump and K-winch cannot be operated together. When the MO

pump is stroking the air pressure drops forcing the drum brake on the
Kwinch to be applied.

MO Pump procedure to override control panel pressure to SC-SSSV for wireline

operations.
1. Check hydraulic oil level in tank.
2. Turn air regulator to zero.
3. Close relief valve and isolation valve on pump unit
4. Close SCSSSV control line isolation valve on wellhead and control panel.
5. Connect air hose from powerpack to pump and HP hydraulic hose from pump to
disconnected control line at well head isolation valve.
6. Open isolation valve on pump.
7. Open air regulator and adjust hydraulic output pressure to required control line
pressure i.e. 300 bar.
8. Open isolation SCSSSV valve on wellhead, control line pressure should remain
at 300 bar.
9. After completion of wireline operations, close SCSSSV isolation valve on
wellhead.
10. Open relief valve on pump unit to bleed off pressure.
11. Disconnect HP hydraulic hose from isolation valve on wellhead and close
isolation valve on pump unit.
12. Connect control line from platform control panel to SC-SSSV isolation valve on
wellhead.
13. Open platform control panel SCSSSV supply valve.
14. Open SCSSSV isolation valve on wellhead.

MO Pump Operational Procedure for SCSSSV change out.

To pull the SC-SSSV.

Repeat steps 1 thru 8 as above

9. Latch the SCSSSV.

10. Close air regulator.
11. Open relief valve and bleed down controlline pressure to THP, close relief valve.
12. Close SCSSSV isolation valve on wellhead.
13. Open relief valve bleed down to 0 bar, close relief valve.
14. Pull SCSSSV.
15. Run SCSSSV to 10m above SCSSSV nipple.
16. Open air regulator and adjust to required control line pressure i.e. 300 bar.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

To set the SCSSSV.

17. Open SCSSSV isolation valve on wellhead and flush control line for 3 min.
18. Close SCSSSV isolation valve on wellhead , pump pressure to remain at 300 bar.
19. Set SCSSSV.
20. Open SCSSSV isolation valve and keep pumping till control line pressure is at
300 bar and pump stops pumping.
21. Repeat steps 9 thru 14 as on page 1.

PORTABLE MO PUMP UNIT

The operation of the SSR portable Control Unit is Identical to the Haskel and MO
pump.

The pump is air operated and hydraulic pressure output is adjusted with the air
regulator.

Hydraulic pressure can be bled off by opening the dump valve, which allows the fluid to
be returned to the tank.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

PORTABLE SSR PUMP UNIT

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

WS-302-K SSR TRIPLEX PUMPING UNIT, HP - 0017

SSR MODEL HPA 0017

SPECIFICATIONS

HIGH OUTPUT CHEMICAL INJECTION PUMPING UNIT, HYDRAULICALLY DRIVEN

VIA A 3 SPEED TRANSMISSION AND CHAIN DRIVE TO A TRIPLEX PISTON
DISPLACEMENT PUMP. A LARGE STAINLESS STEEL RESERVOIR IS PROVIDED
WITH PROVISION ALSO FOR AN ALTERNATIVE FLUID SUPPLY. THIS ALL
ENCASED IN AN HEAVY DUTY BOX SECTION STEEL STRUCTURE, FITTED WITH
OFFCON TYPE LIFTING EYES.

DIMENSIONS:
LENGTH : 42"
WIDTH : 42"
HEIGHT : 68"

TARE WEIGHT

APPROXIMATELY 1 TON

CAPACITY

10.2 US GALLONS PER MINUTE AT 7,000 PSI

HYDRAULIC REQUIREMENTS

42 GALLON IMP PER MINUTE AT 2,200 PSI

SSR TRIPLEX PUMP (HIGH VOLUME 10,000psi)

Operating instructions

1. Fill the tank with required fluid

2. Open the pressure bleed valve and connect hydraulic hoses
3. Start the power pack keeping the engine revs low
4. Sellect a gear (1,2 or 3) then increase power pack revs
5. Close the pressure bleed valve
6. To pressure up,screw in the pressure supply valve .When at required pressure,
lock in the pressure at the manifold at the pressure out put
7. After use (if saIt water was used) drain the tank and flush the system with oil.

Note: DO NOT exceed 10,000 psi and keep the manifold with the pump.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

PARTS LIST
FOR TRIPLEX PUMP UNIT
DRG 3920

TYPE HPA 0017

ITEM DESCRIPTION QTY PART No DRG No

1. MAIN FRAME 1 HPF 0023 3909

2. TANK 1 HPF 0021 4004
3. GEARBOX MOUNTING BRACKET 1 HPF 0009 3959
4. FRONT COVER 1 HPF 0028 4009
5. HOSE TRAY 1 HPF 0024 5402
6. CHAIN GUARD (TOP) 1 HPF 0025 4005
7. SIDE COVER 1 HPF 0026 4007
8. INSTRUMENT PANEL 1 HPF 0027 4011
9. JOCKEY SPROCKET ASSEMBLY 1 MAC 0001 1995
10. TRIPLEX PUMP CHAIN WHEEL 1 MCD 0090 3934
11. GEARBOX SPROCKET 1 MCD 0041 3933
12. OUTRIGGER SHAFT 1 HPM 0001 3988
13. BEARING 1 MBB 0091 -
14. GEARBOX 1 MAG 0013 -
15.* HYDRAULIC KIT 1 HPL 0021 5401

* ITEM NOT SHOWN ON DRAWING.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

PARTS LIST
HYDRAULIC KIT FOR
TRIPLEX PUMP UNIT

TYPE HPL 0021

ITEM DESCRIPTION QTY PART No DRG No

1) TRIPLEX PUMP 1 HAP 0033 -
2) HYDRAULIC MOTOR 1 HAM 0004 -
3) HYDRAULIC RELIEF VALVE 1 HIV 1023 -
4) HYDRAULIC RELIEF VALVE PANEL MOUNTED 1 HIV 1015 -
5) HIGH PRESSURE RELIEF VALVE 1 HCV 6012
6) Y STRAINER 1 HAF 0057
7) BALL VALVE 1 HIV 3004
8) FILLER BREATHER CAP 1 HGG 3001
9) LEVEL INDICATOR 2 HGG 2006
10) 0-4000 PRESSURE GAUGE 1 HGG 1018
11) 0-15,000 PRESSURE GAUGE 1 HGG 1051

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

KERR TROUBLESHOOTER GUIDE

REASON OR SERVICE NEEDED

Unusual pounding, knocking broken Insufficient fluid at high speed. Check to
valve springs see if the suction line is the proper size
and is not constricted, trash in line, valve
partly opened, etc.
There is also a possibility of gas in the
fluid causing the roughness.

Loss of pressure or volume Also above. Foreign matter may be

holding valves open. Worn valves.
Broken springs.

Consistent, rhythmic knock Improper bearing adjustment. Worn

bearings or connecting rods.

NOTE: Valve noise is common and

normal in high speed pumps. It should
not cause concern unless if becomes
erratic.

Packing failure (Excessive) Improper installation. Improper type

lubrication. Incorrect type packing for
particular installation.
(Contact Kerr if in doubt) Excessively
worn plungers.

Abnormal wear of fluid end parts Abrasive or corrosive fluid.

Abnormal wear of power end parts Lack of oil, overload on pump, foreign
matter in oil.

Heat in power end A new pump will run hot for a short
period (2 or 3 days). Check above for
persistent heating. Pump will operate
near 140° F. under average conditions
check for air in pump by bleeding at
cover caps. Too much spring tension
Reciprocating pumps have very limited
pick up, check installation section.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

WS-302-L ELMAR TEST BENCH 15,000 PSI, L-69039

GENERAL

The Elmar Services A.P.I. Test Bench L-69039 is designed to carry out testing of
sub-surface safety valves in accordance with A.P.I. procedures. It is a fully enclosed
unit for use in a workshop. It provides hydraulic control (10,000 psi), pressure testing
(15,000 psi) and gas testing (8,000 psi) functions. Any leakage of a SCSSV during
testing may be monitored using the unit.

FEATURES AND SPECIFICATIONS

- 10,000 psi radial piston hydraulic pump powered by an electric motor.

- 15,000 psi air driven water pump.
- 25:1 ratio gas booster gives gas pressures up to 9,000 psi.
6" diameter test gauges for all 3 systems. (±0.5% FSD accuracy)
- Digital readout for hydraulic and lower end pressures. (±0.2% FSD accuracy)
- 3 channel panel mounted electronic chart recorder.
- Gas flowmeter for checking leakage.
- A11 controls are mounted on an easily readable mimic control panel.
- Stainless steel components used extensively throughout.

SAFETY

SAFETY IS EVERYONE'S RESPONSIBILITY

CAUTION

- READ SERVICE MANUAL BEFORE OPERATING

- OBSERVE ALL SAFETY PRECAUTIONS
- THIS SYSTEM IS CAPABLE OF PRODUCING HIGH PRESSURE
- TO AVOID COMPONENT RUPTURE AND POSSIBLE INJURY REGULATE
INLET AIR PRESSURE SO OUTLET PRESSURE DOES NOT EXCEED THE
MAXIMUM WORKING PRESSURE OF ANY COMPONENT IN THE SET-UP
- CHECK PRESSURE RATING AID COMPATABILITY OF ALL CONNECTIONS
- CLEAR AREA OF UNNECESSARY PERSONNEL
- SELECT PROPER EQUIPMENT
- MAKE SURE VALVES AND REGULATORS ARE IN CORRECT POSITION
- DO NOT TRY TO TIGHTEN OR LOOSEN CONNECTIONS UNDER
PRESSURE
- DO NOT WELD, FILE OR USE METAL STAMPS ON THE PRESSURE
EQUIPMENT – THESE CAN START CRACKS
- DO NOT OVERTIGHTEN ANY VALVES
- DO NOT ATTACH ANYTHING TO THIS EQUIPMENT UNLESS YOU ARE
SURE OF ITS PRESSURE RATING
- WATCH FOR TRAPPED PRESSURE. BLEED OFF FULLY BEFORE
BREAKING DOWN UNIONS ETC.

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

ELMAR SERVICES LTD ABERDEEN

Assy. No. ASSEMBLY LIST s/o 6037 Drawing No. L-
69039
ITEM DWG. NO. DESCRIPTION - 15K API TEST BENCH QUANTITY UM GENERAL NOTES
1 86396 Control Panel Assy. 1 ea
2 86397 Water Filter Assy. 1 ea
3 86398 Airline Filtrer Assy. 1 ea
4 86399 Hydraulic Pump Assy. 1 ea
5 86400 Gas booster Assy. 1 ea
6 86401 Manifold – Hydraulic 1 ea
7 86402 Water Pump Relief Valve Assy. 1 ea
8 86403 Bulkhead Connections 1 ea
9 86404 Manifold – Lower End 1 ea
10 86405 Manifold – Upper Eng 1 ea
11 86406 Water Pump Assy. 1 ea
12 86407 Frame / Covers 1 ea

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BSP Well Engineering Manual Volume 3 Wireline, Standards & Procedures

A.P.I. SPECIFICATION

The following operating procedures should be read in conjunction with the American
Petroleum Institute Specification 14A. The unit is primarily designed to carry out
functional testing of hydraulically actuated SCSSV's (i.e. Appendix C of spec. 14A) This
lists the actual procedure to be followed while testing SCSSV's. The unit exceeds the
minimum test facilities specified in exhibit C1.1

GENERAL CHECK BEFORE OPERATION

After the test lines (hydraulic, upper and lower) have been connected to the SCSSV the
following should be checked:
- Hydraulic oil tank full. (Small orange plug beside hydraulic ' pump electric motor)
Airline filter should be drained. (LES cupboard)
- Leakage test containers should be empty and in position. (Top shelve of RHS
cupboard)
- All panel air valves in OFF position.
- The nitrogen supply/air supply pressures. The nitrogen bottles may require
changing.
- The power supply to the unit should be switched ON, as should
the transducer power supply. (Switch below chart recorder)

HYDRAULIC SYSTEM

NOTE: Before operating the hydraulic system ensure that the hydraulic pressure
dump/leakage test valve is in the horizontal position. Never leave in the
vertical position or operate valve with pressure on the line.

(a) Pressure Test

The hydraulic pump/system may be checked as follows:
- Blank off the end of the hydraulic line with a suitable 10,000 psi rated
fitting. Ensure that no air is trapped in the line.
- Close the hydraulic bleed valve.
- Switch the hydraulic pump ON.
- Adjust the pressure relief valve until 8,000 psi is reached. (8,300 psi
-pump internal relief valve opens)
- Adjust the pressure regulator until 8,000 psi reads on the digital counter.
The large 6" pressure gauge and the chart recorder should match these
figures.
- Check system for any leaks.
- Release pressure by opening the hydraulic bleed valve/bleed adjust
valve.
- Reset relief valve to required pressure.
- Turn hydraulic regulator fully anti-clockwise.
- Switch hydraulic pump OFF.

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(b) Operation
With the hydraulic line connected to the SCSSV
- Switch the hydraulic pump ON.
- Increase hydraulic pressure by turning regulator clockwise.
- With pump OFF, release pressure by opening the hydraulic bleed valve. The
pressure may be controlled by using the bleed adjust valve.
- The hydraulic dump/external drain valve should normally be positioned to the
hydraulic dump side. The external drain is connected to the measuring
container in the RHS cupboard. This allows any leakage down the hydraulic line
to be monitored.

N.B. The pump should be switched OFF when not in use. This will avoid overheating
the oil as it passes through the relief valve.

PRESSURE TEST SYSTEM

a) Pressure Test

The water pump/system may be checked as follows:

- Blank off both the upper and lower end test line with a suitable 20,000 psi rated
fitting (a A.E.S.L.) Ensure that no air is trapped in either line.
- Close the lower bleed, upper bleed, flowmeter and upper end leakage test
valves.
- Open the balance valve.
- Open the water supply valve to the pump.
- Turn water pump air valve ON.
- Turn air regulator clockwise until 15,000 psi reads on the digital counter. The
large 6" pressure gauges and the chart recorder should match these figures.
- Check system for leaks.
- Turn air valve OFF.
- Turn water supply valve OFF.
- Release pressure by opening either the upper or lower bleed valve.
- Turn air regulator fully anticlockwise.

b) Operation

With the upper/lower end hoses connected to the SCSSV

- Turn water supply valve ON.
- Turn air supply valve ON.
- Set pressure by turning the air regulator clockwise.
- The balance valve will isolate the upper and lower parts of the SCSSV.
- With water supply/air supply valves turned OFF release the pressure by
opening the relevant upper/lower bleed valve.
- While testing the lower end the upper end may be monitored for leakage by
opening the leakage test valve. A measuring container inside the cupboard
gives the leakage flow.

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GAS SYSTEM

(a) Pressure Test

By using a fully charged nitrogen bottle connected to the unit the gas system may
be checked as follows:
- Blank off both the upper and lower end test lines with a suitable 20,000 psi
rated fitting. (As for 3.4)
- Close the lower bleed, upper bleed, flowmeter and upper end leakage test
valves.
- Open the balance valve.
- Turn gas booster air valve ON.
- Turn air regulator fully clockwise. Open gas supply valve.
- Turn maximum gas pressure regulator clockwise until pressure reads 8,000 psi.
- Turn air valve OFF.
- Release pressure by opening either a bleed valve or the flowmeter valve.
- Reset maximum pressure regulator.
- Turn air regulator fully anticlockwise.

(b) Operation

For gas test pressures less than the nitrogen supply pressure the gas booster is
not required. For higher system pressures or low supply pressures the gas
booster may be used.

- Turn air valve ON.

- Increase gas pressure by turning air regulator clockwise. Open gas supply
valve.
- Gas leakage from the upper end may be monitored through the flowmeter.
- To release the pressure close the air supply valve and open the upper/lower
bleed valve.
- Turn air regulator fully anticlockwise.

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CHAPTER 3
SURFACE EQUIPMENT
TABLE OF CONTENTS

WS-303-A SURFACE EQUIPMENT OVERVIEW ........................................................2

WS-303-B STUFFING BOX ............................................................................................3
WS-303-C LUBRICATOR SECTIONS ...........................................................................6
WS-303-D BLOW-OUT PREVENTORS.........................................................................9
WS-303-E X’MAS TREE CAPS & WELLHEAD CONNECTIONS ............................15
WS-303-F SURFACE EQUIPMENT ACCESSORIES..................................................18
WS-303-G QUICK UNIONS ..........................................................................................20
WS-303-H O-RINGS ......................................................................................................23
WS-303-I MARTIN DECKER WEIGHT INDICATOR ................................................24
WS-303-J WIRELINE SHEAVES ..................................................................................26
WS-303-K WIRE CLAMP ..............................................................................................28
WS-303-L LIFTING CLAMP & SHACKLE .................................................................29
WS-303-M BLOCK & TACKLE....................................................................................31

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WS-303-A SURFACE EQUIPMENT OVERVIEW

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WS-303-B STUFFING BOX

General Information
Correct sealing of the wireline is a critical part of wireline operations. The choice of
sealing device is determined by the type of wire and well pressure / fluid, but will be
one of the following:

➢ Stuffing Box - All sizes of slickline.

➢ Swabbing Head - Braided line (for a partial seal during applications such as
swabbing).
➢ Grease Injection Head - Braided line high pressure seal.

This section deals with the stuffing box used for slickline applications. The braided line
options will be covered later in this section.

Design Features
The essential function of the wireline stuffing box is to ensure sealing off around
moving or stationary solid wireline at the upper end of the lubricator during wireline
operations. The packing nut is adjustable and can be rotated clockwise (to the right /
clockwise) to increase the compression force on the packing rubbers as they wear. A
swivel mounted (360° free movement) sheave wheel and guard are fitted to the top of
the stuffing box. The standard stuffing box is rated for 5,000 psi, but they are available
in 10,000 psi and higher pressure ratings if required.

Size Variations
The line size determines the size of the "upper gland" (2), "lower gland" (4), and
sheave diameter. For 0.092" line the sheave diameter is 10", and 15" for 0.108" line.
For other line sizes check the "Wireline Section" of this manual, or with your line
supplier. If the line diameter is to be changed, the above components also have to be
exchanged.

Broken Line
Most stuffing boxes contain a BOP plunger which seals off flow in the event that the
wireline breaks. Well pressure acting on the cross-sectional area of the wire forces the
wire out when the line weight is less than the upward force. The flow causes the BOP
to rise, and the rubber on the upper end deforms to seal off the well until the BOP /
swab valve can be closed.

Surface Line Break

The natural curling tendency of the wire forms loops as the tension is removed when
the line breaks. The sheave guard on the stuffing box is designed to trap wire, which
breaks on the surface before it drops downhole.

Injection Port
Some styles of stuffing boxes have an injection port which can be used for the
following:
➢ Injection of glycol or similar antifreeze in low temperature environments, or when
working on high pressure gas wells where freezing may be a problem.
➢ Injection of an inhibitor to protect the line in corrosive well conditions, such as
H2S.

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➢ Bleed off pressure to activate the BOP plunger if the packings have to be
changed under pressure. It is usually sufficient to split one packing laterally and
add it to the existing packings. Re-apply force with the packing nut to achieve a
seal to retrieve wire and tools out of the hole, then replace the packings
completely. (Refer to the procedures in this section.)

Hydraulic Packing Nut

The use of a remote hydraulic pressure activated packing nut enables the adjustment
of force on the packings from a safe distance. This feature is particularly useful when:

➢ The stuffing box cannot be easily reached during wireline operations.

➢ On high pressure wells when close proximity to a pressurised stuffing box is not
advisable.
➢ On wells containing dangerous levels of H2S.

Important: You must use H2S rated equipment on wells containing H2S in
concentrations above the recommended pressure / % combination. (Refer
to the " H2S Section" of this manual.)

Stuffing Box Checks

Before use, the following checks should be carried out:

➢ Check the packings are not worn out. If the packing nut is near the lower end of
its movement, there may not be sufficient movement remaining to increase the
packing compression force to maintain a seal during wireline operations.
➢ Check the sheave is the correct size for the line in use (10" for 0.092", or 15" for
0.108").
➢ Check the upper and lower brass packing glands for wear. If they are worn
oversize they should be replaced, as worn glands allow the wire to cut the
packings faster.
➢ Check the sheave bearings for free spinning, and replace the bearings if
necessary.
➢ Check the sheave bearings for side play, and replace if the side play is
excessive. The sheave should not touch the sides of the support arms. Excessive
side play also leads to a worn upper gland and subsequent reduction in packing
life.
➢ Check the alloy side arms for damage from side play in the sheave wheel. The
complete sheave staff should be replaced if cutting / wearing action has occurred
on the inside of these arms.
➢ Check the sheave staff for freedom of swivel movement. It is essential that the
sheave follow the wire direction during rig-up or the wire can jump out of the
groove and become damaged.
➢ Check the sheave guard is tight and adjusted close to the sheave to ensure it will
trap the line in the event of a line break.
➢ Check the BOP plunger for wear and freedom of vertical movement.

In Use
The life of the packings can be extended by keeping the line oiled while running into
the well.

The choice of packings is also important. Packings are available in hard, soft, cloth
filled, and polyurethane. Check with your supplier for the appropriate material for your
field conditions.

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Changing Packings
Remove the "packing nut" (1) and "upper gland" (2). Remove the packings with a
`packing hook'. New packings should be reamed on a piece of wire of the diameter to
be used, and roughened up with cutter pliers to form a `file'. Insert this wire through the
lower packing gland and push each new piece of packing into position with a piece of
II/16" brass shear stock. Replace the upper packing gland and packing nut. The wire
can be removed or remain in place during transportation.

WIRELINE STUFFING BOX

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HYDRAULIC PACKING NUT

WS-303-C LUBRICATOR SECTIONS

The Lubricator enables wireline toolstring and equipment to be inserted and removed
from a well under pressure. It is a tube with quick connections at each end. The quick
connections are welded in position, x-rayed, and pressure tested prior to use. All
lubricators should be x-rayed, magnifluxed for cracks, and visually inspected at regular
intervals. The usual period of these inspections is annually.

The pressure ratings of the lubricator are:

Working Pressure (WP) psi* Test Pressure (TP) psi

3,000 4,500
5,000 7,500
10,000 15,000
* Sometimes expressed as CWP (Cold Working Pressure).

Note : H2S equipment must be used on wells containing H2S.

The actual threshold valves are dependent on pressure and % H 2S. Please refer to the
appropriate NACE and / or API charts to verify usage. The standard length of the
lubricator is 8 feet, but shorter sections are available (4 to 5 feet).

The lower section must be of sufficient diameter to accommodate tools / equipment

being run (usually the same size as the tubing and wellhead). The lower section has a
bleed off valve to vent pressure and / or gauge point.

Upper sections are smaller as only the toolstring is inside.

The total length must be sufficient to take the total toolstring plus the tools being
recovered.

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The maximum length recommended to be picked up with rope blocks on ginpoles are:

(i) 3 sections - if the lower section does not exceed 4'/2".

(ii) 2 sections - if both sections are 4 '/2".

If the diameters exceed these sizes, a crane must be used.

Sizes are 2" 2 '/ " 3 '/ " 4 '/ " 5 '/2" and 7".

Wire Tracking
Caused by wire cutting into the inside wall of the lubricator. This can drastically reduce
the strength of the lubricator and should be checked by visual inspection regularly.

Color Coding System of Lubricator Components Description Pressure

Rating Colour Code (BSP)

DESCRIPTION PRESSURE RATING COLOR CODE (BSP)

Lubricator 10,000 psi (69,000 kPa) Orange

Lubricator 5,000 psi (34,000 kPa) *
Blowout Preventer 10,000 psi (69,000 kPa) Orange
Blowout Preventer 5,000 psi (34,000 kPa) Grey
Blowout Preventer 3/16 5,000 psi (34,000 kPa) Green
Blowout Preventer 1/4 5,000 psi (34,000 kPa) Red
Stuffing Box 10,000 psi (69,000 kPa) Red
Stuffing Box 5,000 psi (34,000 kPa) Red

*To identify each section of lubricator in a set, identical color codes areal located to
each section.

Care/Handling/Transportation of Lubricator
Care in Handling
When removing the wellhead adaptor, BOP, lubricator sections and stuffing box from
the tray, take care not to hit exposed threads of the female quick unions. Do not set the
exposed threads in dirt, sand or anything else that can wedge into the threads. Coat
ORings with light oil or grease before joining union halves together. Assemble the
lubricator close to the base of the X'mas tree.

Use of the lubricator assembly stand is recommended for keeping the threads out of
any contamination and for facilitating assembly.

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TYPICAL LUBRICATOR SECTIONS

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WS-303-D BLOW-OUT PREVENTORS

A wireline BOP (also known as a wireline valve) is installed between the tree
connection and lower lubricator section.* Under normal working circumstances it is not
actually used, but it cannot be installed later with wire in the hole and pressure in the
lubricator. It must be included in all rig-ups.

* The only exceptions to the BOP being next to the tree connection are:

(i) When installing / retrieving BPV's (Back Pressure Valves) and there is a
possibility of the toolstring remaining across the Xmas tree valves, the BOP's can
then be mounted above the lower lubricator section. Check that this provides
sufficient length to close the rams on the wire, i.e. above the rope socket.

(ii) When running /pulling an SCSSV or a wireline retrievable BPV the BOP can be
positioned above the first section of the lubricator. Alternatively, a second BOP
can be placed immediately below the stuffing box. This provides a means of
isolating the well pressure and recovering the tools if the wire breaks at the rope
socket and the tools drop across the Xmas tree valves.

Purpose
➢ To enable the well pressure to be isolated without cutting the wire by closing the
master valve.
➢ To permit the assembly of the wireline cutter above the BOP rams.
➢ To permit the dropping of a wireline cutter if the toolstring becomes stuck in the
well.
➢ To permit `stripping' of the wire through closed rams, only when necessary.

Description
Mechanical and / or hydraulic force is applied to close the rams which seal against the
wire.

Ram Types
➢ Slickline (.092", .105" / .108") use blind rams with rubber inserts on the sealing
faces to seal with or without wire across the rams.
➢ Braided line 3/16",1/4" or conductor cable) use rams with a semicircular groove
in the seals to match the line diameter.

All of the above types of rams have centralisers to ensure the wire is positioned
centrally on the sealing face as the rams close.

Caution : BOP's will only hold pressure from one direction.

Check visually with the rams open by looking down past the rams for the key way slot
on the pressure (bottom) side of the body. Any wording on the body casing should also
be the correct way up. Some brands have an arrow to indicate the top.

BOP's are available with manual or hydraulic operation, and are used in the following
configurations:

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Single
Installed between the tree connection and lower lubricator.

Dual
Double or twin ram BOP's are primarily used with braided line. Usually hydraulic, it is
generally a single casing containing 2 pairs of rams. 2 single BOP's can be used one
above the other, but this configuration is not as convenient as a one piece unit. To
obtain a seal against braided line, a grease injection point is provided between the 2
sets of rams.

Multiple
For high pressure gas wells, a third BOP is advisable. The lowest set of rams are
installed upside down so that they will hold pressure from above. Grease injected
above these rams will be contained and form an efficient seal.

Procedures For Use

Equalising All BOP's have a means of equalising the pressure below the closed
rams with the pressure above. A pressure differential acting on the
cross-section of the rams creates a force that makes opening the
rams extremely difficult. Attempting to open the rams without equalising
may result in internal damage.

Always check that the equalising assembly is correctly* installed. The

allen screw should be on the high pressure side of the rams, i.e.
downwards.

➢ Some older designs allowed the equalising assembly to be

installed upside down, which could prevent equalisingand cause
the BOP to be inverted.

Keep the equalising valve closed so that in an emergency the BOP

will hold pressure as soon as the rams are closed. If this valve is in the
`open' position, it will have to be closed manually before the well
pressure will be contained. The additional time required may be critical
in an emergency.

Remember the BOP is a safety device for use in an emergency, and it

is the responsibility of the operator to ensure that it is in perfect working
order at all times.

Testing All types of BOP's should be tested in the workshop on a regular basis to
be determined to suit field conditions.
With the rams open - Pressure to 150% of the working pressure.
With the rams closed - Pressure to 100% of the working pressure to
test the ram seal against the wire diameter. A test rod* of the same size
as the wire to be used should be inserted between the rams.
* Caution : Ensure the rod has an enlarged diameter below the ram
to prevent it being blown out during testing.

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Remember The force created by pressure acting on the cross-sectional area of the
test rod will act to push the rod out of the rams. For this reason, it is not
recommended to use a locally made device unless it has been subjected
to recognised welding certification. To assist in monitoring test
frequency, the date and test pressure can be recorded on a stainless
steel banding strap above the connection. In addition to these tests, it is
recommended that the BOP be tested against the well pressure during
each rig-up.

Transportation Prior to removing the BOP from the wellhead, it is strongly

recommended that the rams be closed and the handles be removed.
This will prevent accidental bending of the threaded stems and will
protect the threads from corrosion.

Carried in this manner, the BOP is ready for testing during the next
rig-up and it also confirms that the rams will move correctly.

Maintenance All BOP's need careful and regular maintenance to ensure they are
ready to seal in an emergency. Refer to individual manufacturer's
instructions.

Special Designs New hydraulic BOP's are supplied fitted with `gas vented
hydraulic cylinders'. A small hole in the adapter cylinder, (refer to the
diagram) close to the BOP body, prevents gas from passing the O-ring
seal on the stem. Any gas reaching the hydraulic cylinder can cause the
following problems:

(i) Gas mixes with hydraulic fluid which can pressurise the hose and
pump above their rated pressure.

(ii) Gas can cause the hydraulic fluid to expand and cause the rams to
open.

Summary
Remember that a BOP:

1. Will hold pressure from one direction only.

2. Requires regular testing.
3. Should be carefully maintained.
4. Should be transported with the rams closed.
5. Hydraulic actuated versions can be manually closed, but hydraulic oil must be
allowed to vent from the piston chamber.

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[1]

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BOWEN B.O.P. – RAM DETAIL

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WS-303-E X’MAS TREE CAPS & WELLHEAD CONNECTIONS

Tree Connections are required as a `crossover' between the Xmas tree and quick
connection pin on the lower side of the BOP.

There are a significant number of different designs required to match the various trees
available, however the main types only are shown here:

➢ Threaded - No longer recommended as safe.

➢ Unibolt.
➢ Quick union.
➢ Hammer union.

General Description and Specifications

Wellhead connection is actually a cross over connection. The bottom connection will be
a flange machined to API specifications. The top connections can be a variety of
female quick unions, or hammer unions.The flange can be either a single or a dual
type. The single will be round while the dual will be segmented flange.

When there is no wireline work being done on the wells they are protected by a
blanking cap. The blanking caps are drilled through the center and tapped with a 1/2"
(13 mm) NPT box. A bleed off valve is normally screwed in with a pressure gauge
screwed into it.

Pressure Rating
The wellhead connections used by this group comply with API standards.

Pressure ratings are:

Working Pressure Test Pressure
3,000 psi (21,000 kPa) 4,500 psi (31,000 kPa)
5,000 psi (34,000 kPa) 7,500 psi (52,000 kPa)
10,000 psi (69,000 kPa) 15,000 psi (103, 000 kPa)

X'mas Tree Caps

The X'mas tree caps can be a blank flange or a quick union, unibolt or a hammer type
union. They serve a three-fold purpose:
1. They are protectors for the threads and internal bowl for the O-Ring seal, and
from the weather elements.
2. They are a quick way to rig up the BOP.
3. As a backup to the swab valve, where a bleed valve and pressure gauge are
screwed into the 1/2" (13 mm) NPT port for reading the wellhead pressure.

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MCEVOY SINGLE X’MAS TREE CAP MCEVOY SINGLE X’MAS TREE CAP

(3 1/8 “ X 5000 PSI) (4 1/16” X 5000 PSI)

MCEVOY DUAL SEGMENTED X’MAS TREE CAP

(3 1/8” X 3 1/8” X 5000 PSI)

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STANDARD X’MAS TREE WELL HEAD ADAPTER

SINGLE XMAS TREE WELL HEAD DUAL XMAS TREE WELL HEAD

ADAPTER ADAPTER

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WS-303-F SURFACE EQUIPMENT ACCESSORIES

Chemical Injection Sub

A chemical Injection Sub is designed to allow the injection

of either a de-icing agent (i.e. Methanol or Glycol) or an
inhibitor to prevent H²S/CO² corrosion. It is mounted just
below the stuffing Box or Grease Injection Head.

Crossover Adaptor

Crossover Adaptors are essential for the connection of

incompatible components required for well service
operations.
Crossovers can be ‘Tailor Made” to suit any combination
of connections required and can be combined to include
injection and bleed off facilities.

Quick Union Test Cap

Quick Union Test Caps are available for all sizes of quick
union connections to assist with the testing of pressure
control equipment.

Test Caps are normally supplied with a ½” N.P.T. port, but

are also available blank or with any number and type of
port required.

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Lifting Cap

A Lifting Cap is a safe and efficient way of lifting Blow-Out-

Preventors onto the wellhead. It gives the operator a
straight vertical lift which is essential when connecting
quick unions

3” Low Torque Plug Valve

The Low Torque Plug Valve is used mainly as a secondary

swab valve in cases where all wellhead valves are leaking
badly and the well has to be plugged for Wellhead
Maintenance operations. Care must be taken when using
this valve to open the wall. The rotation of the plug inside
the valve body is direct as opposed the wellhead valves
which open gradually. Crack the valve open little by little
until a pressure build up is observed in the lubricator. Stop
and wait for full equalisation before opening the valve all the
way. It is easy to get blown up if not handled properly.

Integral Pump In Tee

The Integral Pump In Tee is mostly used during Well
completion wireline operations.
It is installed as part of the surface equipment, below the
wireline BOP.
A 2” Low Torque valve will be installed on the 1502 – 2”
Weco side outlet on the sub body.

It allows for tubing tests to be conducted, while staying

latched onto selective test tools, prongs or standing
valves, without having to rig down lubricators, BOP,s etc.
to install a test head.

It is also need in fishing operations with risks involved (i.e.

fishing out a longer fish then anticipated while being
rigged up with maximum length lubricator and not being
the well might have to be killed through the pump in tee.

Always make sure a 2” Low Torque valve is installed on

the side outlet and pressure tested prior to commencing
fishing operations.

A 1502 Weco blanking cap should be used to plug off the

side outlet, as when the need arises to kill the well,
(because of a stuck tool string or fish across the tree
valves), it will be too late and impossible to install the Low
Torque valve.

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WS-303-G QUICK UNIONS

The connections used to assemble the wireline service lubricator and related
equipment are referred to as `Quick Unions', and they are designed to be assembled
by hand. 2 types in common use are 'Otis and 'Bowen' designs.

An O-ring on the pin section forms the seal when made up into the box. The collar has
an internal ACME thread to match the external thread on the box. This thread makes
up quickly by hand and should be kept clean. The O-ring should be thoroughly
inspected for damage - replace if necessary before use. A light film of oil (or grease)
helps to make up the union and prevent damage to the O-ri as the connections are
made up.

When the collar is made up, it should be backed off approximately one quarter turn to
eliminate any possibility of it sticking, due to friction when it is to be removed.

Pipe wrenches, chain tongs, or hammers, should never be used to loosen the collar of the
union. If it cannot be turned by hand, precautions must be taken to make sure that the
well pressure has been completely released.

Rocking the lubricator to ensure it is perfectly straight will assist in loosening the quick
union.

All quick unions are welded to the lubricator. Older types up to 5,000 psi were
threaded, but this practice is no longer permitted. In some designs the pin and box
sections are machined in one piece, and the collar is assembled over the pin and
retained with a `split nut' fitted internally in the collar.

Caution : Any equipment to be used in an H 2S environment must be H2S rated.

Standard service equipment must not be used when H2S is present.

Note : Otis and Bowen types of union are not compatible.

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Maintenance Procedure
All types and sizes of the lubricator are checked as follows:

➢ General damage and corrosion.

➢ Check the needle valve condition on the lower sections. Redress / replace the
valve as necessary.
➢ Visually inspect the internal bore for corrosion and `wire tracking' wear grooves.

Check the quick unions for:

➢ The condition of the O-ring groove.

➢ The condition of the pin and box sealing surface.
➢ Check the pin and box sizes carefully, as per the table on page 12 and 13 of this
section.

Important : The maximum clearance between dimension 'B' and 'C' is 0.020"
(0.010" per side).

The gap between the pin and box diameter has a direct bearing on the seal integrity,
and it is therefore critical that these tolerances be checked each time the lubricator
arrives in the workshop.

Note : Report any sizes below the minimum. Remove the item from service for
replacement or- repair.

Clean and inspect all components and replace the O-ring seals and thread protectors.

Otis Type Quick Union Dimensions

Bore WP Service Connection Pin OD Box ID Thread O-Ring #
(A) (B) (C) (D) OD (E) (F)
2.50 5,000 Std 5.000-4 ACME 3.494 3.500 5.000 338
10,000
2.50 15,000 Std 5.000-4 ACME 3.494 3.500 5.000 338
3.00 5,000 H 2S 5.750-4 ACME 3.994 4.000 5.750 342
10,000
2.50 15,000 H 2S 6.250-4 ACME 3.994 4.000 5.750 342
4.00 5,000 Std 6.500-4 ACME 4.744 4.750 6.500 348
10,000
3.00 15,000 H 2S 7.500-4 ACME 5.494 5.500 7.500 354
5.00 5,000 Std 8.250-4 ACME 6.182 6.188 8.250 434
10,000
4.00 5,000 H 2S 8.375-4 ACME 5.244 5.250 8.375 427
10,000
6.38 5,000 Std 8.750-4 ACME 7.494 7.500 8.750 441
5.00 5,000 H 2S 9.000-4 ACME 6.744 6.750 9.000 362
10,000
6.38 5,000 H 2S 9.500-4 ACME 7.994 8.000 9.500 443
4.00 15,000 H 2S 9.500-4 ACME 6.244 6.250 9.500 435

Notes: As a general guide, soft O-rings are used with 5,000 psi and hard on higher
pressure ratings.
Viton for use in H2S.
Nitrile for use in CO2
The 3 digits of the O-ring number indicate the international standad code.

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Ordering: In the Hydrolex system add 202-xxx to order O-rings, 215-, 270- and
291-, prefix numbers identify material.
In the Otis system add 91Q1 xxx yo order O-rings; 91QV1 xxx for Viton.
Check with the supplier for the correct material for specific conditions.

The above data is courtesy of Eastern Oil Tools and Hydrolex Inc.

Bowen Type Quick Union Dimensions

Bore WP Service Connection Pin OD Box ID Thread O-Ring #
(A) (B) (C) (D) OD (E) (F)
2.50 5,000 Std 4.750-4 ACME 3.744 3.750 4.750 340
10,000 H 2S
3.00 5,000 Std 4.750-4 ACME 3.744 3.750 4.750 340
10,000
2.50 10,000 Std 4.750-4 ACME 3.744 3.750 4.750 340
15,000
3.00 5,000 Std 5.500-4 ACME DL 4.369 4.375 5.500 345
10,000
3.00 10,000 Std 5.500-4 ACME DL 4.369 4.375 5.500 345
15,000
3.50 5,000 Std 6.000-4 ACME DL 4.869 4.875 6.000 349
10,000
2.50 15,000 Std 6.312-4 ACME 4.369 4.375 6.312 345
22,500
2.50 10,000 H 2S 6.312-4 ACME 4.369 4.375 6.312 345
15,000
2.50 5,000 H 2S 4.750-4 ACME 3.744 3.750 4.750 340
2.50 15,000 H 2S 6.312-4 ACME 3.744 3.750 6.312 340
22,500
4.00 5,000 H 2S 7.000-5 STUB ACME 5.244 5.250 7.000 427
10,000 Std
4.00 10,000 Std 8.250-4 ACME 5.994 6.000 8.250 358
15,000
5.00 5,000 H 2S 8.250-4 ACME DL 6.744 6.750 8.250 438
10,000 Std

Notes: As a general guide, soft O-rings are used with 5,000 psi and hard on higher
pressure ratings.
Viton for use in H2S.
Nitrile for use in CO2
The 3 digits of the O-ring number indicate the international standad code.

Ordering: In the Hydrolex system add 202-xxx to order O-rings, 215-, 270- and
291-, prefix numbers identify material.
Check with the supplier for the correct material for specific conditions.

The above data is courtesy of Eastern Oil Tools and Hydrolex Inc.

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WS-303-H O-RINGS

O-Rings are used widely throughout the oil and gas industry to contain pressure both
in static and dynamic applications. Correctly fitted and used within their design limits,
O-rings perform well. The biggest cause of failure in the quick union application is
damage during making up the connection. This can be averted by lubricating with oil or
grease prior to assembly. Worn connections, where the gap between the pin and box
exceeds tolerances, will also lead to failure as shown below:

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WS-303-I MARTIN DECKER WEIGHT INDICATOR

The Weight Indicator is a completely sealed hydraulic system. The sensing load cell
is attached to the Xmas tree by a chain, and a heavy duty hose carries the pressure
generated to the fluid filled pressure gauge which is calibrated in lbs, kgs (or kN at
some Shell locations).

The load cell is provided with eye connections on one side to attach to the hay pulley,
and on the other for the Xmas tree forming a pull at 90°. The system is calibrated to
this right angle pull and accuracy will be slightly affected if this angle is not true, but the
sensitivity of the system is always maintained.

The gauge is a 6" fluid filled instrument which can be fastened on the wireline winch. A
damper is provided on the gauge to set the pointer motion to the required sensitivity.
The fluid filled case eliminates severe vibrations and also lubricates and protects the
working parts.

If fluid leaks out of the system, the plates of the load cell will close. If this occurs, the
reading on the gauge will be incorrect and if the plates close sufficiently to touch, the
gauge will no longer show the actual line tension. It is possible to pull the line to its
break point without realising the true load. The gap should be approximately 3/16".

Check this gap before and during wireline operations.

In addition to preventing the overloading of the wireline, the weight indicator will also
show changes in tension due to:

(i) Fluid levels or changes in fluid density.

(ii) Jar action.
(iii) The position of the downhole equipment.

A different Martin Decker weight indicator is used for 3/16" line because of the higher
pull which can be exerted. The load cell for this instrument has a smaller
cross-sectional area in the diaphragm, and is matched to the higher range dial (gauge).
The gauge / load cell cannot be interchanged.

Dial Marking
Maximum loading - Standard = 2,000 lbs 1,000 kgs
3/16" Unit = 4,000 lbs 2,000 kgs

Caution : Do not crush or cut the hose.

Mount the load cell so that the hose leaves the cell towards the tree
and is not kinked.

Note : Electronic strain gauges are available as alternate types of weight

indicators, but are not in such common use as the above hydraulic type.
Some counter assemblies as on the ASEP Flyline units have a build weight
indicators. This eliminates the need for a long hose. The principle of
operation is exactly the same as the weight indicator described above.
However the neccessity of the 90 degree angle of the wire passing the
hay pulley is no longer valid since the pulling force is measured at
diaphram in the counterhead assembly (See WS-302-B).

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WS-303-J WIRELINE SHEAVES

Wireline sheaves, known as `Hay Pulleys' in the smaller slickline sizes, are an
essential part of a wireline rig-up.

They are used to bring the wireline down from the stuffing box, and into horizontal to
the wireline winch drum. The wire should be parallel to the lubricator to reduce side
loading and resulting bending stresses on the tree connection. Ideally the wire should
form a 90° angle* at the pulley, but some location constraints make this difficult.

* The 90 ° angle is important to provide an accurate reading of the line tension on

the weight indicator. Refer to the “Weight Indicator Section" for further details.

It is hooked directly onto the eye in the weight indicator sensor.

The hole in the frame of the hay pulley is to permit a line wiper attachment to be fitted
to apply lubricant corrosion inhibitor.

Always install with the locking pin `up', to prevent the pin vibrating down and unlocking
the hay pulley if the pin spring is weak.

The size of hay pulley must be at least the minimum recommended for the line
diameter and type in use.

The larger diameter sheaves require a frame to prevent them from toppling over as
they drop when the line tension is reduced.

Minimum Recommended (inches) Pulley Diameter (inches)

0.092 11.25
1.108 13.00
0.125 15.00
3
/16 12.00
¼ 16.00
5
/16 20.00

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WS-303-K WIRE CLAMP

The Wireline Clamp used to clamp the wire to the lubricator while raising or lowering
it, or during operations when the weight has to be taken off the wireline unit (such as
rezeroing the weight indicator or hanging off the tools for an extended period).

The clamp is usually fastened to a bleed off valve, located on the lower most lubricator
section by means of a short chain or wire sling.

Take care not to kink the wire at any point during the rig-up, as this will cause a weak
point which may break or stick in the stuffing box.

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WS-303-L LIFTING CLAMP & SHACKLE

General Description of Clamp

Made of 1/2" or 5/8" thick by 2.1/2" or 3" wide bar stock, forged to fit around a
lubricator section. They are a matched pair of straps with bolt holes drilled in the wing
ends. One of the straps has a loop welded on for attaching the lower block of the
tackle. The bolts can be loosened for adjustment of the clamp up or down the OD of
the lubricator section.

Installation and Position of Clamp

Position the two halves of the clamp on each side of the top lubricator section so the
holes match up.

Insert a cap screw through one set of holes, slip a lock washer onto the threads and
thread a nut onto the bolt. Do the same for the other side. Move the clamp downwards
to about three feet from the quick union and make up the bolts tight.

Checking/Inspection of Clamp
Check the 1/2" or 5/8" pick up loop where it is welded to the half strap.

The possibility of cracks in the weld is remote but possible. Check the bolts for pulled
threads and possible cracking in the thread roots. The bolt threads will have to be very
clean for this examination.

Attaching Rope Block and Shackle

Always use a marine shackle with a threaded clevis pin. Before attaching the block to
the clamp, make sure that the tackle will not be twisted when the lubricator is lifted to
the proper height. Fit the shackle over the clamp loop and make up the clevis pin in.
Wrench the clevis pin slightly.

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WS-303-M BLOCK & TACKLE

Pre-Check Prior to Use Before Hooking the Block and Tackle on Top of
the Scaffolding

1 Extend the block and tackle out on the work deck.

2 Check the end plaited around the ferrule of the anchoring block.
3 Look for any frayed strands or cut lay.
4 Free end of rope is braided to prevent unravelling.
5 Check for any deteriorated places in whole length of rope.
6 Make sure there are no inner twists between blocks before hooking on to the
lubricator.
7 Ensure that blocks, sheave shafts are properly pinned.
8 Check that grooves on shave are in good condition.

Care and Maintenance of the Block and Tackle

1 Take care not to let top block fall on the work deck.
2 Do not let the rope or the blocks drag in dirt, sand, mud or oil.
3 Replace the rope when any damage to any of the lays are noticed. Use a good
quality Manila rope.
4 When rigging down stretch the blocks apart fully. Make a double half hitch with
pull rope above the lower block. Plait the block and tackle in a chain stitch (this
prevents entanglement and saves time at the next rig up).

Care and Handling of Rope

1 Before stringing new rope in the blocks stretch the rope out to its full length,
anchor one end, pull and untwist the new rope for a few minutes.
2 Lay the pulleys on a clean surface about a foot apart.
3 String the rope through the pulleys.
4 Dead end of rope should be plaited around ferrule.
5 The pull rope end should be plaited to prevent rope from unravelling,

General Safety Guidelines in Using Rope Block

1 Never tie pull rope to a hand rail, bleed off valve or a hand wheel.
2 Do not wrap pull rope around any object with sharp or square edges.
3 Easiest way to tie pull rope is to tie a clove hitch around one of the ram housings
of the BOP It can easily be tied with either hand.

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CHAPTER 4
STANDARD WIRELINE TOOL STRING
TABLE OF CONTENTS

WS-304-A STANDARD WIRELINE TOOLSTRING & PREPARATION ...........................2

WS-304-B BASIC TOOL STRING COMPONENTS .........................................................3
WS-304-C ROPE SOCKETS ............................................................................................4
WS-304-D STEM ...............................................................................................................7
WS-304-E ROLLER STEM ...............................................................................................8
WS-304-F TUNGSTEN & LEAD FILLED STEM...............................................................9
WS-304-G MECHANICAL JARS ....................................................................................10
WS-304-H KNUCKLE JOINTS ........................................................................................11
WS-304-I KNUCKLE JAR ...............................................................................................12
WS-304-J PETROLINE QUICK LOCK CONNECTION ..................................................13
WS-304-K THREAD STRENGTH VERSUS QUICK LOCK CONNECTION ..................14
WS-304-L SUCKER ROD THREADS .............................................................................15
WS-304-M BDK RELEASABLE ROPE SOCKET ...........................................................16

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WS-304-A STANDARD WIRELINE TOOLSTRING & PREPARATION

Before assembling a toolstring, the following checks should be carried out:

1. Inspect the rope socket for burrs around the wire hole which could damage the
wire.
2. Inspect all box and pin threads or quick connections for damage.
3. Inspect the fishing neck profiles for burrs and wrench damage.
4. Inspect the mechanical jars for buckling, bending, bowing, and check for smooth
operation.
5. Check the hydraulic jars for leaks and correct operation.
6. Check the spring jars for operation (with hydraulic test sub) and set the release
point required.
7. Check the integrity of the roll pins in the knuckle joints, and freedom of movement
of the ball in the socket.
8. Check the swivel joint rotation action and any roll pins.
9. Check all tool operations on the surface. i.e. Remove the shear pins and check the
movement.

Rectify any faults found before assembling the string.

While it is expected that wireline tools and equipment will sustain some wear and / or
damage during use, it is inexcusable to use them in a badly worn or damaged state.

Although all tools and downhole equipment should be inspected and tested in base
workshops before issue, they must also be thoroughly inspected on site before and
after use.

For Example - Fishing necks on SRT type threaded connections may be damaged
from wrenches. These should not be run as it may impair the pulling
tools ability to latch that fishing neck if the toolstring or components
are lost in the hole.

If pulling / running tools do not function smoothly on the surface, there

is no chance of them working in the hole. Check and redress as
necessary.

Inability to locate a running tool in a landing nipple for example, could

be caused by weak springs in the locking mandrel. Most
manufacturers recommend that the key springs in locking mandrels
are replaced each time the mandrel is run and pulled, to ensure the
proper location of the locking keys.

When disassembling tools and equipment incorporating heavy duty

springs, always ensure the correct jigs and tools are utilised as the
stored energy within a strong spring can be considerable.

HYDRAULIC OR SPRING JAR

When a hydraulic or spring jar is incorporated in the tool string the following applies

The hydraulic or spring jar shall be installed immediately above the mechanical jars.
Check the tightness and security of all the sections of the additional jar.

Check for correct operation of the jar.

Check the length of the jar in open and closed position.

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COMPOSITION OF STANDARD TOOLSTRING

1 7/8” Tool string (1.750” Fishing neck) 1.50” Tool string (1.375” Fishing neck)

1 7/8” Rope socket (Tear drop type) 1.50” Rope socket (Tear drop type)

1 7/8” Stem x 5ft. 1.50” Stem x 8ft. (3 + 5ft)

1 7/8” Hydraulic or Spring jar (optional) 1.50” Hydraulic or Spring jar (optional)

1 7/8” Knuckle joint**(when required) 1.50” Knuckle joint**(when required)

1 7/8” Mechanical jar 1.50” Mechanical jar

1 7/8” Knuckle joint** 1.50” Knuckle joint**

17/8” Quick Lock Connection 1.50” Quick Lock Connection

** The use of a Knuckle joint should be carefully considered when working in deviated
wells and with Side Pocket Mandrels, as it may result into hold ups.

NOTE: When opening a 2.750” a 2.313” or 1.875” SSD with 0.092” wire, an 1.50”
standard tool string is to be used at all times. The number of feet of stem to be
used will depend on pressure differential and deviation. Additional knuckle
joints will depend on well conditions. Any changes in tool string configurations
have to be approved by the Operations Supervisor (CSR or Non Campaign).

WS-304-B BASIC TOOL STRING COMPONENTS

The basic tool string components are shown here.

The diameters in most common use are 1 1/2" and 1 7/8", but tool string
components are also available in 1", 1 1/4", 2 1/8", and 2 1/2" diameters
Rope Socket Provides a link with the wireline

Swivel Joint Attach between the rope socket and stem if required

Stem To add weigth / mass to the tool string to overcome well

pressure and friction, and provide impact downhole.

Upstroke Jars Attach here if required.

Mechanical Jars To provide a means of generating impact.

Knuckle Joint Attached here if required.

Attach the required tool to the bottom of the jars or knuckle joint.

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WS-304-C ROPE SOCKETS

The Rope Socket is required to make the connection between the wireline and
toolstring.

Types in most common use:

➢ 0.092" regular knot type.
➢ 0.092" / 0.108" / 0.125" no-knot type (teardrop).
➢ 3/16" braided.

Disc spring type

Preparation Procedure

Always wear gloves when tying the wire and take care of the springy sharp ends.

Pass the end of the wire through the stuffing box, then pass the end of the wire through
the wireline socket body, spring and spring support. Place the disc in a vice and run the
wire down between the jaws behind the disc, then bend the end of the wire into a loop
to form a handle that will be comfortable to grip. The disc should contact the wire
approximately 10" or 12" from the loop. Grip the long end of the wire (the end
connected to the drum) by wrapping it around your left forearm (if right-handed) and the
handle with your right hand.

Now holding the wire taut, start bending the wire about the disc (a). The wire should go
around the disc once, then be wrapped around itself making sure there is a minimum of
slack in the wire when starting to wrap. These wraps should be made smooth and
even, and should hug the wire closely with the coils touching one another. Continue
wrapping in this manner until about 12 coils are made.

Now move the wire in the direction shown in order to twist off the free end (b). Be
careful to keep the loop pointed in the same direction or slightly twisted during this part
of the operation, so that the torque is focused on the end of the last coil. The wire
should twist off cleanly presenting a neater appearance, and should be a far better job
than could be accomplished with a file or other tools (c).

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Place the disc crosswise in the vice or pliers, and straighten the knot as well as
possible. Now using the wire, pull the knot into the socket and check to see that the
socket swivels freely. The socket is now ready to be attached to the upper end of a
stem.

The `No-Knot' Type Rope Socket (also called a `teardrop' or `wedge' type) is designed
for 0.108" and 0.125" slickline. While it can be also used for 0.092", the knot type is
more common for the thinner wire.

Description

The standard body has an internal taper to accept the thimble, however a thimble eye
is available to convert the older style of rope socket.
The end of the wire is bent to fit the curve at the bottom of the `teardrop', with the
`short' side slightly shorter than the side of the thimble.
The groove in the thimble of these sockets is not deep enough to accommodate the
total thickness of the wireline. As the security of the wireline depends upon its being
`pinched' between the thimble and body, care must be taken to ensure the correct size
of socket is selected for the wireline in use.

Important : As the internal components of the teardrop rope socket do not permit
the wire to rotate, it is essential to include a swivel immediately below
the rope socket. Do not substitute a knuckle joint in place of a swivel.
A swivel has 1 1/2° - 5° of lateral movement, where a knuckle is not
designed to rotate under load and has 15° of lateral movement. In the
event of it being necessary to fish the rope socket, a knuckle joint will
allow it to lay over against the side of the tubing wall at an angle
which may make latching difficult / impossible.

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Rope Socket Size Chart

Nominal Fish Neck Types Length t Pulling Tool Minimum
Size Available Nominal Size Tubing
Diameter
1" 0.875" K 6.0" 1 3/16" 1.380"
1 1/4" 1.187" K, N/K 5.0" - 6.60" 1 1/2" 1.610"
1 1/2" * 1.375" K, N/K, B 5.0" - 6.75" 2" 1.867"
1 7/8" 1.750" K, N/K, B 5.0" - 8.90" 2 1/2" 2.259"
2 1/4" 1.750" N/K, B 6.6" - 10" 2 1/2" 2.992"
2 1/2" 2.312" N/K, B 6.8" - 10 1/8" 3" 2.992"
* Otis 1 'l2" has a 1 3/8" body maximum OD.
( K = Knot N/K = No-Knot B = Braided line)
t =Approximate Camco sizes shown.

Pear Drop Type For Slick Line

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WS-304-D STEM

Sometimes referred to as `sinker bar', the Stem provides weight to the toolstring to
enable the wire to run into the well against well pressure and stuffing box friction.

A `rule of thumb' to determine the weight of a solid steel stem is:

Stem OD2 x 8/3 = weight lbs / ft.

Increasing the stem weight increases the impact force delivered

by the jars. However do not `overweight' the toolstrings, as
excessive mass dampens the `feel' and premature shearing of
the pins can occur.

Flats for wrenches are provided and should be used. NEVER grip
on the fishing neck or this will damage the sharp edge.

All connections should be clean and dry. DO NOT LUBRICATE

THE TOOLSTRING THREADS - they will unscrew downhole
during extended jarring.

The stem is available in standard lengths of 2', 3' and 5'.

The following chart gives details of common stems:

Nominal Thread * Fish Maximum Approxima

Size Connectio Neck OD (ins) te Weight
(ins) n OD (ins) per foot
(lbs)
(kgs)
¾ 5/8 –11 0.750 0.750 1.500
0.68
1 5/8 –11 1.000 1.000 2.660
1.21
1¼ ¾ -10 1.250 1.250 4.160
1.90
1½ 15/16 – 10 1.500 1.500 6.000
2.73
1 7/8 1 1/16 –10 1.880 1.880 9.375
4.26
2 1/8 1 1/16 –10 2.125 2.125 12.040
5.47
2½ 1 1/16 –10 2.500 2.500 16.660
7.60

* ‘Quick’ type connections are available on most of these

sizes.

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WS-304-E ROLLER STEM

The Roller Stem is a valuable, sometimes essential, addition to

toolstrings for deviated wells to reduce the frictional losses against
the tubing wall.

The Petroline roller stem shown here has phosphor bronze

bearings, and the pins are inserted into place and a weld positioned
to retain the pins. The weld is not designed to bond to the pins.

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WS-304-F TUNGSTEN & LEAD FILLED STEM

To provide greater weight for the same diameter and length, Otis
manufacture `Tungsten or Lead Filled Stems'. This stem has a
regular steel pin and box, and a tubular steel outer barrel. The inside
is filled with tungsten or lead to provide maximum density.

This stem is used primarily to run flowing pressure surveys to obtain

maximum weight and minimum cross-sectional area, to protect
against `floating' or being blown up the hole by pressure surges.

Other high density, heavy weight stems which are available include:
• Uranium, and
• Mallory filled (mercury alloy).

DO NOT USE LEAD FILLED STEMS FOR JARRING as the lead

will tend to creep downwards and split the outer barrel.

O.D. Thread Fish Neck Length Weight lbs

1.250” 15
/16” – 10 1.187” 2ft 10.4
3ft 16.3
5ft 28.3
1.500” 15
/16” – 10 1.375” 2ft 15.9
3ft 24.8
5ft 42.8
1.875” 1 1/16” – 10 1.750” 2ft 23.8
3ft 37.6
5ft 65.3
2.125” 1 1/16” – 10 1.750” 2ft 31.2
3ft 49.4
5ft 86.0

O.D. Connection Fish Neck Length Approximate Weight

(ins) (ft) (lbs) (kgs)
1¼ 15
/16 – 10 1.187 5 32.0 15.0
1½ /16 – 10
15
1.375 5 41.7 19.0
1 7/8 1 1/16 – 10 1.750 3 24.6 11.2
1 7/8 1 1/16 – 10 1.750 6 48.0 22.4

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Top chart shows weight of tungsten filled stem.

Bottom chart shows weight of lead filled stem.

WS-304-G MECHANICAL JARS

Jars are a vital component in every toolstring (except when running

pressure surveys on wireline).

It is essential that the operator can recognise the precise opening and,
closing point of the jars on the weight indicator.'

The force required downhole to manipulate tools and shear pins is

generated by the impact of the jars. If the jars are not being operated
correctly or if jar action is lost, then very little force can be exerted on
the tools.

From the formula, F = ma (Force = Mass x Acceleration), it can be

seen that the impact force can be increased by increasing:
(i) Stem weight (mass).
(ii) Speed at impact (acceleration).

Stem weight is fixed after the tools are run in the well, but speed can
be varied.

Jar down action is limited to maximum speed that gravity will close the
jars. In highly deviated wells and wells with thick viscous fluid
downward, jarring may be severely restricted.

Jar up action is more effective (with the same stem weight) as speed
can be increased by increasing the spooling speed at the wireline unit,
and by the use of long stroke jars.

Caution: Prone to scissoring in large bore wells.

O.D. Connection Fish Neck Closed Length Stroke

(ins) (ins) (ins) (ins)
1¼ 15
/16 – 10 1.187 38 20
1½ 15
/16 – 10 1.375 38 20
1½ 15
/16 – 10 1.375 48 30
1 7/8 1 /16 – 10
1
1.750 38½ 20
1 7/8 1 1/16 – 10 1.750 38½ 30

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WS-304-H KNUCKLE JOINTS

Knuckle Joints are used to add flexibility to the toolstring and should be used in
deviated wells. They are usually positioned immediately below the mechanical jars.
However if additional flexibility is required, a further knuckle joint can be included
between the stem and jars.

Knuckle joints permit 15° of movement and should be used

only when necessary. Excessive numbers of knuckle joints
can reduce the effectiveness of downward jarring by
allowing a sideways component of the force to be applied to
the tubing wall.

Some brands of knuckle joint have a fishing neck on the

lower body to assist recovery if the knuckle separates
downhole.

Important

Do not confuse knuckle joints with swivels. Swivels

permit only limited movement*, and have a bearing to
allow easy rotation even when under tension.
* 1 1/2 o to 5 °- depending on type.

Caution

Knuckle joints should not be used in place of swivels. If

the line breaks, latching a rope socket with a knuckle
joint leaning against the tubing wall can be very
difficult.

Size Chart - OD 1 ¼” 1 ½” 1 7/8”

Fishing Neck 1.187” 1.375” 1.750”
Length* 10 /8”
3
11 /8”
7
11 ½”
*Varies with manufacturer

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WS-304-I KNUCKLE JAR

The B.D.K. Knuckle Jar is similar in construction to the

Knuckle Joint.
The Knuckle Jar design incorporates a length extension of the
socket that allows the ball to move vertically for light jarring.

O.D. Thread Fish Neck

1.250” 15
/16 – 10 1.187”
1.500” 15
/16 – 10 1.375”
1.875” 15
/16 – 10 1.750”
2.125” 1 1/16 – 10 1.750
2.500” 1 1/16 – 10 1.750

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WS-304-J PETROLINE QUICK LOCK

CONNECTION

A faster method connecting toolstring

components is available using the `Quick
Lock Connection'. One of the types currently
on the market is the Petroline 'QLS' type
shown here.

To Connect

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The components are pushed together and rotated 90°. Once engaged, the
spring-loaded `blade' prevents rotation and release.

To Release

The blade is retracted by using a punch as shown or by hand on some designs, and
the male connection is then rotated 90 ° and released.

Advantages

• Speed of the toolstring assembly.

• Rapid changing of the tools for each run.

• Higher strength than sucker rod connections.

• Wrenches no longer needed to make up / break-out the tools, therefore no sharp

burrs, damage to tools fishing necks, or risk of damage to hands.

• Prevent possibility of unscrewing downhole.

WS-304-K THREAD STRENGTH VERSUS QUICK LOCK CONNECTION

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Notes
1. The information contained in this document has been derived from purely
considering theoretical tensile and shear calculations. It takes no account of
fatigue or bending stresses, and also has no derivation from test results.
2. Material yield value is taken as 91,300 psi. (This results in a 1.2 FOS.)
3. Material shear stress is taken as 45,60 psi. (This results in a 1.2 FOS.)
4. Material ultimate tensile stress is taken as 140,000 psi.

WS-304-L SUCKER ROD THREADS

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The traditional means of connecting the toolstring components are the Sucker Rod
Threads (SRT) used to connect sucker rods in beam pumping wells. The main sizes
are detailed below.

SRT connections are susceptible to damage from:

Direct damage in the toolbox if inadequately protected.
Corrosion if not protected. Copper based lubricants (or similar) provide good protection.
Overtightening with pipe wrenches and `cheater' pipes.

Additional damage can occur around the fishing neck and wrench area from the
wrench jaws.

WS-304-M BDK RELEASABLE ROPE SOCKET

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The B.D.K. Safe Joint

Patent Pending (Application No: GB 9509918.0)

The B.D.K. Safe Joint is designed for use as a standard item in the
Wireline toolstring.

The main purpose of this tool is to climinate the uncertainty of whether

you should risk dropping cutters and go-devils into the well and possibly
causing additional problems.

The Safe Joint can be installed as a Rope Socket using the conventional
Rope Socket and Pear Drop configuration or set lower in the string with
the majority of the stem above the Safe Joint which offers the added
advantage of more weight when pulling back to surface. This is
especially important when opening in high pressure well situations.

To install the Safe Joint further down the string (but always above the
jars) offers the operator the opportunity in a fishing situation to retrieve
the majority of the tools. Ie. Rope Socket. Stem etc. thus climinating one
extra section of Lubricator when fishing for the remainder of the tools.

Prior to running the Safe Joint, a calculation must be made to access the
maximum weight of the tools in the worst situation. Ie. Stems. Jars.
Weight of wire and possible swabbing effect when pulling back through
fluid. When an approximate figure is calculated the Safe Joint can be
calibrated to the required release point. (eg. 200 – 300 ilbs above
calculated weight of tools).

The range of the safe Joint will vary slightly depending on the tools size
(see chart below).

DETAILS 1½” 1 7/8” 2 1/8” 2½

Maximum OD 1.50” 1.875” 2.125” 2.50”
Make-up Length 36.00” 37.50” 37.50” 41.50”
Fishing Neck 1.373” 1.750” 1.750” 2.312”
Connection TBA TBA TBA TBA
Range 400-2000 lbf 400-2700 lbf 400-2700 lbf 400-4000 lbf
Maximum 300F 300F 300F 300F
Working Temp.
Service Standard Standard Standard Standard

Operation

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The Safe Joint operates via an enclosed sealed oil reservoir and is controlled using a
central differential check valve. For the tools to function the force created by the over-
pull on the line must exceed that of the calibrated setting. The action of pulling back on
the line creates a pressure within the oil reservoir and when this force is equal to that of
the stored energy within the Belleville springs the tool will start to function. The joint will
lock into the release position when sufficient oil has been displaced.

During jarring operations the tools will experience toads close to the calibrated release
setting. As the jarring action and load impact is relatively instant. This action could
possible cause the tools to prematurely start the release procedure. To overcome this
the State Joint has been designed with a low-pressure safety return system, which the
coupled with the hydraulic damping effect of the oil returns the tools to its neutral
condition instantly. There fore, there is never any danger of the joint ever pre-releasing
during the normal wireline operations.

The Safe Joint mechanism offers the operator a 3 point safety release system:-
1. A calibrated controlled over-pull
2. A short safety time delay
3. A sit down soft release

The advantages of this tools are:-

1. Fully adjustable to suit all types of wireline grades and sizes.
2. Adjustable complete with auto-lock mechanism.
3. Designed to release in high deviated situations
4. Weights can be added for high pressure controlled pull back
5. Leaves the same size fishing neck for re-latch
6. Eliminates wireline Cutters
7. Eliminates Go-devils
8. Eliminates costly rig-ups
9. Saves on hours of lost rig time

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CHAPTER 5
SPECIAL WIRELINE JARS
TABLE OF CONTENTS

WS-305-A Tubular Jar ....................................................................................... 2

WS-305-B Hydraulic Jar ..................................................................................... 3
WS-305-C BDK Hydro-Mechanical Jar............................................................... 5
WS-305-D BDK Mechanical Spring Jar .............................................................. 7
WS-305-E Petroline Spring Jar .......................................................................... 9
WS-305-F Rotary Jar ....................................................................................... 13

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WS-305-A TUBULAR JAR

Tubular jars are useful additions to the toolstring when fishing for wire, as there is
much less chance of tubular jars becoming jammed with a loose end of a piece of wire
than `spang' type mechanical jars.

1 - Top Sub
2 - Lock Pin
3 - Outer Housing
4 - Jar Rod
5 - Bottom Sub
6 – Lock Pin

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WS-305-B HYDRAULIC JAR

Hydraulic Upstroke Jars are placed between the stem and mechanical jars in the
toolstring, when extra jar up action is required or a need anticipated. This is especially
important when conventional jar up action is difficult because of deviation or high
viscosity well fluid.

Sizes available in 1 '/4", 1 '/2", and 1 3/4".

Always INCLUDE mechanical jars to provide downward jar action to shear off if
necessary (run with shear down tool).

Hydraulic oil - Jar Tube TS 190 or 10 W 30.

Oil viscosity may be varied to suit downhole temperatures.

Jars should operate after approximately 30 seconds of pull.

Never place hydraulic jars BELOW mechanical jars. If hydraulic jars become `gassed
up' (especially in high pressure gas wells) they will act as a shock absorber. In their
correct position, mechanical jars can still be used to shear downwards to release the
tool.

Operation

[1] The upward pull on the wire compresses the oil. The slow, controlled leakage
past the piston permits the jars to open slowly. Energy is stored in the `stretched'
wire.
[2] The piston reaches the increased ID - no further resistance as the oil rapidly
bypasses the piston.
[3] Upward impact as the piston strikes the top of the cylinder.
[4] The jars close under the stem weight as the check valve in the piston permits
easy fluid bypass.

Note : The balance piston compensates for the fluid volume loss as the piston shaft
moves out.

Caution : Always CLOSE THE JARS as the toolstring is lowered from the
lubricator, BEFORE laying the tools down.

Failure to do so may result in:

(i) Bent / cracked piston shaft.

(ii) Piston shaft* exposed to corrosion / damage.

* This surface is hard chromed to ensure a seal against the O-rings. Any
pitting will impair the operation of the jars.

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WS-305-C BDK HYDRO-MECHANICAL JAR

Mk3 Hydro-Mechanical Jar (Balanced System High Temperature Type)

Operation

The Hydro - Mechanical Jar is a patented tool designed to allow the operator to deliver
an upward impact force of a desired value. The jar has characteristics similar to
existing hydraulic jars except for the jar rod release mechanism, which is purely
mechanical. The jar will fire at any overpull imparted by the wireline, varying only on
time delay. Impact force is dependent on line pull prior to jar rod releasing. If an
accelerator is used, it is absolutely essential that the accelerator be adjusted so that
the stroke of the accelerator is equal to, or more than, the jar stroke, and that full stroke
is opened prior to the jar firing. If the accelerator is not set up property, then the
accelerator will 'fire' downward to meet the jar when the jar rod is released. This will
'look good' on the weight indicator, but no upward impact will have been achieved
downhole.

Like all other mechanical jars by-pass holes are provided in the main housing for
operation in fluid. If debris is present in the fluid e.g. Sand, Scale etc., then, like a bailer
the jar may suck this debris in. It is essential that the jars are broken down and cleaned
between jobs, ensuring the release mechanism is clean.

The jar has been designed for primary jarring use. This means that, although Spang
Jars will be present in the toolstring, the Hydro - Mechanical jar should be used for
impact operations first before Spangs are used. The impact force delivered by the
Hydro - Mechanical jar will be by far in excess of that expected from the Spang jars. If
for some reason Spang jars are used in preference to the Hydro - Mechanical jar, then
accelerated wear should be expected to the release mechanism, as all impact loads
will be transmitted through this mechanism.

Although the Hydro - Mechanical Jar uses, as it's name suggests, Hydraulic oil as a
time delay medium, the jar is not prone to 'gassing up' like other hydraulic jars. This is
because the oil is confined to a small chamber, sealed by virtually static seals, unlike
jars that employ jar rod dynamic seals.

From in house experimental testing, it was established that the allowable operational
temperature for the Hydro - Mechanical Jar should be set at a maximum of 200°
Celsius.

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WS-305-D BDK MECHANICAL SPRING JAR

Description

The BDK Mechanical Spring Jar is a telescoping upstroke jar that should be run in
conjunction with wireline stem installed immediately above. The spring jar can be
adjusted, on or off the toolstring at surface to a predetermined release force, therefore,
offering the operator a controlled impact force at the tool during heavy duty wireline
operations.

The BDK Spring Jar has been designed using a minimum number of working parts,
which offers the operator a fast and simple redress.

Maintenance

It is recommended to disassemble the Spring Jar after each operation and thoroughly
clean and inspect all parts. See disassembly and assembly instructions for further
details.

Operation

To operate the jar with an upstroke force the jar must be closed completely, this will
automatically engage the power release mechanism. An upstrain equal to the
predetermined setting plus the weight of the toolstring will place the slide stem in the
release position, the full force of impact then occurs as the slide stem strikes the top
cap, which transmits maximum impact at the running/pulling tool.

Adjustment Instructions

1 Adjustment to the load setting can be made on or off the toolstring.

2 The indicator bands are approximate settings and should not be taken as
accurate loadings.
3 For precise settings use the BDK Calibration Sub, (see adjoining Calibration
Sheet.
4 To adjust the jar simply rotate the Cover Sleeve (22) to align the Adjuster Lock
Screw. Back off the Adjuster
Locking Screw (18), rotate the Bottom Sub (14). Rotate the Sub clockwise for
heavier load and anti-clockwise for lighter loads.
5 The load setting can be monitored through the indicator band slot in the body
(see adjoining adjustment detail sheet) by checking the.position of the Adjuster
Nut Indicator (11).

IMPORTANT: Always tighten the Adjuster Locking Screw (18) after the required
setting has been achieved. Finally rotate the sleeve to
encapsulate the Adjuster Screw.

Calibration Instructions

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1 Back off the jar adjustment fully, this will allow the slide stem to be released by a
slight overpull.
2 Screw the top sub of the jar handtight into the calibration tool.
Note : If the Jar has a QRJ type connection then the Top Sub will have to be
removed and the QRJ crossover calibration adaptor screwed on in its place.
Ensure that the calibration tool is reset, with the tommy bar boss touching the
internal plug.
3 Close the jar and adjust to approximate setting, using the indicator bands.
4 To operate the calibration tool, turn the tommy bar anti-clockwise until the jar
releases, taking note of the maximum pressure gauge reading.
The reading on the pressure gauge in psi at the point of release is equal to
the release force of the jar in Ibf. (1000psi max reading indicates a jar set to
10001bf release force).
5 Adjust the jar to the required release force. (See adjustment instructions). Spin
the tommy bar back to its starting position against the internal plug and relatch
the jar.
6 It is recommended to follow steps 4-6 to check the load calibration.
7 With the jar in the open position unscrew the calibration tool from the top sub.
8 Close the slide stem thus latching the jar. The jar is now ready for use.

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WS-305-E PETROLINE SPRING JAR

Petroline Spring Jars, shown here, are an alternative to hydraulic jars to provide
upward impact force. As with hydraulic jars, they are installed in the toolstring between
the stem and mechanical jars.

Note : Mechanical jars should always be included to enable downward jarring to

shear if upward jarring does not achieve the desired result.

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Principle of Operation

An upward pull is applied via the wireline. With the pulling / fishing tool latched, the line
tension is stored until a mechanical release mechanism retracts and permits the rapid
upward movement which creates an upward impact force.

Some designs permit the adjustment of the release mechanism* , which alters the
amount of tension required to `fire' the jars. Hence the magnitude of the resulting
impact is variable.

Sequences of Operation

1. Increasing the line tension moves the "jar rod" upwards from its static position,
slowly compressing the main "disc spring" via the "trip keys" and "trip housing".
The amount of tension required is adjustable by rotating the "spring rod" with the
"calibrating key". The "jar rod" and "trip housing" are gripped together by the "trip
keys".
2. As the "trip keys" move upwards with increasing line tension, they move
outwards (expand) into the recess in the "main housing".
3. The "jar rod" is released and moves rapidly upwards to strike the inside of the
"main housing", thus creating upward impact proportional to mass (stem weight)
above the jars and velocity at impact. The "trip housing" returns to the central
position as soon as the "jar rod" releases.
4. To reset the jars back to their original position (1), the weight of the stem forces
the "jar rod" and "trip housing" down by compressing the "cocking spring". This
causes the "trip keys" to retract into the lower recess in the "main housing". The
"trip keys" relatch the groove on the "jar rod" and the jarring cycle can be
repeated.
Advantages of Using Spring Jars

• No O-ring seals to leak and allow internal pressure build-up.

• Fluid bypass permits free access of well fluids through the jars.
• Generally greater upward impact than comparable hydraulic jars.

Note : The use of fishing tools with a greater area of `dog to fishing neck' contacts is
advisable.

Design Variations

• Use of balls or segments in the release mechanism.

• Position of release mechanism (middle or bottom).
• Adjustable release tension.
• Use of coil springs or 'Belleville' disc springs.

Note : It is advisable to close the jars before laying down the toolstring to prevent
bending of the “jar rod".

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WS-305-F ROTARY JAR

The Rotary Jar is run in combination with a

regular mechanical jars. It is used to
remove obstructions from around fishing
necks or brake up solid obstructions with a
chisel.

It can add in re-positioning of tools when

fishing.

Jarring down is the most preferred method

to operate and applies right hand torque to
tool run below. Jarring up might result in
parts of tools or fish backing off, however in
some cases this might be the preferred
option.

The jars must be run below the mechanical

jars and knuckle joints should be taken out
of the tool string (if possible) to obtain
maximum results

1 - Plunger
2 – Clip
3 – Cage
4 – Cross Pin
5 – Allen screw

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CHAPTER 6
STANDARD RUNNING TOOLS
TABLE OF CONTENTS

WS-306-A TYPES OF PIN SHEARING ............................................................................2

WS-306-B RUNNING & PULLING TOOL OVERVIEW.....................................................6
WS-306-C TYPE X & R RUNNING TOOL ........................................................................7
WS-306-D RUNNING SEQUENCE ................................................................................12
WS-306-E TYPE RX RUNNING TOOL ...........................................................................13
WS-306-F TYPE RXN RUNNING TOOL ........................................................................15
WS-306-G TYPE W RUNNING TOOL ............................................................................16

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WS-306-A TYPES OF PIN SHEARING

There are two ways in which wireline tools can be used for shearing pins. The first is
the straight shear which is through the center of a circular area. The second is the edge
or tangential shear which is the shearing of a pin in a hole drilled at right angle to the
radius of the OD of one part and the ID of the mating part, and longitudinally with the
plane of the shear pin, see Drawing No. I.

The nomographs on Drawing Nos. 2 and 3 give the theoretical breaking force of a
material normally used for shear stock. The ultimate shear strengths given in the table
below are sample results only. These tests were conducted under very good
conditions.

There are several factors that actually increase the shearing or breaking force of shear
pins such as:
1) Cutting edges of shear pin hole in the core and sleeve becoming dull or slightly
rounded off.
2) When the hole is larger than shear pin.
3) Increased clearance between ID of sleeve and OD of core.
4) Actual area of material to be moved in a tangential shear.

Material Selection for Ultimate Shear Strength

Material Type of Description Ultimate Shear Strength

Yellow Brass ½ Hard-Rokwell B 70 40,500 psi (279,000 kPa)

Aluminium 2024 – T4 41,000 psi (283,000 kPa)

Naval Brass (Tobin Bronze) ¼ Hard Rockwell B 80 43,000 psi (296,000 kPa)

Mild Steel 1018 58,000 psi (400,000 kPa)

Low Fuming Bronze – Type RCUZN-C Rockwell 58,000 psi (400,000 kPa)
U U2 Anaconda welding
Rod No. 997

Low Fuming Bronze – Type RCUZN-C Rockwell B 60,000 psi (412,000 kPa)
80 Airco welding Rod No.
27

Drill Rod Oil hardening, polished, 81,000 psi (558,000 kPa)

annealed – Rockwell C 10

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Different Types of Pin Shearing

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Shear Pin Breaking Forces

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Shear Pin Breaking Forces

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WS-306-B RUNNING & PULLING TOOL OVERVIEW

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WS-306-C TYPE X & R RUNNING TOOL

Design Principle

The X running tool is designed and developed to run the X and XN lock mandrels in
either the selective or non-selective position to the X or XN nipple, and firmly lock it in
the nipple.

The R running tool is identical in operational and design concept to the type X running
tool, except that this tool is designed to run type R and RN lock mandrels into type R
and RN nipples.

All the running, pulling, pinning, assembly and disassembly procedures are as stated
for the type X running tool.

The Otis R range of down hole equipment is designed to meet the higher weight
ranges of tubing in both size and pressure rating. On occasions an R or RX nipple is
used in step down completion nipple designs where a mixture of X and R ranges can
provide larger bore sizes of nipples than could be achieved using the X range only.

Operating Principle

The operational mode of the running tool must be manually set on the surface before
running it in the well. Set the X running tool in the selective position when setting in any
X nipple except the top X nipple. The X running tool should be in the non-selective
position when setting a lock assembly in the top X nipple.

In the selective position - Lock mandrel keys are fully retracted. The running tool
holds the lock fully extended. Running tool nipple locater dogs are out. The lug
segments lock the core to the main mandrel. There is no gap between the fishing neck
and the spring housing.

In the non-selective position - Lock mandrel keys are sprung forward to permit
square shoulders to be located in the nipple. Running tool nipple locater dogs are now
in holding the inner mandrel in the upward position. The lug segments are free to
permit the core to move when the top pin shears. There is a gap between the fishing
neck and the spring housing.

NOTE: Non-selective and control mode mean the same thing.

Pinning Procedure

Prior to pinning to the lock mandrel, the running tool should be checked to ensure that
it trips freely from the selective to non-selective positions. Place the tool in the
non-selective position, as it would be after pulling out of hole.

Then gently grip the tool horizontally in a vice on the dog retainer. Using a square
shank screwdriver or other suitable tool. Place in the gap between the spring housing
and fishing neck increasing the tension on the main spring. At the same time place
thumb and forefinger on the upper end of the nipple locater dogs and squeeze inwards
and upwards against the small spring. Release the screwdriver. The tool should spring
into the selective position.

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If the tool does not spring into the selective position:

1) Check if the nipple locater dogs were entirely outwards when you release the
tension.
2) Gently tap the spring housing in case the spring is binding inside a deformed
housing. If it is too tight replace it before running.

With the tool in the selective position. Place the tool horizontally in a vice and grip it
gently on the dog retainer. Push the nipple locater dogs up towards the fishing neck.
They should move inwards when at the upper end of the travel and return freely to the
extended position. If they do not move freely the spring may be binding and the tool
need redressing.

Pull the fishing neck outwards against the spring tension. A bar or screwdriver can be
placed through the slot above the core as a handle so that the necessary force may be
exerted.

The tool should trip into the non-selective position and remain there when the tension is
released.
1) Check that the running tool is in the non-selective position otherwise the core will
be locked.
2) Place the lock mandrel fishing neck firmly in a vice. Close the lock and insert the
running tool. Push the core downwards and hold it in place with a punch through
the top shear pin hole. Extend the lock mandrel and move the running tool in line
with the bottom shear pin hole. Insert a 8 mm brass pin.
3) Insert a 6 mm steel shear pin in the top hole. Cross punch and centre punch the
shear pins to ensure that they do not drop out.
4) Check that tool will trip from the selective to non-selective position.
5) Check that the lock mandrel keys when in the selective position are fully retracted
or when in the non-selective position are sprung forward.

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‘R’ Lock Mandrel

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A) SECTIONED B) EXPLODED VIEW OF COMPONENTS

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WS-306-D RUNNING SEQUENCE

(I) (II) (III) (IV) (V)

RUNNING TOOL LOCATING NIPPLE LOCK IN JARRING DOWN LOCK SET CHECKED
IN SELECTIVE & TRIPPING NON-SELCTIVE SHEARED PIN A BY OVERPULL,
MODE RUNNING TOOL MODE & LOCATED & SET LOCK JARRED UP &
IN NIPPLE SHARRED PIN H

Positions / Movement at labelled points

A Shear pin protected by lug segments Pin unprotected Pin sheared ------
B No gap Gap Gap Gap
C Dogs out Dogs locating Dogs holding inner mandrel in non selective position
D Lug segments locking core to main Lug segments release core by moving into recess in key
mandrel retainer
E Holding fishing neck of lock – will not release until core move Release fishing neck – core fully
80% moved
F Fully extended Partially Closed
compressed
G Keys fully retracted Sprung Forward Locked Locked
to
H Shear pin intact Intact Intact Sheared

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WS-306-E TYPE RX RUNNING TOOL

Design Principle

The RX running tool is designed to run surface controlled subsurface safety valves
attached to R, X, RN, XN and RQ lock mandrels and lock them in the uppermost nipple
of the tubing string. The RX running tool is used to run, set and release from lock
mandrels. The RX running tool has the following features.

1) If for any reason the lock mandrel is not jarred to the full down and locked
position. The running tool remains latched to the fishing neck and the lock and
control devices are retrieved.
2) It allows a variety of sizes or quantities of shear pins to be used to jar the lock
mandrel and control device into the landing nipple. Depending on the difficulty
anticipated with packing interference.
3) Once the locking mandrel expander sleeve has moved down the full distance to
the locked position. Relative motion within the running tool is eliminated by
use of a snap ring which locks the core to the body of the tool.
4) The final 25 mm of stroke of the running tool shears an addition tell tale shear pin
in the' top sub. The snap ring should not lock the core in the full position releasing
the lock mandrel fishing neck. Unless the lock mandrel is fully locked.
5) There are two shear pin positions in this running tool. This capability is provided
by two sets of shear pin holes approximately 11 mm apart at the upper end of the
core. One position causes the keys in the lock mandrel to be retracted. This
position is used when running the RQ lock mandrel with a no-go ring or any other
no-go type lock mandrel. The other position causes the keys of the lock mandrel
to be in the expanded position and is used to run an RQ lock mandrel without a
no-go ring or an X or R lock mandrel.

Pinning Procedure

1) Inspect the safety valve and lock mandrel for correct operation.
2) Cut and fit the 5 mm pre-machined steel mandrel fishing neck locking pins. Close
the neck and check for correct operation of the pins and leaf spring.
3) Remove the pins, open the fishing neck and then open the valve with a hand
pump.
4) Check the lock mandrel running tool for correct operation.
➢ The snap rings are in the correct position.
➢ All remaining parts of shear pins are removed.

The appropriate running prong is fitted tightly to tile core.

5) Install the running tool in the mandrel and fit quantity 100 mm x 6 mm steel upper
shear pins, 25 mm x 9.5 mm brass lower shear pin, 25 mm x 6 mm brass
indicator shear pin and refit the mandrel fishing neck locking pins and leaf
springs. Ensure that when the pins are sheared all pieces will be prevented from
falling free of the running tool or mandrel.
6) Remove the hand pump and check that the valve is held partially offset.
7) Lightly grease the V packing of the valve and lock mandrel.

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Attaching to a Lock Mandrel

1) Make up the proper running prong into the lower end of the core of the running
tool.
2) Apply control pressure to the safety valve until it moves to the full open position.
3) Remove the cap screw, leaf spring and shear pin from the lock mandrel.
4) Remove the shoulder bolt, set screws and shear pins from the running tool.
5) Remove the top sub and the snap ring from the running tool.
6) Move the core down until the lugs are located over the recess in the core. Place
the snap ring just over the end of the core. Insert the running prong, core, and
lugs into the locking mandrel until shear pin holes in the core line up with the
mating holes in the lock mandrel. Install one or more shear pins in these holes.
Move the bottom sub of the running tool up in relation to the core so the lugs
move out onto the larger diameter of the core and engage the fishing neck.
7) Install the shoulder bolt.
8) Install the shear pins in the selected running position shear pin holes and the set
screws in the running tool. The number of shear pins installed depends on
packing resistance anticipated, but it is usually four.
9) Replace the top sub.
10) Replace the shear pin, leaf spring and the cap screw on the lock mandrel.
11) Install the brass shear pin between the.lock mandrel and the running tool core.
12) Install the tell tale shear pin in the top sub of the running tool
13) Bleed off the pressure on the valve and check that the ball or flapper is held
offset.
14) The assembly is now prepared for running.

“RX” Running Tool

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WS-306-F TYPE RXN RUNNING TOOL

Design Principle

The type RXN running tool was designed as a replacement for the type RX. It has
been designed such that the retainer dogs on the running tool will not release the
fishing neck of the lock mandrel until the fishing neck and expander sleeve have moved
at least 80% of their travel. With this increased assurance of lock mandrel closure no
tell tale devices are required.

The following design differences exist between the RXN and the RX.

1) The RXN retainer dogs are of the X Line Running Tool design.
2) No tell tale features.
3) The RXN features an offset retainer pin to transfer the upward shearing action
from the core through to the main mandrel and backs up as an alignment device
for pinning in the selective or non-selective position.

“RXN” Running Tool

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WS-306-G TYPE W RUNNING TOOL

Design Principle

The type W running tool is designed to run the type W and type B locking mandrels
with a special internal groove near the top of the main mandrel.

Operating Principle

The W running tool is especially useful in getting the W and B locks down the tubing
where there are paraffin problems or the tubing bore is slightly out of round. The tool
can be jarred down without any danger of pre-setting at the wrong depth. Moving the
tools upward at the pre-determined depth, sets the slips by forcing them out against the
tubing wall. Upward jarring with the wireline tools causes the slips to bite harder into
the tubing wall. Continued upward jarring shears the pin which lets the collet expander
move up the collet to collapse and release its hold of the main lock mandrel.

When setting the W lock, the upward jarring also pulls the element expander up under
the sealing element forcing it against the tubing wall for a seal.

Pinning Procedure

1) Unscrew the running neck and remove from the body.

2) Remove the screw.
3) Extract the shear pins.
4) Push the collet down against the inner shoulder of the body.
5) Set the collet in the internal recess in the main mandrel.
6) Align shear pin holes and insert shear pins.
7) Slide sleeve over body.
8) Install the fishing neck and tighten.
9) The tool and lock are ready to be run in the well.

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BSP Well Engineering Manual Volume3, Wireline, Standard & Procedures

CHAPTER 7
STANDARD PULLING TOOLS
TABLE OF CONTENTS

WS-307-A X-LOCK PULLING PROCEDURE ..................................................................1

WS-307-B TYPE GS & GR PULLING TOOL ....................................................................3
WS-307-C GR EXPLODED VIEW ....................................................................................5
WS-307-D TYPE GSL PULLING TOOL ...........................................................................6
WS-307-E TYPE R PULLING TOOL ................................................................................7
WS-307-F TYPE S PULLING TOOL .................................................................................9
WS-307-G TYPE SSJ PULLING TOOL ..........................................................................11
WS-307-H TYPE J SERIES PULLING TOOLS ..............................................................12
WS-307-I TYPE B PULLING TOOL ................................................................................16
WS-307-J RUNNING & EQUALIZING PRONGS ...........................................................17

WS-307-A X-LOCK PULLING PROCEDURE

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WS-307-B TYPE GS & GR PULLING TOOL

Design Principle

The Otis type GS pulling tool is a shear down releasing tool used in wireline
operations to retrieve various Otis locking mandrels having internal fishing necks.
These pulling tools can be run with equalising prongs and are made up to the standard
wireline work string. The tools are lowered to the lock mandrel and the equalising prong
(if attached) engages the equalising device before the pulling tool engages the fishing
neck of the assembly.

Operating Principle

As the pulling tool starts into the internal fishing neck of the lock, the dogs move up and
in around the smaller diameter of the core because of the restriction of the pulling neck.
When the top of the pulling shoulder of the dogs pass the neck restriction a spring
pushes the dog retainer down until the dogs rest on the shoulder of the core. After
equalisation upward jarring should release the lock. The tool is then pulled from the
well bore.

If the lock cannot be released and it is necessary to retrieve the work string, downward
jarring will shear the shear pin and let the fishing neck and core move down. The dogs
will then move inward against the small diameter of the core and be kept in this mode
by the spring. The tools can now be pulled from the well bore.

Assembly Procedure

➢ Remove set screw.

➢ Grip flats of core upright in a vice and remove fishing neck.
➢ Clamp cylinder in the vice and unscrew the top sub until the shear pin is exposed.
➢ Remove the shear pin with punch and hammer.
➢ Remove the top sub. Note: be careful when nearing the last threads as the top
sub still has spring tension.
➢ Remove spring, spring retainer and dog retainer by turning the cylinder upside
down. The dogs will also fall out.
➢ Wash and wipe all parts and inspect them closely, especially the dog retainer.

Disassembly Procedure

1) Grip cylinder in an upright position lightly in a vice.

2) Place the dogs and dog retainer in position.
3) Put the dog retainer, with the dogs, inside the cylinder.
4) Put the spring and the spring retainer in the cylinder.
5) Install the spring on the spring retainer.
6) Insert the core up through the assembled parts.
7) Clamp the cylinder in the vice and install the top sub over the core.
8) Push the top sub against the compression of the springs and start screwing the
top sub onto the cylinder.
9) Before making the top sub up all the way, place a pry bar against the end of the
core and line up the shear pin holes.
10) Install the shear pin, finish making up the top sub and tighten.
11) Install the fishing neck (do not wrench on the threaded hole).
12) Install the set screw and tighten.

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Design Principle

The Otis type GR pulling tool is a shear-up tool which consists of a GS pulling tool
with a GU shear up adapter. The GR is used in pulling different Otis locking mandrels
having internal fishing necks. This tool can be used in the same applications as the GS
pulling tool.

Operating Principle

The operating characteristics of the GR pulling tool are identical to the GS pulling tool
with the exception of its direction of shear. The GR pulling tool uses a 8 mm shear pin,
and the GS pulling tool takes a 1/4" shear pin.

There are two main reasons why an operator would choose to run a shear-up rather
than a shear-down tool.

➢ First, if the down hole assembly contains a device or mechanism that requires
movement, shearing or penetrating it with a prong would limit the downward
travel of the core of the pulling tool needed for shearing.
➢ Secondly, any obstruction or foreign matter would prevent the cylinder of the
pulling tool from contacting the top of the fishing neck of the assembly down hole.

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WS-307-C GR EXPLODED VIEW

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WS-307-D TYPE GSL PULLING TOOL

Design Principle

This pulling tool is made up of two assemblies. The GSL pulling tool and the GU
shear-up adapter. The outstanding difference between the GR and GRL pulling tool is
the core. The GSL core has an extended nose. The additional length of the nose is to
enable the GRL pulling tool to shift the locking sleeve down in the D collar lock and the
DD Bridge plug assemblies.

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WS-307-E TYPE R PULLING TOOL

Design Principle

The R series pulling tool is designed to engage any external fishing neck and shear
to release by upward jarring. It has three different models namely the types RB, RS
and RJ. The only difference in the three types is the length of the core which is installed
in the tool. The RB uses the longest core, the RS uses the medium core and the RJ
uses the shortest core. The core comes in three different lengths. The different lengths
make it possible for the operator to change the reach of the pulling tool in accordance
to the assembly to be pulled in the well. The reach is the distance from the bottom of
the core to the engaging shoulder at the end of the dogs.

Operating Principle

The R pulling tool is strictly a jar-up-to-release tool. Upward impacts from the wireline
weight bars are transmitted through the fishing neck into the core across the shear pin
and down into the skirt which supports the dogs at the bottom.

If the assembly being jarred on is stuck solid, the force exerted up from the core to the
skirt is a shearing action which cuts the pin in two places. This allows the cylinder
spring to move the skirt and dogs down against the shoulder near the bottom end of
the core. When the dogs make contact with this shoulder the upper inside edge of the
window squeezes the tapered upper end of the dogs against the core. The bottom
ends of the dogs then move out and slightly up so they no longer can engage the
fishing neck. The wireline tools are then pulled from the well bore, and the tool is
re-pinned.

Pinning Procedure

1) Turn the shear pin cap and uncover the shear pin ends. Tap the side of the
pulling tool. The sheared ends will fall out.
2) Use a core puller to pull the core down until the sheared pin is in line with the
hole in the skirt.
3) Drive the sheared pin out and insert a new shear pin.
4) Turn the shear pin cap 90°.

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WS-307-F TYPE S PULLING TOOL

Design Principle

The S series pulling tool is devised to shear by jarring down. Like the R series pulling
tool it engages the standard external fishing neck. One point to remember is that the
core must impact against something solid to make the tool shear. The two core lengths
available for the S series pulling tool are a B and an S core. Basically the S and R
series pulling tools have the same reach.

Operating Principle

The S type pulling tool normally is not used unless a subsurface device is unusually
hard to pull. Because of the shearing condition of the S series pulling tools the operator
must be positive he would be able to shear. off the fish. For the S type pulling tool to
shear, the impact has to travel down the fishing neck and through the skirt. There must
be at least 9.5 mm clearance below itself, although this can be overcome with a double
shear down adapter.
The core then impacts against the fish which drives it upward cutting the shear pin in
two places. The spring forces the core to lift the dogs slightly and drive the tapered
upper ends of the dogs under the edge of the windows they are stuck into. This
squeezes the dogs against the core and the lower ends of the dogs kick out from the
fishing neck freeing the pulling tool.

Pinning Procedure

1) Clamp the pulling tool in the vice on the skirt.

2) Turn the sleeve until the windows expose the sheared pieces of shear pin.
3) Install the core puller in the core.
4) With the back up plate against the skirt pull the core down approximately 13 mm.
5) Turn the core and align the sheared pin with the holes.
6) Drive the shear pin out.
7) Install a new shear pin. Remove the core puller. Turn the sleeve 90 o to cover the
shear pin. The pulling tool is ready for service.

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WS-307-G TYPE SSJ PULLING TOOL

Design Principle

This pulling tool consists of two assemblies. One is the SO double shear-down adapter
and the other is a standard Otis type SJ pulling tool without the fishing neck. When
assembled and shear pinned the SO shear-down adapter holds the core down the
same way the normal shear pin does.

When the shear pin in the SO adapter is sheared by jarring down the core extension
moves down releasing the lock segments. This allows the SJ core spring to move the
core and locking sleeve up and releases the dogs. This SO double shear-down adapter
will shear by jarring down as long as the tool has a solid object to contact.

Operating Principle

The primary use of the SSJ type pulling tool

is to run and pull the Otis type X, S and N
test tools by the standard wireline method.
The long reach of the SSJ allows the drop
valve of the test tool to move off seat during
the setting procedure. The double
shear-down adapter converts the Otis type
SJ pulling tool to a shear-down tool whether
the core or the skirt makes contact.

In the setting process of the test tool with an

SSJ pulling tool, the skirt makes contact
with the body of the test tool and will not
damage the drop valve or seat.

Pinning Procedure

1) Clamp the skirt in a vice.

2) Install a pulling tool core pulley in the
threaded core.
3) Pull the core down approximately
13-16 mm.
4) Turn the retainer ring to expose the
sheared pieces of the shear pin.
Remove the sheared pieces and in
particular drive the piece in the core
extension out.
5) Push the fishing neck, core extension,
locking segments, spring and locking
sleeve down until the fishing neck hits
the housing. Pull the fishing neck and
the core extension back out to the
extended position.
6) Install a shear pin and turn the
retainer ring 90°.

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WS-307-H TYPE J SERIES PULLING TOOLS

Design Principle

The Camco J series pulling tools are designed to engage an external fishing neck,
and shear to release by upward or downward jarring. The J series pulling tool has five
different types namely JUC, JUS, JUL, JDC and JDS. The JUC uses a long core, JUS
uses a medium core, and JUL uses a short core, JDC uses a long core and JDS uses
a medium core and shears down to release.

Any of these tools may be changed simply by changing the cores. The tools can be
adopted with different core lengths which enable the tool to retrieve subsurface devices
with fishing necks of different lengths of reach.

Operating Principle

The designation of the pulling tool letters are as follows:

J Jar
U UP
D Down
C Medium Reach
S Short Reach
L Long Reach

The operating sequence for the JU pulling tool is as follows.

Jar impacts travel through the fishing neck through the core, the shear pin and to the
skirt which supports the dogs. When the JU pulling tool shears, the fishing neck and
core moves up. The large end of the core contacts the pawls taking the collet dogs. In
moving up they contact an inclined part of the skirt and are forced outward. This
outward movement disengages the lugs of the dogs from the fishing neck.

The operating sequence for the 2" JD pulling tool is as follows. The jar impact travels
through the fishing neck and skirt which supports the dogs. If for any reason the
operator needs to release the JD pulling tool from the sub-surface assembly the
operator can jar down. This will shear the pin and release the assembly being jarred
on.

In the jarring down procedure in which the top of the assembly latched by the JD
pulling tool is against the bottom of the core. The jarring down impacts are transmitted
from the wireline tools to the skirt through the shear pin and up the core. When the
shear pin is sheared, the core spring moves the core up and the large end of the core
contacts the pawls The pawls move up also taking the collet dogs up as well. In moving
up they contact an inclined part of the skirt and are forced outward. This outward
movement disengages the lugs of the dogs from the fishing neck.

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1.114" & 1.3I8" J Series Pulling Tool - Pinning Procedure

1) Clamp the spring retainer in the vice.

2) Unscrew the fishing neck.
3) Drop a nut or piece of round stock 19 mm OD by approximately 16 mm in length
into the fishing neck. Not all cores are threaded.
4) Remove the shear pin cover and tap the sheared pieces of shear pin out of the
spring retainer.
5) Screw the fishing neck onto the spring retainer using it to push the core down.
Align the shear pin holes in the spring retainer.
6) Use a pin punch to knock out the sheared pin. Install a new shear pin.
7) Unscrew the fishing neck and drop out pieces of round stock.
8) Replace the shear pin cover.
9) Install the fishing neck and tighten.

J Series Pulling Tool - Pinning Procedure

1) Clamp the fishing neck in the vice.

2) Screw core puller stem into the equalising prong box in the end of the core.
3) Screw core puller flange up against the bottom of the skirt and pull the core down
approximately 3 mm.
4) Pull the dog spring back and knock the sheared ends of shear pin out of holes.
5) Align the shear pin holes in the skirt with sheared pin and drive it out with a
punch.
6) Install a new shear pin and remove the core puller.

NOTE: The above instructions are for the JU and the JD series pulling tools. The
operating sequence for the 1.1 / 4" and 1.3 / 8" JD pulling tool is exactly the
same as that for the larger size pulling tools except that there is a
cross-over sub between the fishing neck and the skirt called a spring
retainer.

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WS-307-I TYPE B PULLING TOOL

Design Principle

The B type pulling tool is designed to work in very special situations. These situations
include small pieces of junk around an external fishing neck, sand build up around the
dog or slip carrier, a short length of wire sticking out of a rope socket or when a slip
carrier on a B lock does not retract enough. The B pulling tool is strictly a shear-up
releasing tool.

Operating Principle

The B pulling tool consists mainly of a fishing neck, cylinder, core and three dogs. The
dogs pivot against the inside lower end of the cylinder. The core can move 9.5 mm
vertically in the cylinder when the shear pin is removed. It is the up-and-down
movement of the core combined with the spring pressure against the dogs, that make
them move inward and outward.

When the pulling tool is pinned correctly, the dogs can move outwardly against the
force of the spring to pass over and engage the fishing neck of any sub-surface control.
Downward jarring passes straight through the fishing neck to the core and mandrel of
the lock.

Upward jarring is transmitted through the fishing neck, cylinder, shearing pin, core and
onto the dogs. This tool is fairly easy to shear, because of its 5 mm shear pin. One or
two moderate blows up are sufficient to shear the pin and release the pulling tool from
the fishing neck. When the cylinder and fishing neck move up, the pivot point of the
dogs changes and causes the engaging end of the dogs to move out into a release
mode.

“B” Series Pulling Tools

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WS-307-J RUNNING & EQUALIZING PRONGS

Design Principle

Running prongs are designed to the particular specifications required by a specific

assembly. They are normally intended for several purposes:
1) To hold an equalizing device open to simplify running different assemblies.
2) To keep locking members in an unlocked mode while running.
3) To shift parts for positive locking assurances in profile.
4) As indicators for verification of certain movements of parts in assemblies.
5) To open equalizing devices in downhole assemblies.
6) For unlocking some assemblies.

Operating Principle

Use of the running prongs is generally in combination with a running tool. Screwed in a
box tapped in the bottom end of the running tools, the prongs will generally hold an
equalizing device open or will allow it to close when the prongs are withdrawn from the
assembly. The reason for holding the equalizing device open is to permit fluid passage
through an assembly when the seal assembly is moving through the polished bore area
in a landing nipple.

Pulling Equalising Prongs

Design Principle

Pulling prongs are designed for moving, shearing or puncturing equalising assemblies
in various down hole pressure control assemblies.

Operating Principle

In some wireline operations different assemblies like plugs, test tools, isolation
assemblies, sliding sleeves and separation tools, must be equalised by the same
method. This is done before attempting to pull or unlock the assemblies.

This is accomplished by making up an

appropriate equalising prong into the
pulling tool core. The tool is then run down
hole carefully until the bottom hole control
is located with ease. The prong is tapped
through to open the equalising valve.
During the tapping operation the change
in tubing head pressure is observed at
surface. The pressure gauge is usually
fitted on the lubricator bleed-off valve.
When the wireline operator is fully
satisfied that the down hole control is fully
equalised it can then be latched and
retrieved.

In cases where a lateral type equalising

device is in the assembly. The operator
will have to jar down a couple of turns to
move the spool down and expose the
equalising holes.

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E OR
PRONG A B C D
THREADS
2 3/8” X RUNNING PRONG 4-15/16” .960” .740” ½” N.C.

2 7/8” X RUNNING PRONG 5-5/32” 1.335” 1.086” 1.207” 5/8” N.C.

2 7/8” R “ “ 5/8” N.C.

3” X RUNNING PRONG 5.540” 1.713” 1.492” 1.616” ¾” N.C.

2” ‘P’ PRONG 60” .975” .870”

2 ½” ‘P’ PRONG 60” 1.320” 1.245”

3” ‘P’ PRONG 60” 1.725” 1.495”

2 3/8” ‘PX’ PRONG & CATCHER 44-1/2” 1.835” .875” 2” ‘G’

2 7/8” ‘PX’ PRONG & CATCHER 44-1/2” 2.000” 1.010” 2 1/2” ‘G’

3” ‘PX’ PRONG & CATCHER 43” 2.000” 1.490” 3” ‘G’

2” X EQUALISING PRONG .965”

2 1/2” X EQUALISING PRONG 12-13/16” 1.335”

3” X EQUALISING PRONG 12-7/8” 1.715”

‘DK’ PULLING PRONG 45-7/8” 1.687” 1.250” .9375”

‘DK’ PULLING PRONG 50-3/4” 1.906” 1-11/16” 1.000”

‘DK’ PULLING PRONG 56-3/4” 3.000” 2.625” 2.000”

XOB-7 PULLING PRONG 65” 1.910” 1.440”

2”SEPARATION TOOL RUN PRONG 23-3/16” .960”

2” SEPARATION TOOL PULL PRONG 33-3/4” .965”

2 1/2” ‘XO’ SEP. TOOL RUN PRONG 26-3/16” 1.335”

2 1/2” ‘XO’ SEP. TOOL PULL PRONG 36-1/8” 1.335”

2 1/2” ‘XO’ SEP. TOOL RUN PRONG 29-3/16” 1.335”

2 1/2” ‘XO’ SEP. TOOL PULL PRONG 39-1/8” 1.335”

3” SEP. TOOL RUN PRONG 31-1/4” 1.713”

3” SEP. TOOL PULL PRONG 42-1/2” 1.715”

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CHAPTER 8
PRODUCTION WELL SERVICES OPERATIONAL
PROCEDURES
TABLE OF CONTENTS

WS-308-A BDK PULLING TOOL ......................................................................................2

WS-308-B P.C.E. UNIVERSAL PULLING TOOL .............................................................3
WS-308-C BDK HEAVY DUTY PULLING TOOL .............................................................7
WS-308-D P.C.E. HEAVY DUTY PULLING TOOL ........................................................10
WS-308-E PETROLINE HEAVY DUTY PULLING TOOL ..............................................12

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WS-308-A BDK PULLING TOOL

Description

The B.D.K Pulling Tool is designed for running and retrieving down hole flow control
devices with external fishing necks. Incorporated in the design is a feature that allows
the tool to be used in very heavy wireline operations. With the Pulling Tool in the
latched position, the dogs are supported within the skirt of the tool. This allows the
operator to continue heavy jarring without the fear of shearing the dogs. For surface
operation the dog assembly has a finger grip to enable the tool to be manually released
from the fishing neck whilst in the pinned position. The tool can be converted from a
Shear-up Tool to a Shear-down Tool by changing the fishing neck and is available with
the standard reach cores: short, medium and long.

Maintenance

It is recommended to strip the pulling tool down completely after each operation.
Always check the Shear Pin after each run and replace if any signs of pre-shear are
visible.

15 1 Cylinder
14 1 Dogs
13 1 Pawls
12 1 Spacer
11 1 Dog Spring
10 1 Shear Pin
*
9 1 Shear Pin Retainer
8 1 Grubscrew
*
7 1 Core Spring
6 1 Core (Extra long reach)
Core (long reach)
Core (medium reach)
Core (short reach)
5 1 Core cap
4 1 Grubscrew
*
3 1 Grubscrew
*
2 1 Top sub shear (thread connection)
Top sub shear down (QRJ)
1 1 Top sub shear up (thread connection)
Top sub shear up (QRJ connection)
ITEM QTY DESCRIPTION

* NOTE:-
REDRESS KIT CONSIST OF THE
FOLLOWING ITEMS
3,4,8 AND 10

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WS-308-B P.C.E. UNIVERSAL PULLING TOOL

Introduction

The P.C.E. Pulling Tool can be converted from a shear up to

release tool (Camco type ‘JU” tool or Otis type ‘R’ tool), to shear
down to release tool (Camco type ‘JU’ tool or Otis type ‘S’ tool)
without the need for two separate tools or for any additional
cores or parts.

The P.C.E. Pulling Tool has a universal core which allows the
same tool to be able to retrieve devices with external fish necks
of different lengths or reach; i.e. the P.C.E. Pulling Tool core can
be adjusted to short, medium or long reach.

The P.C.E. Pulling Tool is available in 1.25”, 1.50”, 2.00”, 2.50”,

3.00” and 4.00” nominal sizes for either standard or H²S service.

Operation

1. Disassembly Procedure
2. Assembly Procedure
3. Conversion of Tool (Shear Mode)
4. Selection of Core Reach
5. Shear Pin Installation
6. Maintenance

Tools Required

Tommy Bar 3/16” x 12” long for 1.25” and 1.50” tool
Tommy Bar 5/16” x 12” long for 2.00” and 2.50” tool
Tommy Bar 3/8” x 12” long for 3.00” and 4.00” tool
Adjustable Wrench
Standard Core Pulling / Repinning Tool Vice
3 off 1/8” Pin Punches or 1/8 » Roll Pin

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Description

By reference to the accompanying drawings-the P.C.E. Pulling Tool is convertible,

without the need for special tools or additional parts, from:

Figure 1: Shear Down to Release Tool.

Figure 2: Shear Up to Release Tool,

When in-the shear-down to-release mode the tool is attached to a conventional wireline
work string via the threaded fish neck (1). A downward jar action is then transmitted via
the upper cylinder (4) to the shear pin (10). An equal and opposite upward force is
applied via the subsurface device and the core (8) to the shear pin (10), causing the pin
to shear. This then releases the energy in the coil spring (7) which drives the core (8)
upwards. As the core moves upwards its lower shoulder engages the base of the pawls
(15). The pawls move upwards and in turn pull the dogs outward, thus allowing the tool
to release from the subsurface device. To convert this same tool to the shear up to
release mode (see instructions in later chapter) unscrew in a clockwize direction the
thread on the fish neck (1) and the upper cylinder (4) and re-engage and tighten the
inner thread on the fish neck (1) and the mating thread on the top of the core (8) and
lock in place with captive alien screw.

When in the shear up to release mode (Figure 2). The tool is attached to a
conuentional wireline work string via the threaded fish neck (1), an upward jar action is
then transmitted via the core (8) to the shear pin (10), against the dogs (12) which
when latched to the subsurface device, bottom out within the lower cylinder (16).

The shear pin (10), which pins the core (8) to the lower cylinder (16) will shear and this
will release the energy in the coil spring (7) and cause the core (8) and the top sub (1)
to move upwards. As the core moves upwards its lower. shoulder engages the base of
the pawls (15). The pawls move upwards, an inclined surface in the vertical opening of
the lower cylinder (16) drives the dogs outwards thus allowing the tools to release from
the subsurface device.

To achieve the full flexibility of the P.C.E. Pulling Tool a multi position core is supplied,
as standard, which will give a choice of 3 reach settings for each tool either the upward
and downward shear to release mode (3 position core).

An alternative 2 reach-core is also available to ensure that the P.C.E. Pulling Took
cannot he run without major modification in a Long Reach Shear Down position in
which it would prove impossible to release from a conventional fishing neck. This
inability to release from along reach shear down tool also applies with a Carrico type
'JDL'.

The 2 reach core has been manufactured to enable the operator, if necessary, to
convert the core to a long reach by removing the core from the pulling tool and cutting
with a hacksaw along a specially prepared machined groove on the larger o.d. of the
core. After cutting the 2 reach core can only be used in the long or immediate reach
dimension.

NOTE The new intermediate reach does-not correspond exactly to the mediurn,
reach setting specified with the standard 3 reach core.

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Shear Down to Release Mode

1. Ensure that the core is fully retracted, place tommy through the assembly assist
hole in core (8) at 90 degrees to shear pin hole in lower cylinder (16).
2. Ensure that the captivated locking grub screw (3) in the fish neck sub (1) is
backed in the 'redundant' position against the shoulder such that it will not
interfere with the core when the tool is ultimately sheared.
3. With the fish neck sub (1) engaged in the upper cylinder (4) thread, (Shear Down
Mode), tighten fish neck (1) against upper cylinder (4) shoulder by turning
anti-clockwise.
4. By using two adjustable wrenches, torque until tight.
5. Check that lower cylinder (16) to upper cylinder (4) thread is tight by applying
torque, via adjustable wrench, on the lower part of the upper cylinder and the
tommy bar inserted through lower cylinder (16) and core (4).
6. Remove tommy bar and screw P.C.E. Pulling Tool on standard core puller in
order to set core length. Having determined reach required insert shear pin.

Shear Up To Release Mode

Ensue that the core is fully retracted, place tommy bar through the assembly assist
holes in core (8) at 90 degrees to the shear pin hole in the lower cylinder (16).

1. Ensue that locking grub screw (3) in the fish neck sub is backed out against the
shoulder, in the 'redundant' position. See diagram.
2. By gripping the upper cylinder (4), screw fish neck sub (1) clockwise until it
engages the core thread shoulders out. (The twin ring and marking on the fish
neck sub (1) will have now disappeared within the upper cylinder).
3. Apply torque to the tommy bar and the fish neck sub using an adjustable wrench
on the flats provided to tighten fish neck to core.
4. Screw in and lock captivated grub screw (3) into-recess provided on core (8).
5. Check that the lower cylinder (16) and upper cylinder (4) thread is tight by aplying
via an adjustable wrench on the lower part of the upper cylinder (4) and the
tommy bar inserted through the lower cylinder and core (8).
6. Remove tommy bar and place P.C.E. Pulling Tool on standard core puller.

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WS-308-C BDK HEAVY DUTY PULLING TOOL

The BDK Heavy Duty Pulling Tool is designed for running and retrieving down hole
flow devices. The tool is based on a comet to give maximum coverage of the fishing
neck and features unique supports between the collet fingers. The supports centralise
the fishing neck preventing it hanging on the collet fingers even in highly deviated
conditions. A full sleeve both supports the collet and gives the tool a clean profile.

Maintenance

It is recommended to strip the Pulling Tool down completely after each operation.
Always check the Shear Pin after each run and replace if any signs of pre-shear are
visible.

Assembly – Shear Up Mode

1 Install Core Spring (7).

2 Make up Top Cap (17) hand tight into Spring Housing (6).
3 Make up to Top Sub (16).
4 Secure with Grub Screw (4) through the aligning Slots provided in Top Cap (17)
and Spring Housing (6).
5 To insert Shear Pin (3), back off Top Cap (17) until Shear Pin holes in Top Cap
(17) and Top Sub (16) line up.
6 Insert Shear Pin (3).
7 Remove Punch.
8 Using flats on Top Cap (17) make up Top Cap (17) and Top Sub assembly onto
Spring Housing (6) and secure with Grub Screw (5).
9 The tool is now ready to use.

Assembly – Shear Down Mode

1 Install Core Spring (7).

2 Make up Core Cap (3) onto Core (8) and secure with Grub Screw (4) through slot
in Housing (6).
3 Slide Top Sub (1) over Core Cap (3) and engage into Spring Housing (6).
4 Thread Top Sub (1) into Spring Housing (6) until Shear Pin holes in Top Sub (1)
and Core Cap (3) line up.
5 Insert Shear Pin.
6 Remove punch.
7 Make up Top Sub (1) to Spring Housing (6) and secure with Grubscrew (5).
8 The tool is now ready to use.

To Re-pin after Shear (Shear Down)

1 Remove Grub Screw (5) from Spring Housing (6).

2 Back off Top Sub (1) until broken Shear Pin is visible.
3 Remove broken Shear Pin.
4 Continue to back off Top Sub (1) until Shear Pin hole in Top Sub (1) aligns with
Shear Pin hole in Core Cap (3).
5 Using punch, punch out remaining Shear Pin.
6 Insert new Shear Pin (2).
7 Make up Top Sub (1) to Spring Housing (6) and secure with Grub Screw (5).

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To Re-pin after Shear (Shear Up)

1 Remove Grub Screw (5) from Spring Housing (6).

2 Back off Top Cap (17) until broken Shear Pin is visible.
3 Remove broken Shear Pin.
4 Continue to back off Top Cap (17) until the Shear Pin hole in Top Cap (17) aligns
with Shear Pin hole in
5 Top Sub (1).
6 Using Punch, punch out remaining Shear Pin.
7 Insert new Shear Pin (2).
8 Make up Top Sub (1) and Top Cap assembly (17) to Body of Tool and secure
with Grub Screw (5).

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WS-308-D P.C.E. HEAVY DUTY PULLING TOOL

Introduction

The P.C.E. Heavy Duty Pulling Tool is a collet type Pulling Tool designed to latch and
retrieve wireline tools that have badly damaged fishing necks.

The Heavy Duty Releasable Pulling Tool is extremely robust in construction and allows
a full 360 degrees of engagement with the fishing neck to be latched. The tool can be
released by jarring downwards provided a solid footing is available for the core to be
driven against.

The P.C.E. Heavy Duty Pulling Tool is available to latch 7/8", 1", 1 1/8", 1 3/16", 1 3/8",
1 3/4", 2.313" and 3.125" o. d. fish necks.

Inspection of Parts

All component parts making up the assembly should be inspected for identification and
condition. Where required, work order numbers shall be recorded on the component
parts list prior to assembly. Special care must be exercised when drawing small
unmarked items (e.g. O-Rings and Set Screws) so as to ensure that only the specified
items are issued - where necessary such parts should be placed in clearly marked
bags.

Lubrication

The threads of the main body parts should be lightly oiled immediately prior to
assembly.

Maintenance

The P.C.E. Heavy Duty Pulling Tool has been designed to give long and reliable
service. However, it is strongly recommended that the tool should be thoroughly
cleaned after use to prevent the build up of deposits, which could interfere with the
operation of the tool. This is particularly important when the tool has been used in a
corrosive environment.

Re-pinning Procedure

1. Remove Set Screw (8) from Shear Sub (2).

2. Place Shear Sub (2) in vice and break out Fishing Neck (1).
3. Rotate Shear Pin Retainer (7) and remove shear pin stubs.
4. Place Pinning Tool (B 118-012) vertically in vice and screw on Pulling Tool.
5. Rotate tool until assembly assist hole is visible and insert 3/16" punch.
6. Remove Cap Head retaining screw (if fitted) (8) and the core cap (4)
7. Remove snap ring (3) from core cap (4).
8. Remove Cap Head retaining screw (if fitted) (8) and the core cap (4)
9. Relieve tension from punch and remove.
10. Rotate 90 degrees and pull core down to reveal sheared pin, knock out sheared
pin from core.
11. Re-pin the tool with 3/16" brass or mild steel pin.
12. Place snap ring (3) with internal chamfer down onto core cap (4).
13. Tighten up Fishing Neck (1) by hand until resistance is felt. remove assembly from
Pinning Tool.
14. Tighten Fishing Neck (1).
15. Check reach to ensure tool is correctly pinned.

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Test - Operational Preparation

1. Screw link jar (B057-010) to Fishing Neck (1). Latch test piece fishing neck (1)
into pulling tool, stand assembly on solid base and jar down to release. Ensure
test fishing neck releases cleanly.

Note: Tool can only be released by either removing or shearing pin (6).

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WS-308-E PETROLINE HEAVY DUTY PULLING TOOL

The Petroline Heavy-Duty Pulling Tool has been designed to increase the contact
area against the external fishing neck, and therefore spread the load during heavy-duty
fishing operations. This reduces the chance of damage to the fishing neck.

The 50% contact area of conventional pulling tools is shown in the diagram below,
compared to the 95% area of contact of the heavy-duty pulling tool:

The core is deigned to permit latching of fishing necks with and without threads. (i.e.
The equivalent of the Otis 'B' and 'S' cores, and Camco 'C' and 'S' cores.)

Downward jarring shears the pin and pushes the finger core upwards to latch into the
release collet. This keeps the finger core expanded until the disassembly tool is
inserted at the surface to retract the release collet, and retract it from the finger core.

Resetting Procedure

When the tool is in the sheared /

released position:

(i) Remove the "grub screw" (8)

and back out the "top sub" (5)
and "spring" (7).
(ii) Insert the disassembly tool by
threading it into the top of the
"release collet" (3).
(iii) Apply force by rotating the
pressure plate of the
disassembly tool until the
"release collet" (3) comes free of
the "finger core" (4).
(iv) Align the finger core with the
shear pin holes and remove the
old pieces of shear pin.
(v) Insert a new shear pin.
(vi) Remove the disassembly tool
and insert the spring.
(vii) Make up the top sub and replace
the grub screw.

PETROLINE HEAVY DUTY PULLING TOOL

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BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

CHAPTER 9
STANDARD WIRELINE OPERATIONS
TABLE OF CONTENTS

WS-309-A RUNNING AND SETTING ............................................................................. 2

WS-309-B TYPE XOF BALL VALVE ............................................................................... 5
WS-309-C TYPE DK BALL VALVE.................................................................................. 7
WS-309-D OB-7 FLAPPER VALVE (CAMCO) ................................................................ 9
WS-309-E TYPE FXE FLAPPER NSERT VALVE (OTIS) ............................................ 11
WS-309-F TYPE FXVH FLAPPER INSERT VALVE (BAKER) ..................................... 13
WS-309-G TYPE KX AMBIENT VALVE (OTIS) ............................................................ 18
WS-309-H TYPE QOP FLAPPER VALVE (OTIS) ......................................................... 20
WS-309-I TYPE QOS FLAPPER VALVE (OTIS) .......................................................... 22
WS-309-J TYPE MCX INJECTION VALVE (OTIS) ....................................................... 23
WS-309-K TYPE RQ LOCK MANDREL ........................................................................ 25
WS-309-L RUNNING AND PULLING OF OTIS “XX AND XXN: PLUGS ..................... 29
WS-309-M RUNNING AND PULLING OF OTIS “PX” AND “PXN” PLUGS .................. 31
WS-309-N RUNNING AND PULLING OF OTIS “RR” AND “RRN” PLUGS ................. 33
WS-309-O RUNNING AND PULLING OF OTIS “PR” AND “PRN” PLUGS .................. 34
WS-309-P RUNNING OF CHECK SET TOOL .............................................................. 35
WS-309-Q RUNNING AND PULLING OF HAALIBURTON RPT PLUG ....................... 36
WS-309-R RUNNING AND PULLING OF BAKER “AFH” SUR-SET PLUG ................. 40
WS-309-S RUNNING AND [ULLING OF SEPARATION TOOL ................................... 45
WS-309-T RUNNING AND PULLING OF STADDLE TOOL ......................................... 48
WS-309-U ZONE CHANGE OPERATIONS .................................................................. 50
WS-309-V DUMP EQUALISING VALVE ASSEMBLY .................................................. 51
WS-309-W RUNNING A DRIFT CUTTER. AND SCRATCHER ................................... 55

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WS-309-A RUNNING AND SETTING

Before running a surface controlled subsurface safety valve, make sure all the shear
pins in the lock and the running tool have been properly installed. Run the wireline work
string with the safety valve attached to about 5 m above the landing nipple.

Check out the surface control system to determine if it is controlling other wells besides
the one being worked on. If so, isolate the other wells by closing the control line valves
at the Xmas trees. Now, the control line valve is opened on the well being worked on.
Pump into the control line long enough to displace the volume of the control line or at
least for three minutes.

Stop the control line pump and lower the safety valve to the landing nipple. Start jarring
down easily until the lower packing stack on the valve passes through the upper
polished bore of the nipple. The safety valve should drop about eight inches (20 cm).
Continue jarring down easily until the keys locate in the locking profile of the landing
nipple.

Note: The "X" and the "R" running tools are already in the control mode. This is a
standard procedure for the top landing nipple. The one exception to this is the
4.125" OD lock which has a no-go shoulder right below the locating and locking
keys.

When the jarring down sound change to a metal-to-metal impact, bleed down control
line to zero to confirm valve in place; start jarring down harder to physically shear the
pins, and lock the dogs in their locking recess.

Pressure up on the control line to ensure the packing stacks are holding and to open
the flapper or ball to free the running prong. When satisfied valve holding control line
pressure, jar up to release running tool from the safety valve.

Note: All jarring for setting or pulling SC-SSSV,s shall be done by hand, NEVER
attempt to use the wireline unit for jarring at a shallow depth.

Not all SC-SSV,s in the field are equipped with an Interference lock
although this will be accomplished in due course. For valves with regular
X-lock mandrels, a Check-Set tool needs to be run to confirm the proper
setting and locking of the mandrel. Partially set valves might vibrate loose
and be blown up the hole. This Check Set tool run is not required for the
interference lock due to its improved design. (Ref:WS-309-P)

With the work string out of the well and the swab valve closed, bleed off the control line
pressure to zero pressure. Open swab valve half way. Bleed off the tubing pressure
above the safety valve to manifold pressure, close flowline valve or Willis choke and
observe pressure build-up in the tubing , (Allowable leak rate: 350 kPa in 15 minutes).

After the leak-off test has been successfully completed, equalize and open the valve
according to the following procedure.

Note: The DK, XOB-7, FXE, QOP and QOS safety valve each have an equalizing
feature. The XOF and FXVH have no equalizing feature and will be explained
separately.

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With the flow line valve closed and a pressure gauge made up in the lubricator bleed
off valve, start pumping into the control line and observe the pressure build-up above
the safety valve. Equalization should take from three to ten minutes depending on the
setting depth of valve and ID of the tubing. Once equalising has started, pumping into
the control line must stop until complete equalization has been achieved After the
valve has opened, the control line pressure is built up to about 7000 kPa above the
shut-in well pressure.

If any other wells are controlled by the same control unit through a manifold system,
each well control line pressure should be checked and brought up to high pressure
level of the control unit before being admitted to the control manifold system.

XOF and FXVH.

After the leak-off test has been completed on the XOF, the control line pressure is built
up slowly in stages to ensure the ball is rotated just enough to start equalizing the
tubing above the XOF. At this point stop pumping , further increase in pressure could
seriously damage or break the control arms for the ball.
For the FXVH it is preferred to equalise the differential pressure with pressure from an
other well prior to pulling. Refer to WS-309-F and WS-319-A for more details.
When the tubing pressure has been equalized the control line pressure is increased to
finish opening the ball and bring the control line pressure to 7000 kPa above its
opening pressure.

Pulling.

Attach the proper prong to the "GR" pulling tool and make up the "GR” to the work
string.

1) Run the tools down to the safety valve depth.

2) Engage the "GR" to the safety valve. Note: Ensure safety valve is open prior to
engaging the lock mandrel by inflow testing the valve. Pick up on the tool string to
check if the "GR" has latched the fishing neck of the valve assembly. If the "GR"
is latched the ball or flapper must be open or clear. Bleed down the control line
pressure to THP. Jar down on the Lock mandrel to drive it down and free the
keys and packing.
3) Upward jarring unlocks the assembly and the valve is pulled out of the landing
nipple and pulled to the surface. If the pin in the GR shears prematurely, pull out
and run a GS with prong.
4)
Alternative pulling method.

In cases where a SCSSV is closed and cannot be opened by pressuring up the control
line, the tubing above the SCSSV will have to be pressured up either by equalizing
from another well (with an equalizing hose or a length of ¼” or 6 mm SS tubing) or
using a high pressure pump.

Pressure above the SCSSV must be at least equal to or slightly higher than the
pressure below the valve to prevent getting blown up the hole when the locking keys
are released.

When using an equalizing hose or a piece of ¼” contol line to open a valve, make sure
that the pulling tool and prong are allready in the lubricator and swab valve is open.
Pressure from an other well or pump will give a rapid increase of

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pressure above the valve due to the relative small volume of tubing to be filled up.Once
the build up slows down or stops, it can be assumed that the pressure across the valve
is equalized. Run in the hole with the pulling tool and latch on to the valve.

Note: For pulling a Flapper type valve, the prong can be run on the GR since ,once
pressures are equalized, the flapper is very easily pushed off seat. For Ball type
safety valves the pulling prong cannot be run as the ball is only “cracking open”
to allow pressure to be equalised. It would therefore be advisable to continue
equalising through the HP hose or ¼” SS control line while latching on and
pulling the valve from the nipple.

The Interference lock as discussed on page 1, is an upgraded / improved design of a

regular X-lock mandrel.
The difference, as shown in detail in the picture below, consists off a ”build up” or
“ridge” machined on the outside of the Packing mandrel and a recess cut in the bottom
of the Expander mandrel.When setting the lock, downward jarring will force the
expander sleeve over the ridge and provide an extra locking feature to prevent the lock
from becoming unlocked due to vibrating at high flow rates.

NOTE: When installing insert valves in Tubing Retrievable

Safety Valves, bear in mind that the distance
between packing stacks on the wireline retrievable
insert valve is considerabely longer than on the
regular SC-SSV.

This fact, combined with the higher weight due to its

length, can create problems when tapping the bottom
packing stack of the valve through the upper seal bore.
Once tapped through, the valve will drop a distance longer
than the stroke of the jar and could shear the bottom
brass pin in the running tool. The valve cannot be set
properly and has to be retrieved. It is good practice to
install a steel pin in this case, to avoid any unnessecary
problems.

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WS-309-B TYPE XOF BALL VALVE

Design Principle

The XOF ball valve is a wireline retrievable surface controlled subsurface safety valve.
It is designed to shut in a well in an emergency situation and contain the well pressure
below the surface.

The XOF is a non-equalising valve consisting of a housing which contains a ball, upper
and lower seats, a piston, control arms and springs. The ball is mounted between the
upper and lower seats in such a manner that when the spring moves the control arms
upward, the ball is rotated on its own axis to a closed position perpendicular to the axis
of the seat. When the piston is forced downward by control line pressure it pushes the
control arms down and rotates the ball 90° to its open position.

Operating Principle

The XOF valves are located and locked in a ported S4 nipple. The ported nipple is
connected by a 6 mm control line to pre-set hydraulic pressure source at the surface.
When the ball valve is properly set in the nipple the packing stacks seal against the
polished bore of the nipple above and below the port.

Hydraulic pressure introduced through the control line acts against the piston forcing it
downward against the spring force. As the piston, spring and control arms move
downward. The ball is rotated 90° to a full open position.

When the hydraulic pressure is released, the spring below the lower seat, assisted by
well pressure forces the control arms, spring and piston upward and rotates the ball to
its closed position. Being a normally closed valve, the XOF is held open in the flowing
mode by one of three sources shown below.

• The Axelson Control- O-Matic.

• The Otis well control unit.
• The Autocon well control unit.

The following surface interruption will cause the valve to close.

• Loss of pressure in an ESD loop in an emergency situation.

• Loss of power supply to the control unit.
• The manually operated well shutdown valve handle on the panel is depressed.
• Loss of system hydraulic pressure.
• Sudden extreme change in the flow line pressure.

For running and pulling procedure; refer to WS-309-A

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WS-309-C TYPE DK BALL VALVE

Introduction

There is one type Otis DK surface controlled subsurface safety valve presently in use,
which is the 2.750 “ OD valve. The former 2.562” OD and the 4.125” OD DK valves
have since been replaced by Flapper Valves which have a larger bore, thus higher flow
rates can be achieved.

Design Principle

The DK Ball Valve is a wireline retrievable surface controlled subsurface safety valve. It
is designed to shut in a well in an emergency situation and contain the well pressure
below the surface. The DK valve has a built-in equalising feature and by admitting
hydraulic pressure from the control unit on the surface in the piston chamber area puts
the valve in an equalising mode. This equalising feature protects the ball anc seat from
damage that can occur if the ball is rotated under high differential pressure.
All valves with an equalising feature have a secondary seat. The primary and
secondary sealing surfaces of the DK valve are metal-to-metal type seats. After
equalisation is complete the ball is rotated to its normal open position. Being a normally
closed valve, hydraulic pressure must be maintained on the control line to keep the DK
valve open.

For running and pulling procedure; refer to WS-309-A

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OTIS ‘ DK’ BALL SCSSV

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WS-309-D OB-7 FLAPPER VALVE (CAMCO)

Design Principle

The OB-7 safety valve is a Camco B-7 safety valve adapted to an Otis lock mandrel. It
is a normally closed wireline retrievable valve. Its open/close function is controlled by a
hydraulic control unit located at surface. The functional purpose of the valve is to stop
the flow of a well in an emergency situation and contain the pressure below the
surface. This is caused by the loss of hydraulic pressure maintained in the control line
by a surface power source that is tied into the ESD system.

The flapper valve features a straight through bore with the flapper and seat completely
shielded from the flow stream. The equalising seat allows differential pressure to be
equalised across the safety valve without the necessity of pressurising the tubing
above the valve.

Operating Principle

The OB-7 flapper valve is run by wireline to a pre-determined depth. Before setting the
valve in its landing nipple the surface control unit is activated for a length of time that is
sufficient to displace fluid and any gas that might be in the control line.

The OB-7 is located and locked in the ported landing nipple and tested to make sure
the control pressure is isolated from the tubing pressure. The valve is properly tested
for closing after the wireline tools have been withdrawn from the well.
After a satisfactory test the well is put on production. Like the XOF and DK valves the
OB-7 is controlled on the surface by one of the three sources, for details refer to
procedure for XOF. Also like the XOF and DK valves any of the five possibilities that
interrupt the control line pressure will close the OB-7 valve.

For running and pulling procedure; refer to WS-309-A.

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Chapter 9, Standard Wireline Operations Page 9 of 56
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

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Chapter 9, Standard Wireline Operations Page 10 of 56
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

WS-309-E TYPE FXE FLAPPER NSERT VALVE (OTIS)

Design Overview and Principle

The Otis FXE safety valve is an equalising flapper wireline retrievable SCSSV. The
valve consist of a piston opposed by a spring which operates a flapper mechanism.
When pressure is released from the piston chamber, the spring moves the piston up
and a torsion spring rotates the flapper to the closed position. The valve has a metal to
metal seat as the primary sealing surface. The valve consists of a top sub which is
threaded to allow the make up of a lock mandrel. It is also ported to admit control
pressure from the surface. Packing on the housing seals below the port in the landing
nipple. The lock mandrel packing forms a seat above the port in the nipple. An
equalising mechanism allows pressure from below to be routed across the flapper prior
to opening.

Listed below are a few definitions concerning hold open pressure.

• Hold Open Pressure - The pressure required to maintain the safety valve in the
open condition during well production.
• Recommended Hold Open Pressure - Opening pressure + tubing pressure + (3450
kPa 6895 kPa). The values in parenthesis represents a range of additional pressure
required to offset the forces created by flow through the internal components of the
valve.
• Opening Pressure - The pressure required to fully open the safety valve under
atmospheric conditions. For the maximum allowable opening pressure for a particular
SCSSV, refer to the Engineering Data Sheet.

Attaching Lock Mandrel to Flapper Valve

5) Make up an Otis X, R or safety set lock mandrel onto the SCSSV. For X and R
mandrels follow the steps below for the running procedure of the safety set lock.
6) Make up the proper prong to the Otis X or R running tool.
7) Attach a pressure source to the port in the top sub and apply control line pressure
to open the SCSSV.
8) Record the pressure to fully open the SCSSV
9) Slowly close the SCSSV and record the pressure at which the SCSSV is fully
closed.
10) Re-open the SCSSV.
11) Insert the running tool prong through the bore of the lock mandrel and into the
bore of the SCSSV far enough to hold the flapper in the open position.

NOTE: If the SCSSV closes when the pressure is released, remove the running
tool`and prong. Check the prong for the proper length. Repeat steps 1 - 4.

For running and pulling procedure, refer to: WS-309-A.

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Chapter 9, Standard Wireline Operations Page 11 of 56
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

NOTE: When installing a FXE as an insert valve in

aTubing Retrievable Safety Valve, bear in mind that
the distance between packing stacks on the
wireline retrievable insert valve is considerabely
longer than on the regular SC-SSSV. This fact,
combined with the higher weight due to its length
(spacer tube installed between lock mandrel and
valve) can create problems when tapping the
bottom packing stack of the valve through the upper
seal bore. Once tapped through, the valve will drop
a distance longer than the stroke of the jar and
could shear the bottom brass pin in the running
tool The valve cannot be set properly and has to be
retrieved. It is good practice to install a steel pin in
this case, to avoid any unnecessary problems.

COMPONENTS

FIND NAME QTY

1 TOP SUB 2 1/4-12 SLB 2 5/16-16 1.00
2 PSTN FLP O-RING BBC-UP 9CR 1.00
3 SK-UP RING 2.258 X 2.022 4.00
4 0-RING 2.262 X 1.984 1.00
5 FEM PKG ADPT 2.803 X 2.380 X .270 2.00
6 V-PKG 2.813 X 2.364 2.00
7 0-RING 2.822 X 2.354 2.00
8 V-PKG 2.831 X 2.360 4.00
9 0-RING 2.137 X 1.859 1.00
10 PKG MDL 2 5/16-16 UNS 2 9/16-12 1.00
11 BK-UP RING 2.004 X 1.834 2.00
12 O-RING 2.005 X 1.799 2.00
13 SPG HSG 2 9/16-12 STUB AC 2 7/16-12 1.00
14 SPG 2.406 1.88 22.68 24.1 1.00
15 SPG 010 1.84 9CR 1.00
16 SEAT INSRT 2.750 FLP INC-925 1.00
17 SK-UP RING 2.428 X 2.258 2.00
18 0-RING 2.381 X 2.175 1.00
19 OPN PRNG 2.750 TNC-925 1.00
20 V SEAT 2 7/16-12 STUB AC INC-925 1.00
21 FLP SEAL 2.750 MFT 1.00
22 FLP PIN 2.813 MP35N 1.00
23 TRSN SPG 2.750 .032 ELOY 1.00
24 FLP 2.750 INC-925 1.00
25 V HSG 2 3/8-12 STUB AC FLP 9CR 1.00

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Chapter 9, Standard Wireline Operations Page 12 of 56
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

WS-309-F TYPE FXVH FLAPPER INSERT VALVE (BAKER)

DESCRIPTION AND PURPOSE

The Baker Model 'FXVH' wireline Retrievable Insert Safety Valve is a hydraulically
operated, surface controlled, non-equalizing, flapper-type, subsurface, trough tubing
retrievable (TTR) safety valve. The valve is a normally closed type, i.e. in the absence
of control chamber pressure the valve will return to the closed position, and shut-in the
well.

In the event of a Tubing Retrievable Safety Valve malfunction, the Model FXVH'
Wireline Retrievable insert can be run into the nipple adapter profile in the I.D. of the
T.R.S.V. after the malfunctioning valve has been locked open.

The packing on the Model 'FXVH' Wireline Retrievable Safety Valve straddles the
Tubing Retrievable Safety Valve from top to bottom. It uses the same control line which
previously operated the Tubing Retrievable afety Valve. Therefore, if a Tubing
Retrievable Safety Valve malfunctions a Model 'FXVH' Safety Valve can be run inside
it. This feature can prevent unscheduled workovers or maintenance.

OPERATING DATA

Item Description 3 1/2 x 2.75

A Model 'FXVH’
H Product Numbers 823-52
C Class of Service 3S2
D Rated Working Pressure (psi) 10,000
E Test Pressure (psi) 15,000
F Control Chamber Test Pressure (psi) 15,000
+G Piston Displacement (c-c.) 15
H Temperature Range (°F) 20-275
J Opening Pressure (psi) 2,500 + Shut-In Pressure
Required Minimum Control Line
K Pressure To Hold SCSSV Open 2,500 + Flowing Pressure
After Initial Opening (psi)
Maximum Fail-Safe Setting
L Depth With Salt Water In 1,020*
Control Line (ft.)
Maximum Fail-Safe Setting
M Depth With Hydraulic Fluid 1,310*
In Control Line (ft.)

* These maximum fail-safe setting depths neglect the possibility of heavier annulus fluid. If the annulus
fluid is heavier than the Control Line fluid, it must be acknowledged that should the Jontrol Line break, the
hydrostatic pressure applied to the Piston of the Safety Valve is based on the gradient of the heavier
annulus fluid. Therefore, the maximum setting depth should be reduced accordingly.

+ Piston displacement is the volume of fluid required to fully actuate the Valve. This calculated volume is a
nominal value and does not include volume changes due to:

1) Fluid compressibility.
2) Pressure induced deflection of piston chamber components.
3) Pressure induced deflection of the control line.
4) Elastomer movement during pressure reversal.

Due to the variables this value should be used as a reference only.

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Chapter 9, Standard Wireline Operations Page 13 of 56
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

Running and Pulling Procedures For Model ‘FXVH’

Since Valve is run with an Otis `X' Lock, refer to Lock manufacturer for running and
pulling procedure.(Ref: WS-309-A)

Running The Model 'FXVH' Valve

Preparation on the Rig Floor:

1) Using a pair of calipers, check the basic OD and No-Go dimensions of the Valve.
Compare the values with the well prognosis for any incompatibility.
2) Attach a Pump to the Packing Sub and slowly open and close the Valve five (5)
times. Leave Valve open.
3) Make-up the Baker Model "X" Prong, see chart for Commodity No., onto the
Running Tool. Follow the recommended Otis procedure for attaching the Prong
and Running Tool to the Oti's X Lock and for preparing the Otis X Lock to run in
the hole. Close the Valve and remove pump.
4) Pick-up the Lubricator and attach the Running Tool to the jars.
5) Before pulling the Tool string and Lock tin into the Lubricator, clean, inspect, and
grease the Chevron Packing on the Valve. Pull & Tool string and Valve up into
the Lubricator. Attach the Lubricator. Circulate Control Line fluid down the Control
Line to ensure that it is not blocked.

MODEL
"X"PRONGS

FOR 'FVHD' W/O T.L.O. FOR RUNNING FOR RETRIEVING

*** ***

*** Available upon request.

Running The Model 'FXVH' Valve:

1) Lower the Valve to within 5m of the Nipple Adapter of the permanently locked
open tubing mounted safety valve.
2) Again, circulate Control Line fluid while lowering the Valve into the Nipple Adapter
and Bottom Sub. Record the pump pressure required to circulate the control line
fluid.
3) Keep circulating Control Line fluid while jarring down to land the Valve. The
circulating pressure should ncrease once the Chevrons straddle the Control
pressure inlet area between the seal bores of the nipple adapter and bottom sub.
Once this occurs, bleed the Control Line pressure back to the original circulating
pressure recored in Step 2 and lock it in at the surface to maintain this pressure
while jarring down on the Valve until the Valve NoGoes in the Nipple Adapter and
Bottom sub.
4) Follow the recommended Otis procedure to remove the Running Tool from the
Otis ‘X’ Lock.
5) Come out of the hole.
6) Pull the Tool string up into the Lubricator. Close in the well and bleed any
Lubricator pressure.
7) Remove the Lubricator.

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Chapter 9, Standard Wireline Operations Page 14 of 56
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

Retrieving the Model 'FXVH' Valve With The Model "X" Prong

Preparation on rig floor:

1) Make-up the Model "X" Prong, see chart on page 6, onto the Pulling Tool.
2) Follow the recommended Manufacturer procedure for operation of Running Tool.
3) Pull the Tool string up inside the Lubricator.
4) Attach the Lubricator.

Retrieving. the Model 'FXVH':

1) Pressure the tubing and pump down through the valve or inflow test the valve,to
be certain that shut in pressure has been equalled and that no differential exists
across the valve. Record the pump pressure required to pump through the valve.
2) Open the Valve, then run in the hole with the Pulling Tool.
3) Lower the Pulling Tool into the Lock.
4) Once landed, follow recommended procedure to engage the pulling tool in the
Lock. Bleed the Control Line pressure to zero.
5) Jar up to unseat the Valve from the Tubing Retrievable Safety Valve.
6) Come out of the hole.
7) Pull the Tool string and Valve up into the Lubricator.
8) Close in the well and bleed all Lubricator pressure.
9) Remove the Lubricator.

Retrieving The Model FXVH Without The Model "X" Prong

Preparation on the rig floor:

1) Follow- the recommended Manufacturers procedure for preparing the Pulling

Tool to retrieve the Valve.
2) Pull the Tool string up inside the Lubricator.
3) Attach the Lubricator to the production string.
4) Proceed per step one (1) of Retrieving the Model ‘FXVH’.

Operation

Opening Procedure With No Differential Pressure Across Valve:

1) Close wing valve.

2) Pump down tubing, through the valve to be certain that no differential exists at
the valve.
Record pressure required.
3) Hold required pump pressure on tubing.
4) Apply control line pressure. Minimum pressure is 2,500 psi + shut-in pressure as
recorded in Step #2.
5) Open wing valve to flow line. Well should flow normally. Maintain Control Line
pressure at 2,500 psi + flowing well pressure (minimum).

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Chapter 9, Standard Wireline Operations Page 15 of 56
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

Opening Procedure With Differential Pressure Across Valve:

In order to reopen the FXVH with a differential pressure at the valve, the differential
must first be reduced to less than 200 psi. (However, in order to open the valve with
1500 psi control line pressure at the valve, it may be necessary to reduce the
differential across the flapper to zero psi).

The Opening Procedure is as follows:

1) Close wing valves.
2) Pressure the tubing and pump down through the valve to be certain that shut-in
pressure has been equaled or exceeded. Record this pump pressure.

Note: If for any reason Step #2 cannot be accomplished it should be acknowledged

that the valve should not be forced open with greater than 200 psi differential at
the valve.
3) Apply control line pressure of 2,500 psi + shut-in well pressure (as recorded) in
Step #2 above).
4) Open wing valves. Well should flow normally. Maintain control line pressure of
2,500 psi + well flowing pressure.

Closing Procedure:
1. Close wing valve.
2. Bleed control line pressure to zero psi.
3. Open wing valve to flow line thus bleeding tubing pressure above the valve, to
assure that the valve is closed.

Maintenance

The assembled Model "FXVH" Wireline Retrievable Insert Safety Valves should be
stored vertically in cylindrical cardboard containers. These valves can be stored
indefinitely.

Note: The Elastomeric seals in unused Valves should be replaced every five years.

Each Baker surface controlled subsurface safety vavle should be operationally tested
every month. Operational testing includes one complete cycle of opening and closing in
the well. If the Valve malfunctions or fails to close, it must be replaced or repaired. A
"Failure Report", Form MFR-1 (attached), must be filled out and submitted if the Valve
fails to operate according to this operating manual.

Note: When installing insert valves in Tubing Retrievable Safety Valves, bear in mind
that the distance between packing stacks on the wireline retrievable insert valve
is considerabely longer than on the regular SC-SSSV.

This fact, combined with the higher weight due to its length, can create problems when
tapping the bottom packing stack of the valve through the upper seal bore. Once
tapped through, the valve will drop a distance longer than the stroke of the jar and
could shear the bottom brass pin in the running tool. The valve cannot be set properly
and has to be retrieved. It is good practice to install a steel pin in this case, to avoid any
unnecessary problems.

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Chapter 9, Standard Wireline Operations Page 16 of 56
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

Model “FXVH” Wireline Safety Valve

Note: SC-SSV in drawing not equipped with X-lock but Baker AF lock.

ITEM PART NAME REQUIRED

1 Otis Crossover 1
*2 Chevron Packing Assembly 1
3 St. Stl. Hex. Soc. Hd- 6
Set Screw
*4 O-Ring 4
*5 Back-Up Ring for O-Ring 8
6 Upper Sleeve 1
7 Lower Separation Sleeve 1
*8 Packing Sub Connector I
9 St. StI. Hex. Soc. Hd. 8
Set Screws
* 10 Lower Packing Sub 1
* 11 O-Ring 2
*12 Back-Up Ring for O-Ring 2
13 Spring Washer 1
* 14 Flow Tube 1
* 15 Spring Housing 1
* 16 Power Spring 1
17 Spring Stop 1
18 Snap Ring 1
*19 Intermediate Sub 1
*20 Resilient Seal 1
*21 Flapper Pin 1
*22 Torsion Spring 1
*23 Flapper 1
*24 Flapper Housing 1
*25 T-Seal 1
*26 Back-Up Ring for T-Seal 2
27 St. Stl. Hex. Soc. Hd. 2
Set Screws
*28 T-Seal 1
*29 Back-Up Ring for T-Seal 2
Spare Parts Kit --

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Chapter 9, Standard Wireline Operations Page 17 of 56
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

WS-309-G TYPE KX AMBIENT VALVE (OTIS)

Design Overview

The Otis KX wireline retrievable ambient valve is a poppet valve designed to

automatically shut in a well when the tubing pressure falls below a pre-set condition of
the safety valve. It will remain closed until the pressure across the safety valve is
equalised. The dome chamber is filled with gas and acts like a spring to close the
valve. The safety valve is also designed to use a spring in the absence of gas. A detent
mechanism is built in to ensure a snap action closure. This valve is normally closed.

The safety valve begins to open when the tubing pressure above and below is
equalised. The pressure must be great enough to cause a differential force across the
valve pistion to overcome the spring and gas pressure in the dome. The detent
mechanism is set once the safety valve is fully open. The detent spring and the closing
spring work in opposite directions. When the tubing pressure drawdown is sufficient,
the valve piston begins to close. When the detent mechanism is tripped the valve will
snap closed.

The principle advantage of the safety valve is its large flow area. It should always be
run with an equalising sub unless alternative equalising means are available. If the
charged pressure has been properly determined, the safety valve will open before the
nipple is reached.

For running and pulling procedure, refer to: WS-309-L

1 Top Sub
2 Spring Housing

4 Valve Piston
5 O - Ring
6 Back Up Ring
7 Closing Spring

9 O - Ring
10 Back Up Ring
11 Detent Rod
12 Dome Chamber
13 Detent Spring
14 Detent Ring
15 Detent Balls

16 Gasket
17 Set Screw
18 Gasket
19 Cap Screw

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Chapter 9, Standard Wireline Operations Page 18 of 56
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

Storm Choke® K Safety Valves

Halliburton STORM CHOKE K SAFETY

VALVES are ambient-type, wireline-
retrievable valves with the largest flow area
of all direct-controlled safety valves on the
market. They are ideally suited for high-
volume, low-pressure wells. These valves
are normally closed and pre-charged with a
set dome pressure.

When the well’s flowing pressure drops

below the pre-determined dome-pressure
charges due to a rupture in flow-line or
surface equipment, the dome pressure and
the main valve spring close the valve,
shutting in the well below the earth’s
surface. This valve contains a detent
mechanism to provide a positive snap-
action closure at the pre-determined
disaster rate of the valve. Its bore is not
restricted by a flow bean. The valve is
designed to resist pressure surges. A metal-
to-metal poppet valve and seat comprise
the valve’s primary closure mechanism.

The K valve is ideal for protecting wells with

declining bottomhole pressure. This valve
closes in situations where a pressure
decline would not activate a valve with a
flow bean. To re-open the valve, the
operator must fully equalized pressure
either by applying pressure in the tubing
from the surface or by an equalizing prong.
The valve will reopen when the tubing
pressure acting on the internal piston area
overcomes the dome charge.

Applications
• Wells with declining
bottom pressure
• high-volume, low-pressure
wells
• wells that do not have
• provisions for surface- Ambient Safety Valves (Poppet-Type Closure)
controlled valves Nominal Size Compatible OD ID Top Thread
Features Lock Mandrel (Box)
In. mm In. mm In. mm
• poppet closure
• large ports with capacity 2 50.80 1.875 S 1.750 44.45 0.650 16.51 1 3/16 –14 UNS
for high-volume wells 1.875 X® 1.750 44.45 0.970 24.64 1 3/8-14 UNS
• designed to resist pressure
2½ 63.50 2.313 S 2.170 55.12 1.250 31.75 1 3/16 – 12 UNS
surges
Benefit 2.313 X® 2.160 54.86 1.380 32.51 1 3/4- 12 UNS
• installed and retrieved under 3½ 88.90 2.750 X® 2.500 63.50 1.620 41.15 2 1/4 – 12 SLB
pressure by wireline methods
• adaptable to any Halliburton 4 101.60 3.313 X® 3.120 79.25 2.120 53.85 2 3/4 – 12 SLB
lock mandrel 4½ 114.30 3.813 X® 3.500 88.90 2.250 57.15 3 1/16 – 12 SLB
• can be locked in any
5½ 139.70 4.562 X® 4.440 112.78 2.880 73.15 4 – 12 SLB
Halliburton landing nipple

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Chapter 9, Standard Wireline Operations Page 19 of 56
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

WS-309-H TYPE QOP FLAPPER VALVE (OTIS)

Design Overview

The 22YQ08 is an 2.562” Otis 'QOP' Type Subsurface Safety Valve which is built to
Special Customer Requirements.

The Otis 'QOP' Surface Controlled Subsurface Safety Valve (SCSSV) is a Hydraulic
Controlled Safety Device with a Flapper-Type closure. The 'QOP' Safety Valve is a
normally "closed" Valve and has an equalizing feature. It also incorporates a protection
feature that will not allow the Valve to open if there is a significant differential pressure
across the Flapper.

The Valve is opened by hydraulic Control Line pressure, remains open while the
pressure is applied and closes when the pressure is released. Hydraulic control
pressure is transmitted from a surface source via a conduit to the Valve.

The Valve consists of a Piston, opposed by a compression Spring which operates a

Flapper Mechanism. When pressure is released from the Piston Chamber, the Spring
moves the Piston, Piston Extension, Secondary Valve and Opening Prong up to allow
the Flapper to close. The Safety Valve is installed by using standard wireline methods
and is applicable to external control pressure conduit or concentric installations.

Design Principle

The 'QOP' Subsurface Safety Valve consists of a Top Sub which is threaded to allow
the make up of a Lock Mandrel and is ported to admit control pressure to the Safety
Valve Piston. When the Valve is set in the Landing Nipple, the Safety Valve Packing
forms a seal against the bore of the Nipple below the port. The Lock Mandrel Packing
forms a seal above the port in the Nipple.

The Piston is attached to the Secondary Valve through a Piston Extension and is
opposed by a Spring. The Flapper is contained in the Valve Housing. The Valve is
designed with a metal-to-metal seal as the primary sealing surface. During production
the Valve is held open with hydraulic control pressure. The Valve is designed to close
automatically when the pressure is released.

This Valve incorporates an exclusive "Flapper Guard" feature to avoid Flapper damage
when opening. The Valve is designed not to permit Flapper opening until pressure is
equalized to within approximately 550 kPa across the Flapper.

When attempting to open the Valve with greater than approximately 550kPa differential
across the Flapper, the lower protection spring is designed to compress as the Piston
moves down. The force of the hydraulic pressure is absorbed by the lower protection
spring instead of the Opening Prong and Flapper. Hydraulic control pressure moves
the Piston and Secondary Valve downward to separate the Secondary Seat for
equalization. Well pressure enters through the ports in the Adapter Sub and passes
between the Secondary Valve and Seat and enters the bore of the Valve through small
ports in the Secondary Valve. When equalized, the Spring lowers the Opening Prong to
open the Flapper.

During closure, the Piston Mandrel is machanically linked (via metal-to-metal shoulder)
to the Opening Prong to raise it from across the Flapper.

This type Safety Valve is designed to be attached to a Type ‘X’ or ‘R’ Lock Mnadrel. It
is located and locked in a standard Type Safety Valve Landing Nipple.

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Chapter 9, Standard Wireline Operations Page 20 of 56
 BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

The SCSSV should not be used regularly shut in the well. The Tubing String above the
Flapper must be equalized to a state equal or greater than shut-in pressure below the
Flapper before it opens.

For running, setting and pulling procedure, refer to WS-309-A.

DESIGN SPECIFICATION
Service -H2S Closing pressure -438 Psi
Size -2.562” Max Pressure diff at valve opening -15,000 Psi
Pressure rating -15,000 Psi Opening ration (Cont press/diff press) -1.02
Minimum I.D. -1.12” Special Feature -Equalising/flapper protection
Maximum O.D. -2.53” Min closing pressure allowed -438 Psi
Length -60.4” Max. full opening pressure allowed -1,500 Psi

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Chapter 9, Standard Wireline Operations Page 21 of 56
 BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

WS-309-I TYPE QOS FLAPPER VALVE (OTIS)

The Otis QOS Type flapper valve used in BSP comes in two different designs.

The first design is a 2.313” valve with a single spring module, self equalizing feature,
resilient seat backed by metal to metal seat, Spring modules can be added to set valve
at lower depth. Working pressure, depending on size, is 5000 or 6000 psi.

The second design is a 4.125” valve similar to the QOP, which incorporates a flapper
protection feature. (Ref: WS-309-H) and has a working pressure of 6000 psi.

For running setting and pulling procedures refer to WS-309-A.

DESIGN SPECIFICATION
Service -H2S Closing pressure -336 Psi
Size -4.125” Max Pressure diff at valve opening -6,000 Psi
Length -66.87” Opening ration (Cont press/diff press) -1.116
I.D. -2.38” Test Pressure -7,000 Psi
O.D. -4.08” Special Feature -Equalising
Working Pressure -6,000 Psi

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Chapter 9, Standard Wireline Operations Page 22 of 56
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

WS-309-J TYPE MCX INJECTION VALVE (OTIS)

Design Overview

The Otis Type 'MCX' Injection Valve is a Flapper-Valve designed to open when
injecting down the tubing string. It is a normally closed Valve. It is installed and
retrieved using standard wireline methods.

Design Principle

Injection down the tubing string creates a pressure differential across the Bean and
Flapper Valve. This forces the Prong down and' the Flapper Valve opens. When
injection pressure decreases, the Spring forces the Prong up allowing the Flapper
Valve to close.

Disassembly Instructions.

1) Place the Valve in a vise and grip on the Valve Seat (6).
2) Remove the Pin (10) from the Valve Housing (12).
3) Remove the Torsion Spring (9) and the Flapper (11) from the Valve Housing (12).
4) Place a back-up on the Valve Housing (12) and remove the Bottom Serb (13).
5) Remove the Valve Housing (12) from the Valve Seat (6).
6) Remove the Top Sub (1) from the Valve Seat (6).

Caution: Remove the Top Sub (1) carbfully due to the Spring Compression on the
Top Sub.

7) Remove the Spring Guide (Z), the Bean (5), the Opening Prong (8), and the
Spring (7) from the Valve Seat (6).
8) Remove the Opening Prong (8) from the Spring Guide (2).
9) Remove the Bean (5) from the Spring Guide (2).
10) Remove the Spring (7) from the Opening Prong (8).
11) Clean and inspect all the parts thoroughly for wear or damage.

For running and pulling procedures refere to: WS-309-L.

Note: Always install an equalising valve between the Lock Mandrel and the Valve.

REASSEMBLY INSTRUCTIONS

1) Install the Bean (S) into the Spring Guide (2).

2) Place the Spring (7) over the Opening Prong (8) and make up the Opening Prong
onto the Spring Guide (2).
3) Place the Valve Seat (6) in a vise and install the Opening Prong and its
associated parts into the Valve Seat.
4) Make up the Top Sub (1) into the Valve Seat (6).
5) Place the Torsion Spring (9) and the Flapper (11) in the Valve Housing (12).
6) Install the Pin (10) to hold the Flapper (11) and the Torsion Spring (9) in place.

Note: Check that the Torsion Spring (9) winds in tension when opening the Flapper
(11).

7) Make up the Valve Housing (12) and its associated parts onto the Valve Seat (6).
8) Make up the Bottom Sub (13) into the Valve Housing (12).

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Chapter 9, Standard Wireline Operations Page 23 of 56
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

FIND NAME QTY

1 TOP SUB 3 1/4-12 SLB 3-10 STUB 1.00
2 SPG GID 2.180 9CR 1.00
3 BK-UP RING 2.992 X 2,756 2.00
4 0-RING 2.887 X 2.609 1.00
5 BN 3.688 100/64 1.00
6 V SEAT 3-10 STUB AC 9CR 1.00
7 SPG 2.596 2.300 10.570 3.90 1.00
8 OPN PRNG 3.81 9CR 1.00
9 TRSN SPG 3.81 .044 ELOY 1.00
10 PIN .31 X 1.50 ANL K-M 1.00
11 FLP 3.813 17 – 4 PH 1.00
12 V HSG 3-10 STUB AC FLP 9CR 1.00
13 B SUB 3 7 / 16-12 STUB AC 2.00 9CR 1.00

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Chapter 9, Standard Wireline Operations Page 24 of 56
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

WS-309-K TYPE RQ LOCK MANDREL

Design Overview

The Otis 'RQ' Lock Mandrel is a Top No-Go type Lock Mandrel that is designed to
land and lock subsurface flow controls in an 'RQ' Landing Nipple profile.

A removable No-Go Ring above the packing section permits the Lock Mandrel to also
locate the 'RQ' Landing Nipple with its Keys. It is designed to hold pressure differentials
from above or below and is installed/retrieved by standard wireline methods.

Selected sizes of the 'RQ' Lock Mandrel were designed with the additional feature that
when the No-Go Ring is removed, the Lock can also locate in the 'R' Landing Nipple
profile. See Engineering Bulletin Number 371.

Design Principle

The 'RQ' Lock Mandrel is run with the Otis 'RXN' or 'RX' Non-Selective Running Tool.
This Lock Mandrel can be run in two modes; with No-Go Ring in place, and with No-Go
Ring removed.

With No-Go Ring In Place

The Lock Mandrel is attached to the Running Tool in the "Select" or fully extended
position.

When the Lock Mandrel is fully extended, the Key Springs bias the Keys 'in' to the
retracted position. With the keys retracted, the Lock Mandrel can be lowered and
landed on the No-Go shoulder at the top of the Landing Nipple hone diameter.

Once landed, downward jar action shears the top Shear Pins in the Running Tool,
permitting the Expander Sleeve to move down beneath the Keys to the fully locked
position.

With No-Go Ring Removed

The Lock Mandrel is attached to the Running Tool in the "control" position.

When the Lock Mandrel is in the "control" position, the lower end of the Expander
Sleeve is under the offset bend in the Springs which causes the Keys to be biasea
"out" toward their expanded position.

With the Keys expanded, the Lock Mandrel is lowered into the Landing Nipple. The 90
degree shoulders on the Keys are designed to engage the 90 degree shoulders i n the
'RQ' Landing Nipple and land the Lock Mandrel within the Landing Nipple.

Once landed, downward jar action shears the top-Shear Pins in the Running Tool,
which permits the Expander Sleeve to move down beneath the Keys to the fully locked
position.

When locked, in either mode, upward jar action checks to determine if the Lock is
locked and shears the lower Shear Pin to release the Running Tool from the Lock
Mandrel.

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The Lock Mandrel has matching non-helical teeth inside the Keys and on the 0D of the
Expander Sleeve which engage and become the primary hold-down when the Lock is
subjected to a pressure differential from below. This primary hold-down inhibits the
Lock Mandrel from being flowed or pulled from the Landing Nipple when a pressure
differential exists from below.

SPECIAL FEATURES

1) This Lock also has a Shear Pin Type secondary hold-down at the upper end of
the Key Retainer Sleeve. This Shear Pin, which is spring-loaded, is designed to
engage within a hole in the Expander Mandrel when the Lock is placed in the
'locked' position. The Shear Pin(s) holds the Key Expander Sleeve in the 'locked'
position when the flowing differential pressure through the Lock is insufficient to
activate the primary (Key-Expander Sleeve) hold-down.
2) This Lock meets the requirements for H2S and MACE MR-10-75 Service.

Installation

'RQ' Lock Mandrel w/No-Go Ring In Place

1) Attach the Lock Mandrel to its Non-Selective ('RXN', 'RX') Running Tool in the
"Select" or fully extended position as prescribed in the Running Tool's Basic
Design and Maintenance Instructions.
2) Make up the Lock Mandrel, desired flow controls and Running Tool (w/Running
Prong) on a standard wireline tool string.

Pre-Installations Checks

A. The Keys of the Lock Mandrel should be fully retracted.

B. The No-Go Ring should be in place on the Lock Mandrel.
C. The lower Shear Pin should be thoroughly bradded and cross center
punched to ensure that it stays in place during the running operation.
D. The Shear Pin should be filed flush with the outside diameter of the
Packing Mandrel.
3) Lower the tool string into the tubing until the No-Go Ring on the Lock Mandrel
locates the No-Go shoulder above the polished packing bore in the Nipple.
4) Downward jar action shears the upper Shear Pins in the Running Tool and allows
the Expander Sleeve of the Lock Mandrel to be driven behind the Keys, locking
the Lock Mandrel in the Nipple. This downward movement also releases the Lugs
from the Fish Neck of the Lock Mandrel.
Note: When an 'RX' Running Tool is put in the "locked" position the Core is
locked by the Lock Ring Segments. It cannot be returned to the "selective"
position until disassembly.
Caution: Avoid bumping the jars open when raising the tool string to jar down. The
lower Shear Pin may shear before the upper Shear Pin thereby causing the
Lock Mandrel to lock improperly.
5) An upward strain on the wireline indicates that the Lock Mandrel is set. After that
confirmation, upward jar action shears the lower Shear Pin which releases the
Running Tool Core from the Lock Mandrel. This allows the tool string to be
returned to the surface.

Note: The lugs will not release the Fish Neck until the Core of the Running Tool
has moved more than 80% of its travel.

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BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

'RQ' Lock Mandrel w/No-Go Ring removed

Note: The 'RQ' Lock Mandrel with the No-Go Ring removed can be run in the
corresponding size 'R' Landing.
Nipple for the following sizes only:
3. 688RQ
3.813RQ
4.562RQ
All other 'RQ' Lock Mandrels have Keys with large OD's that when expanded, are
larger than the 'R' Nipple recess ID.

1) Attach the Lock Mandrel to its Non-Selective ('RXN', 'RX') Running Tool in the
"control" position as prescribed in the Running Tool's Basic Design and
Maintenance Instructions.
2) Make up the Lock Mandrel, desired flow controls, and Running Tool (w/Running
Prong) on a standard wireline tool string.

Pre-Installations Checks

E. The Keys of the Lock Mandrel should be spring biased toward the
expanded or "control" position. They should flex freely from their expanded
to retracted position, inhibited only by the spring force.
F. The No-Go Ring should be removed from the Lock Mandrel Assembly.
G. The lower Shear Pin should be thoroughly bradded and cross center
punched to ensure that it stays in place during the running operation.
H. The Shear Pin should be filed flush with the outside diameter of the
Packing Mandrel.

3) Lower the tool string into the tubing until the 90 degree shoulders on the Keys
engage the 90 degree shoulders in the Nipple, locating the Lock Mandrel in the
Nipple.
4) Downward jar action shears the upper Shear Pins in the Running Tool and allows
the Expander Sleeve of the Lock Mandrel to be driven behind the Keys, locking
the Lock Mandrel in the Nipple. This downward movement also releases the Lugs
from the Fish Neck of the Lock Mandrel.

Caution: Avoid bumping the jars open when raising the tool string to jar down. The
lower Shear Pin may shear before the upper Shear Pin thereby causing the
Lock Mandrel to lock improperly.

5) An upward strain on the wireline indicates that the Lock Mandrel is set. After that
confirmation, upward jar action shears the lower Shear Pin which releases the
Running Tool Core from the Lock Mandrel. This allows the tool string to be
returned to the surface.

Note: The Lugs will not release the Fish Neck until the Core of the Running Tool
has moved more than 80% of its travel.

RETRIEVING PROCEDURE

The 'GR' Pulling Tool is recommended to retrieve the 'RQ' Lock Mandrel. The 'GS'
Pulling Tool may be used as an alternate as outlined below.

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NOTE: The proper Pulling Prong should always be used with the Pulling Tool, and
adequate time for equalization should always be allowed before jarring upward on the
Lock Mandrel.

1) Make up the proper size Prong into the bottom of the Pulling Tool and attach the
Pulling Tool to a standard wireline tool string.
2) Lower the tool string into the bore of the tubing until the Lock Mandrel is
contacted.
3) As the Pulling Tool enters the Lock Mandrel, the Prong ensures that the flow
control device is placed in the equalizing position. (Slight downward jar action
may be necessary to shift an 'X' or 'R' Equalizing Valve open.)
4) The weight of the tool string should be allowed to rest on the Lock Mandrel while
pressure across the control device is being equalized.
5) After equalization has been confirmed, an upward strain on the wireline indicates
whether or not the Pulling Tool is latched into the Fish Neck of the Lock Mandrel.
6) Jar down at least one firm stroke on the Lock Mandrel to loosen the Lock Mandrel
i n' the Nipple.
7) Place an upward strain on the wireline. In most cases this is all that is required to
move the Expander Sleeve up, allowing the Keys to retract, and extract the Lock
Mandrel from the Landing Nipple.
8) In some cases, it may be necessary to jar up to extract the Lock Mandrel.
9) If the pin in the 'GR' Pulling Tool shears without pulling the Lock Mandrel, then a
'GS' Pulling Tool can be used.

Caution: DO NOT make up a Pulling Prong into the 'GS' Pulling Tool when retrieving
a Lock Mandrel with an 'X' or 'R' Equalizing Valve attached. Any attempt to
jar down and “shear off" may be obstructed by the Pulling Prong and cause
damage to the Pulling Prong or Equalizing Valve.

FIND NAME QTY

1 FSH NECK 3 7/16-12 1.00
2 KEY RET 4.125 RQ 9CR H2S W/2 SHR 1.00
3 SPG 4.00
4 EXP SLV 4.125 RQ 9CR H2S.F/SHR 1.00
5 KEY 4.125 RQ 9CR H2S 4.403 X 3.535 4.00
6 NO-GO RING 4.125 RQ 9CR H2S 1.00
7 PKG MDL 3 5/8-12 X 3 1/4-12 SLB 1.00
8 FEM ADPT 4.11 X 3.63 X .25 2.00
9 V-PKG 4.125 X 3.619 2.00
10 0-RING 4.155 X 3.615 1.00
11 V-PKG 4.143 X 3.615 5.00
12 0-RING 3.129 X 2.989 1.00
13 CAP SCR # 8 –32 X 1 / 4 2.00
14 SPG 2.00
15 SHR PIN 3 / 16 X .280 ANL M – R – 405 2.00

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Chapter 9, Standard Wireline Operations Page 28 of 56
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

WS-309-L RUNNING AND PULLING OF OTIS “XX AND XXN: PLUGS

General Introduction

1) Both OTIS 'XX' and 'XXN' plugs are used to seal off the tubing and can hold
pressures from below and above.

2) The 'XX' and 'XXN' plugs are to be set in 'X' and 'XN' - landing nipples
respectively.

3) Both plug valves are set in one wireline trip and incorporate an equalising device.

Preparations Before Installation

1) 1 Check the Lock mandrel including the dog springs for correct tension and
ensure that undamaged chevron packings are used.

2) 2 Check the 0-rings or chevron packing on the prong for damage and replace if
necessary.

3) 3 Connect the plug body to the lock mandrel and check the 0-ring on its pin end.

Running Procedure

1) Make up the "X" running tool to the "XX" or "XXN" plug assembly and pin it in
place. Put the running tool in the slective mode Attach the plug assembly to the
standard wireline work string.

2) Lower the plug assembly into the well (taking care in passing through any "X"
profile on the way down) to a point that is a few feet below the desired type "X"
landing nipple.

3) Raise the assembly slowly, until the weight indicator shows that the assembly
has stopped. This indicates that the locating dogs on the running tool have
located the lower polished bore (restricted ID) of the "X" landing nipple. Apply a
200 lb overpull to pull and trip the locating dogs through the nipple. (Alternatively
the tool can be lowered to approximately 3m below the nipple and run up into the
nipple; this creates a jarring action to trip the locating dogs).

4) When the locating dogs trip, the locking mandrel keys move from a retracted to
an expanded position. The lock mandrel is now in the locating / setting mode.

Setting Procedure

1) With the locking mandrel in the setting mode, lower and tap the assembly into the
nipple. The keys on the locking mandrel should engage in the landing nipple
profile Jar down several times to shear the pin in the running tool, and move the
locking mandrel expander sleeve under the locking dogs on the "X" mandrel, and
lock the assembly in the nipple. Pull 400 lb overpull to confirm mandrel is
properly locked in the nipple. Jar up to shear the bottom shearpin in the running
tool connected to the mandrel. Pull to surface and inspect running tool.

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BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

Note: An XN, plug can be run in the locating mode since the the lock mandrels
keys do not match the profile of an X nipple, but care must be taken to tap
the plug through upper nipples of the same size as it could easily shear the
top pin in the running tool when too much friction on the V-packings is
experienced. This would result in additional wireline trips i.e. fishing out and
re-running the plug.

Larger size plugs (i.e. over 3”) which have to be tapped through upper nipples of the
same size, can create a problem when dropping through. The weight of the plug
combined with the impact of the stroking jar may cause the lower brass pin in the
running tool to shear. The plug cannot be set and needs to be retrieved . It is advisable
to replace the brass pin with steel.

An inflow test is mandatory to confirm integrity of the plug, tubing , SSD,s or SPM,s
above the plug.

Pulling Procedure

An XX / XXN plug is retrieved in the following manner:

1) A "GR" pulling tool, with equalising

prong is run to the plug. When the
plug is contacted the "GR" is tapped
down several times to shift the
equalising melon while observing the
pressure gauge mounted on the
lubricator. When the gauge starts to
indicate a change in pressure the
tools , wait for equalisation to
complete, then jar up to release the
lock mandrel and pull out with the plug
body.

2) In case the pin in the GR is sheared

prematurely, run a "GS" pulling tool
without a prong to the plug and
retrieve it. Take care when going
through nipples of the same size on
the way out. V-Packings and / or
external O-rings may have swollen
(CO2) and will make it nescessary to
jar the plug through.

‘XX’ PLUG ASSEMBLY

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Chapter 9, Standard Wireline Operations Page 30 of 56
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WS-309-M RUNNING AND PULLING OF OTIS “PX” AND “PXN” PLUGS

General Introduction

1) Both OTIS 'PX' and 'PXN' plugs are used to seal off the tubing and can hold
pressures from below and above.

2) The 'PX' and 'PXN' plugs are to be set in'X' and 'XN' - no go landing nipples
respectively.

3) The 'PX' and 'PXN' plugs use a prong for equalisation and will allow a limited
tubing fill i.e. debris as the prong is extended about one foot above the Lock
mandrel.

Preparations Before Installation

1) Check the Lock mandrel including the dog springs for correct tension and ensure
that undamaged chevron packings are used.

2) Check the 0-rings or chevron packing on the prong for damage and replace if
necessary.

3) Connect the plug body to the lock mandrel and check the 0-ring on its pin end.

4) Pin the 'X' running tool to the 'X' or 'XN' mandrel respectively ( in selective or non
selective mode) See : NOTE item 5 of WS-309-L.

5) Attach running tool and plug assembly to the standard tool string.

Running Procedure For Plug Body

1) Rig up the lubricator as per standard procedure.

2) Run in hole to just above the 'X' or 'XN' nipple and check pulling weight ( pass
through nipple and “trip” running tool when setting in X nipple) before locating the
mandrel.

3) Tap plug down and jar down in order to close the lock mandrel.

4) Take an overpull of 400 lbs and hold to ensure that the plug assembly is properly
secured in the nipple.

5) Jar upwards to release the running tool and pull out of hole.

6) Check tool and tool string.

Running Procedure For Prong

1) Attach to the tool string an OTIS 'SB' pulling tool with the 'PX' or 'PR' equalising
prong.

2) Run in hole and set the prong in the plug body.

3) Jar down to release the 'SB' pulling tool.

4) Pull out of hole, check tool and tool string for prong release.

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Chapter 9, Standard Wireline Operations Page 31 of 56
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

5) Inflow test plug and check plug holding for 30 min.

6) Rig down as per standard procedure.

Pulling Procedure For Prong and Plug Body

1) Rig up lubricator as per standard procedure.

2) Equalise pressure above the plug, where considered necessary, as this may
save time.

3) Run in hole with `RB' pulling tool.

4) Check pulling weight of string just above landing nipple.

5) Latch onto the prong and jar out of the plug valve body, if the pin in the RB
shears prematurely, pull out and run an SB pulling tool.

6) Observe CITHP for equalisation.

7) Pull out of hole, check prong and RB pulling tool

8) Before pulling the plug body ensure that equalisation has taken place. If in doubt
apply pressure from the surface.

9) Run in hole a 'GR' pulling tool and check pulling weight of string just above
landing nipple.

10) Latch onto plug valve assembly and jar

upwards.

11) Pull out of hole, check plug valve assembly

and GR pulling tool at surface.

12) Rig down as per standard procedure.

PXN PLUG ASSEMBLY

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Chapter 9, Standard Wireline Operations Page 32 of 56
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WS-309-N RUNNING AND PULLING OF OTIS “RR” AND “RRN” PLUGS

General Introduction

1) Both OTIS - 'RR' and 'RRN' plugs are used to seal off the tubing and can hold
pressure from below and above.

2) The 'RR' and 'RRN' plugs are to be set in 'R' and 'RN' landing nipples
respectively.

3) Both plug valves are set in one wireline run and incorporate an equalising device.

Preparations Before Installation

1) 1 Check the lock mandrel including the dogsprings for correct tension and ensure
that undamaged chevron packings are used.

2) 2 Check the 'R’ equalising sub and valve '0' - rings for damage.

Running Procedure For Plug Assy

1) Rig up as per standard procedure.

2) 2 Screw the running prong to the 'R' running tool and pin the assembly to the
lock mandrel.

Note: Care shall be taken when attaching the equalising sub to the lock mandrel
body to ensure that the valve melon is fitted correctly onto the running
prong and in the equalised position.

3) Set the running tool in the non-selective position and attach the assembly to the
standard toolstring.

4) Run in hole to just above the landing nipple and check pulling weight.”Trip”
running tool by passing though the nipple when setting the plug in an R nipple.
(See Note item 5 ,WS-309-L).

5) Locate the assembly in the landing nipple and tap down closing the lock mandrel.

6) Jar down and take an overpull of 400 lbs and hold to ensure that the plug
assembly is properly secured in the nipple.

7) Jar upwards to release the running tool, which in turn will shift the equalising
valve to the closed position.

Note: Once the running tool is released, do not fall back on to the mandrel body
as the equalising valve may be opened again.

8) Pull out of hole and check running tool and toolstring

9) Rig down as per standard procedure.

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Chapter 9, Standard Wireline Operations Page 33 of 56
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

Note: Larger size plugs (i.e. over 3”) which have to be tapped through upper
nipples of the same size, can create a problem when dropping through.
The weight of the plug combined with the impact of the stroking jar may
cause the lower brass pin in the running tool to shear. The plug cannot be
set and needs to be retrieved . It is advisable to replace the brass pin with
steel.

PULLING PROCEDURE FOR PLUG ASSY

1) Rig up as per standard procedure.

2) Equalise the pressure above the plug at surface where considered necessary
and may save time.

3) Run in hole with a 'GR' pulling tool with equalising prong on a standard toolstring.

Check pulling weight of toolstring just above the landing nipple

Locate prong in the plug assy and tap down gently, shifting the equalising melon to the
open position, allowing the 'GR' tool to engage the mandrel's fishing neck.

Observe CITHP for equalisation.

Jar upwards to unlock the plug assembly and pull out of hole. If GR shears
prematurely, pull out and run GS without prong when sure complete equalisation has
been achieved.

Check pulling tool, plug body,toolstring and rig down as per standard procedure.

WS-309-O RUNNING AND PULLING OF OTIS “PR” AND “PRN” PLUGS

General Introduction

1) Both OTIS - 'PR' and 'PRN' plugs are used to seal off the tubing and can hold
pressure from above and below.

2) The 'PR' and 'PRN' plugs are to be set in 'R' and 'RN' landing nipples
respectively.

3) The 'PR' and 'PRN' plugs use a prong for equalisation and allow a limited tubing
fill i.e. debris as the prong is extended to about one foot above the lock mandrel's
neck.

Running Procedure For Plug Body

1) Rig up as per standard procedure.

2) Check the R / RN lock mandrel including dog springs for tension and replace
chevron packings where damaged.

3) Attach the 'PR' or 'PRN' plug body to the lock mandrel.

4) Attach running tool and plug assy to the standard toolstring in the selective
position.

5) Run in hole to just above the landing nipple and check pulling weight.

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Chapter 9, Standard Wireline Operations Page 34 of 56
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6) Lower the assy below the landing nipple and pull up slowly.

7) Some 200 lbs oveipull will trip the running tool and activate the locating
dogs.(See Note: Item 5 ,WS-309-L)

8) Lower the assy again and locate it in the landing nipple tapping down.

9) By jarring downwards, the lock mandrel is now being locked in the nipple.

10) Take an overpull of 400 lb to ensure that the plug assembly is properly secured in
the nipple.

11) Jar upwards to release the running tool and pull out of hole.

12) Check running tool and toolstring.

Running Procedure For Prong

1) Attach to the toolstring an OTIS - 'SB' tool with the equalising prong and check its
chevron packings

2) Run in hole and set the prong in the plug body.

3) Jar down to release the 'SB' tool.

4) Pull out of hole and check ‘SB’ for prong release.

5) Rig down as per standard procedure. (An inflow test may be requested to test
plug)

PULLING PROCEDURE FOR PRONG AND PLUG BODY

See procedure for 'PX' and 'PXN' plugs OPG.NO. WS-309-M.

WS-309-P RUNNING OF CHECK SET TOOL

The Check Set Tool is run to confirm proper setting of an X-lock on a SC-SSV in the
safety valve nipple. The tool is run into the lock mandrel where the ring, which is pinned
in place with a brass shear pin, No-Go,s on the Flow tube or packing mandrel of the
lock. When the lock is properly set, (i.e. fishing neck completely collapsed), jarring
down will shear the pin in the tool ,allowing it to move down to where to tools main
body No-Go,s on top of the fishing neck. The tool is then pulled out and verification of
the pin being sheared confirms proper setting of the lock.

The tool does not need to be run on SC-SSV,s equipped with an Interference lock.
(Ref: WS-309-A) or locks equipped with a leaf spring / shear pin locking arrangement.

CHECK SET TOOL

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Chapter 9, Standard Wireline Operations Page 35 of 56
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

WS-309-Q RUNNING AND PULLING OF HAALIBURTON RPT PLUG

Design Overview

The Halliburton RPT Lock Mandrel is a high pressure rated top No-Go Lock System for
plugging applications. The key retainer will No-Go on the honed bore of the nipple. The
top No-Go provides a positive locator for the lock mandrel. The lock is designed such
that pressure from above and below is held by key/nipple engagement. RPT Lock
Mandrels are designed so that a tapered string series of RPT nipples can be accessed
with one running and pulling tool. This RPT lock and nipple system provides maximum
flow area and maximum pressure rating along with the simplicity of a No-Go installation
procedure.

The lock mandrel is designed to land and lock subsurface flow controls in a RPT
landing nipple profile only. It is designed to hold pressure differentials from above or
below and is installed and retrieved by standard wireline methods.

Design Principle

The RPT Lock Mandrel is run with a Halliburton RXNTM Running Tool in the retracted
position. The running tool is attached to the lock mandrel and shear pinned. This
places the expander sleeve in the fully extended position. When the expander sleeve is
fully extended, the key springs pull the keys in to the retracted position. With the keys
retracted, the lock mandrel can be lowered and landed on the No-Go shoulder at the
top of the landing nipple hone diameter.

Once landed, downward jar action shears the top shear pins in the running tool, which
permits the expander sleeve to move down beneath the keys to the fully locked
position.

When locked, upward jar action checks to determine if the lock is locked and shears
the lower shear pin to release the running tool from the lock mandrel.

RPT locks have either a shear pin hold-down or interference hold-down feature. The
shear pin hold-down locks the expander sleeve and the key retainer together when the
lock is fully set. The pins must be sheared to pull the lock. The interference hold-down
locks the expander sleeve and the packing mandrel together with an interference fit
when the lock is fully set. These hold-downs inhibit the lock mandrel from being flowed
from the landing nipple.

Caution: DO NOT attempt to run the lock mandrel with the running tool in the locate
position (keys biased outward). The lock mandrel expander sleeve will
extend under the keys and will not permit the keys to fully retract when the
running tool is in the locate configuration.

Installation Procedure

Note: This procedure is for when a RXTM or a RXN non-selective running tool is
used.

Attach the lock mandrel to the running tool in the No-Go or fully extended position .

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To ensure proper operation of both the running tool and the lock mandrel, the following
should be checked:

A. The keys of the lock mandrel should be fully retracted.

CAUTION DO NOT attempt to run this lock mandrel in the locate position.

B. The lower shear pin should be thoroughly bradded and cross center
punched to ensure that it stays in place during the running operation.

C. The shear pin should be filed flush with the outside diameter of the packing
mandrel.

1) Make up the lock mandrel and plug to the running tool assembly on a standard
wireline tool string.

2) Lower the tool string into the tubing until the RPT landing nipple is located.

3) Continue lowering the tool string until the lock mandrel No-Go lands on the
No-Go shoulder of the landing nipple.

4) Jar down hard to shear the upper shear pins in the running tool and lock the lock
mandrel in the nipple.

5) Test the lock mandrel by applying an upward strain on the wireline. If the mandrel
is properly locked in the nipple, upward jarring shears the lower pin in the
running tool and allows the tool string to be returned to the surface.

If the mandrel is not properly locked in the nipple, it should jar loose before the
lower pin is sheared. If this should happen, lower the mandrel back into the nipple
and repeat Step 4.

Retrieving

The GR Pulling Tool is recommended to retrieve the RPT Lock Mandrel. The GS
Pulling Tool may be used as an alternate as outlined below.

Note The proper pulling prong should always be used with the pulling tool and
adequate time for equalization should always be allowed before jarring
upward on the lock mandrel.
1) Make up the proper size prong into the bottom of the pulling tool and attach the
pulling tool to a standard wireline tool string.
2) Lower the tool string into the bore of the tubing until the lock mandrel is
contacted.
3) As the pulling tool enters the lock mandrel, the prong ensures that the flow
control device is placed in the equalizing position. (A slight downward jar action
may be necessary to shift the valve.)
4) The weight of the tool string should be allowed to rest on the lock mandrel while
pressure across the subsurface flow control device is being equalized.
5) After equalization has been confirmed, an upward strain on the wireline indicates
whether or not the pulling tool is latched into the fish neck of the lock mandrel.
6) Jar at least one firm stroke downward on the lock mandrel to loosen the lock
mandrel in the nipple.
7) Place an upward strain on the wireline. In most cases, this is all that is required to
move the expander sleeve up, allowing the keys to retract and extract the lock
mandrel from the landing nipple.
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8) In some cases, upward jar action may be necessary to extract the lock mandrel.
9) If the pin in the GR pulling tool shears without pulling the lock mandrel, then a GS
Pulling Tool can be used.

Caution DO NOT make up a pulling prong into the GS Pulling Tool when retrieving
a lock mandrel with an RPT Equalizing Valve attached. Any attempt to jar
down and shear off will be obstructed by the pulling prong and cause
damage to the pulling prong or the equalizing valve.

FIND NAME TY
1 FSH NECK 3.750 2.62 FSH 9CR H2S 1.00
2 KEY RET 3.688 RPT 9CR H2S SHR 1.00
3 EXP SLV 3.750 RPT 9CR H2S SHR 1.00
4 SPG 4.00
5 KEY 3.688 RPT 9CR H2S WO,SERRATIONS 4.00
6 PKG MDL 3.688 9CR H2S 2 5/8-12 S 1.00
7 V-PKG 3.688 X 3.082 X 185 ESS5- 2.00
8 DBL MALE PKG ADPT 3.680 X 3.100 X . 1.00
9 V - PKG 3.706 X 3.078 6.00
10 FEM PKG ADPT 3.678 X 3.098 X .200 2.00
11 O – RING 2.504 X 2.364 1.00
12 SHR PIN 3 / 16 X .505 AML M-R-405 2.00
13 SPG 2.00
14 CAP SCR 2.00
801 ES - I – 3
802 ES - MM - 1
803 ES - MP - 39
804 ES - MM 31 - 7

Design Overview

The Halliburton RPT Equalizing Prong and Valve Assembly is used with a Halliburton
RPT lock mandrel. The assembly is used to plug the upward or downward flow of well
fluids through the lock when considerable amounts of sand or other debris are
expected above the lock. This equalizing valve with lock and prong assembly is
installed/retrieved by standard wireline methods.

Note: Refer to the Design Specifications for specific design information.

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Design Principle

The valve assembly is threaded to the bottom of

the lock and run into the well. The equalizing prong
is inserted into the valve assembly with a second
wireline trip and has two sealing areas that seal
within the bore of the valve housing on both sides
of the flow ports. The equalizing prong is designed
to extend a sufficient distance above the lock
mandrel so that sand or other debris can settle
around it without covering the fish neck of the
prong. A top plugged central passage through the
prong with side outlet holes permits fluid passage
through the prong during insertion and removal.
After the prong is removed, well fluids flow through
the valve and lock mandrel assembly lifting the
sand and other debris from the top of the lock
mandrel.

Plugs can be installed into the flow ports of the

valve to control the rate of equalization.

Normally the only maintenance required is to

replace the packing.

Find Name Qty

1 PRNG 3.313 2.750 43.25 9CRH2S 1.00
2 HSG 3.688 2 5/8-12 SLB 9CR H2S 1.00
3 FEM PKG ADPT 1.490 X 1.135 X 0.260S 2.00
4 V-PKG 1.518 X 1.115 8.00
5 DBL MALE PKG ADPT 1.490 X 1.135 X 2.00
6 DBL FEM ADPT 1.49 X 1.13 X 0.70 1.00
7 V-PKG 1.500 1.119 4.00
801 ES-MM-1
802 ES-T-336
803 ES-MM-31-7

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WS-309-R RUNNING AND PULLING OF BAKER “AFH” SUR-SET PLUG

Description

Baker Models "AFH", "ARH", "HFH" and

"HRH" Sur-Set Two-Trip Bypass Blanking
Plugs with Removable Mandrel are positive
blank-off devices designed to seal off
pressure from above and below.

These plugs are for use in wells where sand

or sediment might be encountered. The
removable mandrel protrudes from the
fishing neck of the lock so that a sand bailer
can expose the top of the mandrel for
retrieval. The blanking plugs are "twotrip":
two trips to set the plug and two trips to
retrieve the plug.

The blanking plugs are run in the well

without the removable mandrel in place,
providing a large fluid bypass area and
allowing fast run-in time.

The "AFH" and "HFH" plugs are positioned

in a top no-go nipple by the use of a top
no-go shoulder located on the lock mandrel.
This prevents downward movement,
allowing the locking dogs to expand into the
locking profile of the seating nipple.

The "ARH" and "HRH" plugs are positioned

in a bottom no-go nipple by the use of a
bottom no-go shoulder located on the lock
mandrel. This prevents downward
movement, allowing the locking dogs to
expand into the locking profile of the seating
nipple.

Running and Pulling Procedures

Refer to Running and Pulling Tools chart. Use the appropriate running and pulling tools
and the stepby-step instructions to run and retrieve the Models "AFH", "ARH", "HFH"
and "HRH" Sur-Set Two-Trip Bypass Blanking Plugs.

Tools for Running and Pulling Removable Mandrel from Type "H" Bypass Blanking Plugs
Plug Sizes Running & Pulling Tool Sizes
1.562 – 1.781 1/2” SB H811-45-1500
1.812 – 2.188 2” SB H811-45-2000
2.250 – 2.562 2-1/2 SB H811-45-2500
2.750 – 3.437 3” SB H811-45-3000
3.688 – 6.000 4” SB H811-45-4000

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Preparation on the Rig Floor

Refer to Drawing No. 277- 741 (Model "A" Running Tool)

The Models "AFH", "ARH", "HFH" and "HRH" Blanking Plugs are run in two trips. On
the first trip, the blanking plug is run in the well without the removable mandrel in place.
On the second trip, the removable mandrel is installed into the blanking plug.

1) Inspect running tools to ensure that the correct size shear pin is being used.

2) Using a pair of calipers, check the basic OD and no-go dimensions of the tool.
Compare the values with the well prognosis for any incompatibility.

3) Attach pulling tool to lock's fishing neck and shift fishing neck upwards until the
locking dogs on lock collapse.

4) Install Model "D" Probe, Product Family No. H81156, onto Model "A" Running
Tool, Product Family No. H81155, and install Set Screws (8).

5) Remove the Set Screws (4) from Fishing Neck (1) of the running tool, and
remove the Fishing Neck from Dog Retainer (5).

6) Move the Retrieving Ring (3) to a position above the groove on Inner Mandrel (7).

7) Pull Inner Mandrel (7) up until Dogs (6) collapse

8) Slide this assembly into the lock until it bottoms.

9) Align hole in Model "D" Probe (B) with hole in Lock Mandrel. Pin with correct size
Brass Shear Stock.

10) Install Fishing Neck (1) back onto Dog Retainer (5), tighten, and install Set Screw
(4).

11) Install Shear Screws (2) through Fishing Neck (1) and into groove on Inner
Mandrel (7). Screw in until they bottom, then loosen one-quarter turn. Two brass
shear screws should, under normal conditions, be sufficient. The number of
screws required may vary according to well conditions.

12) Before pulling tool string up into the lubricator, clean, inspect and grease the
chevron packing on the blanking plug.

Baker Model "A" Running Tool Assembly Drawing No. 277-741

NOTE: Refer to Tech Unit 8249, Index 480.40, Flow Control Manual, for running
instructions and dimensional data.

Running In

Refer to Drawing No. 277-741, above (Model "A" Running Tool).

1) Run in and locate lock in proper nipple.

2) Jar down easily until no-go is reached.

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3) Continue jarring down to shear Shear Screws (2) in Model "A" Running Tool and
force the Fishing Neck of Lock, behind the Locking Dogs, setting the Locking
Dogs. This will also release the Dogs of the Model "A" Running Tool from the lock
Fishing Neck.

4) Pick up on running tool to ensure that blanking plug is set.

5) Jar up to shear the Shear Pin in the Lock Mandrel and release the running tool
from the lock. If lock is set properly in the nipple, the running tool will release from
the lock.

If lock is not set properly, the running tool will not release and will retrieve it from
hole.Come out of hole, inspect, re-pin tool and rerun.

Blanking Off the Plug

1) Install O-rings (17) into the Seal Mandrel (18) dovetail groove.

2) Make up Seal Mandrel Extension (13) onto Seal Mandrel (18).

3) Attach Fishing Neck (11) onto Seal Mandrel Extension (13).

4) Install St. St'I. Hex. Soc. Hd. Set Screws (12, 14) in their appropriate places.

5) Select appropriate "SB Type" shear down Running Tool, and install it onto
Fishing Neck (11).

6) Run in until Removable Mandrel (11, 12,13, 14, 17 and 18) is landed in the
blanking plug.

7) Jar down to release running tool from removable mandrel.

8) Come out of the hole

Equalizing the Blanking Plug

1) Select appropriate size "RB Type" Pulling Tool.

2) Run in the well and engage the fishing neck of the removable mandrel.

3) Retrieve removable mandrel from well.If RS shears prematurely, pull out and run
SB pulling tool.

CAUTION

Well pressures must be equalized before attempting to retrieve blanking plug.

Retrieving the Blanking Plug

1) Ensure that pressure above and below blanking plug is equalized.

2) Select proper "GR" pulling tool.

3) Run in hole and land pulling tool in blanking plug.

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4) Jar down lightly to engage pulling tool onto blanking plug lock's fishing neck.

Jar up to unseat lock from nipple, If GR pin shears prematurely, pull out and run GS.

Come out of the hole.

Dimensional Data, Sizes 3.312 – 4.125

REFER TO DRAWING NO 561-563

Dim Size
3.312 3.437 3.688 3.750 3.812 3.875 4.000 4.125
A 3.125 3.125
B 2.890 2.890
C 1.018 1.015 0.875
D 2.113 2.115 2.125
E 15.158 4.778 2.940 4.000 4.023 4.640 4.675

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F 13.569 13.293 11.790 12.966 13.000 15.070

G 1.995
H 31.765 30.71 30.71 32.353 33.492
J 33.584 33.578 32.796 39.796 34.097 38.390 36.327
K 1.580 1.375 1.405 1.405 2.315 1.900
L 1.235 2.015
M 2.500 9.500 9.500 3.870
AFH No-Go 3.385 3.500 3.740 3.803 3.875 3.950 4.090 4.200
ARH No-Go 3.305 3.427 3.678 3.740 3.807 3.865 3.985 4.110

Description

Baker Sur-Set Seating Nipples are downhole tubing nipples

that provide for the location of various wireline flow control
devices in the production string.

The location and number of Baker Sur-Set Selective Seating

should be carefully considered in the completion planning
stages to allow maximum versatility in the positioning of
various flow control devices.

Baker Models “A-I” and “H-I” Seating Nipples are the Sur-Set
Selective line of seating nipples. These nipples contains a
locating groove and a locking groove. The locating groove is
used to locate and set the flow control device that is being run
into the well. When running the flow control device in the well
to land in the selective nipple, the lock will pass completely
through as many nipples of the same size until the desired
location is reached. When the flow control device is brought
back up through a nipple, the sleeve covering the no-go device
is shifted downward exposing the no-go device. The lock
mandrel assembly is the lowered back down until the no-go
device comes into the contact with the locating groove of the
seating nipple.

Downward jarring using the wireline begins the expansion of

the locking dogs into the nipple locking groove. When
completely extended, the locking dogs relieve the no-go
device off the locating groove. This prevents no-go damage.
All pressure from above or below is now resting on the locking
dogs. The large bearing area and the angle of the bevel are
what enables the Sur-Set locks to hold high pressures without
damage.

This is a brief summary only. Running/Pulling details not presented.

General Design

Available in three basic versions depending on the profile type and required pressure
rating.

Features :

Can only be located and set in a proper nipple profile. .

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• Failure to fully set will cause lock to return to surface with running tool.
• "Tell-tale" shear pin in running tool provides visual confirmation that lock is fully
set.
• Sur-Set lock will not unseat in high vibration, high flow rate applications.
• Large cross-section load bearing areas to increase pressure ratings from above
and below. This is designed to eliminate deformation of the No Go.
• Increased internal flow area, with smooth bore.

Selective Top No Go (F) Bottom No Go (R) Max. Pressure

Model : A AF AR 10,000 PSI
Model : H HF HR 15,000 PSI
Model : V VF VR Over 15,000 PSI

Nipple profile and

compatible lock have
the same Model
Identification (i.e. AF
Lock fits AF nipple).
Selective nipples
(A,H.V) in 3.1/2 OD
and smaller sizes will
also accept Top No
Go Locks (AF, HF,
VF) of same size.

WS-309-S RUNNING AND [ULLING OF SEPARATION TOOL

The Otis Separation Tool is made up of The BSP Separation Tool version is made up of:
1) ‘X’ Lock 1) X-lock
2) ‘X’ Separation sub. 2) Spacer Pipe with packing Mandrel
3) Spacer pipe (mandrel extension). 3) X-Equalising Sub.
4) Packing mandrel 4) Dump Valve equalisin assembly.
5) Valve Cap.

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The Otis version is designed to plug the lower zone and permit flow from the upper
zone.

While this same result could be achieved by plugging the lower zone in the lower nipple
and flowing the well through the SSD, this may cause a problem in sand producing
zones.

As the production and sand enters the SSD, the abrupt change in direction will permit
some of the sand to settle out onto the plug. This can make recovery of the plug
difficult and time consuming, if a sand bailer must be used.

By running a separation tool directly into the SSD the same effect is achieved. i.e. The
bottom zone plugged, and the upper zone flowed. However, there is insufficient space
between flow ports in the separation sub and integral plug to allow sand to accumulate.

The BSP version is designed to permit higher production rates as the restriction
caused by the Otis Separation Sub
has been removed. Although it allows for a bit more sand to accumulate on top of the
Dump valve spool, it also offers the advantage of being able to knock out this very
spool and get rid of the sand through the large holes in the Dump Valve Equalising
housing.

Running Otis version Procedure same as for the XX plug. (Refer to WS-309-L) A
running prong must be used to provide fluid bypass while
running in.
Running BSP version As for Otis version but no need for use of running prong.

Pulling Otis version Using the GR and equalising prong as for the XX plug (Refer
to WS-309-L). Wait for pressure to equalise before pulling.
Pulling BSP version Run extended Equalising prong on GS without dogs, wait for
pressure to equalise. Check if GS is sheared confirming
melon is shifted. If equalisation does not take place, run
special prong and knock out dump valve spool. Run GR
pulling tool.

Caution: Some separation subs still in use have V-thread connections. Care must be
taken to ensure the lock is compatible. (Newer locks have a square thread
form.)

Note: It is advisable to plug the lower zone prior to opening the upper SSD and
installing the separation tool for the following reasons:

1) To prevent flow from one zone to another if there is a pressure differential across
the zones.

2) To prevent excessive and / or differential across the separation tool when it is

pulled.

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SEPARATION TOOL BSP VERSION

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‘X’ EQUALISING
SUB-ASSEMBLY

‘X;’ LOCK ASSEMBLY

1VALVE HOUSING DUMP

VALVE SPOOL
3 O-RING
4 JAM SCREW
5 PIN ¼ X .550 STEEL
6 O-RING

FLOW TUBE
WITH PACKING MANDREL

VALVE CAP

WS-309-T RUNNING AND PULLING OF STADDLE TOOL

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The running, setting and pulling procedures for a "X" straddle tool is the same as the
instructions for the "X" lock mandrel, (Ref: WS-309-L) with the exception of the
sequence of the packing stacks passing through the polished bore areas.

Design Principle

The above is used during completion operations by installing it in the SC-SSSV nipple
to test the integrity of the control line.

The type "X" straddle tool is also used in the type "X" sliding side door to blank off the
ports when it is not feasible to close the sleeve or when the sleeve is flow cut or leaking
badly. With the "X" straddle tool in place the bottom or lower zone is allowed to
produce and the zone behind the straddle tool is blanked off.

Operating Principle

The "X" straddle tool consists of an "X" locking mandrel, an "X" equalizing sub, a
mandrel extension, and a lower packing assembly.

This "X" straddle tool is run with the type "X" running tool. For pinning and operating
instructions refer to WS-309-L

The difference in the operating instructions, where running the straddle tool is ex-
plained, would be when the packing stacks enter the nipple polished bore areas. This is
the sequence of the packing stack interference with the polished bores:
1) The lower packing stack contacts the upper polished bore.
2) The upper packing stack and the lower packing stack come in contact with the
upper polished bore and the lower polished bore at the same time.
3) The upper packing stack contacts the lower polished bore.

This sequence of events happens when the straddle tool is run through the sliding side
door, again when the straddle tool is pulled through the sliding door to trip the locating
dogs of the "X" running tool and convert the "X" locking mandrel to the control position.

When the straddle is lowered across the sliding side door the first and second events
take place.

The shearing off of the running tool is identical as described in WS-309-L

The retrieving sequence will be the same with the exception of the lower packing stack
entering the upper polished bore area. Here the operator will have to jar upward a few
times to pull the straddle tool free.

“X” STRADDLE TOOL

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WS-309-U ZONE CHANGE OPERATIONS

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Zone changes are carried out for two purposes. One is to gain access to a reservoir to
obtain data and the other to change producing zones or for commingling an open
reservoir with another.

The steps required for zone changes are as follows:

1) Drift run to HUD. (Drift must be run on a pulling tool)

If a separation tool or plug has to be pulled to gain access to a reservoir that has
to be closed or opened, another drift run must be made after pulling out the
Separation tool or plug.

2) Close SSD's (that are open) with an Otis "B" Positive Shifting Tool.
3) Install a plug in the No Go.

Plugs must be installed in the well. This is to positively isolate all the zones and
prevent cross flows. Deviation from this must be authorised.

4) Inflow test the string.

5) Calculate the differential pressure between the reservoir to be opened and the
tubing. Equalise pressures by injecting gas or liquid from another well.
6) Open SSD's with an Otis Selective Shifting Tool. When a pressure change is
noted on the pressure gauge on the lubricator, jarring operations must be
suspended temporarily until the THP has stabilised. Once the pressure has
stabilised, continue jarring operations until the SSD is fully opened.
7) Set Separation Tool. Separation Tools are set to prevent sand accumulation
below the open SSD. Deviation from this practice must be authorised.
8) Handover well to surface operations

NB: In a commingled string, the Separation Tool must be set on the lower zone
which is opened for production.

WS-309-V DUMP EQUALISING VALVE ASSEMBLY

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Design Principle:

Dump Equalising Valves in BSP are used as a back-up equalising option for plugs
which are installed in wells where sand, heavy mud or other contaminants can plug off
the equalising ports in the primary equalising valve.
The “Dump valve” as commonly known, is made up of a valve housing in which a dump
valve spool is pinned in place with brass shear pins. Two O-rings provide the seal
between valve housing and the spool. Large ports in the valve housing provide enough
passage for the pressure to equalise or sand, mud or debris to fall out. The plug can be
sheared either by jarring out the spool with a special prong or pressurising from above
by pumping fluid or using gas pressure.
It is run as part of the plug assembly below the standard equalising valve sub.

Operation:

A run with a GR (without dogs) and equalising prong is made to knock the equalising
melon down and also to confirm
that the tool can be sheared ,thus released. If no increase in CITHP is noticed, or
pressure increase stops prior to reaching its former value, it is safe to assume that the
equalising ports in the primary valve are blocked.
A run with a special dump valve prong is made, run on a RB pulling tool .The bottom of
the prong can be marked or filed smooth to give an indication that it was in contact with
the spool. As the OD of the prong is smaller then the prong for the primary equalising
valve, it shall therefore stand up on top of the spool inside the dump valve.
By jarring down on the spool, the brass shear pins will shear and the spool will fall in
the valve cap thereby exposing the big side ports. Equalising will now take place and fill
can fall to the bottom. The prong is pulled and examined for proof of contact with the
spool.
The plug body may now be pulled with a GR pulling tool.

Note: The Dump Equalising Valve should not be run during Well Completion
Operations as pressure testing and changing hydrostatic pressures by
circulating to different well fluids could easily shear out the spool in the
dump valve which then has to be pulled, wasting valuable rig time.

3 1/2" Dump Equalizing Valve

DESIGN SPECIFICATION

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TUBING SIZE : 3 1/2

SIZE (SING NIPPLE) : 2.75
MAX O.D. : 2.575
MIN I.D. (W/O VALVE) : 1.500
TOP/BOTIOM THREAD : 2 1/4-12 SLB BOX X PIN
MATERIAL : 9 CR 1M0
LENGTH : 5.48
SERVICE : STANDARD/H2S
PUMPED OUT DIRECTION : DOWN
PRESSURE RATING : 5000 PSI
PISTON area : 1.77 SQ. IN.
SHEAR VALUE PER ¼" STEEL PIN = 2800 = (PISTON AREA) = 1581 PSI/PIN
(CALCULATED) ¼" BRASS PIN = 2100 = (PISTON AREA) = 1184 PSI/PIN

HOLES AVAILABLE FOR PIN = 4

DETAIL DESCRIPTION QTY PART NUMBER

1 VALVE HOUSING 1 888 S 50
DUMP VALVE SPOOL 1 888 S 49
3 O-RING 2 91 QV 1218-H
4 JAM SCREW (4) 410 JM 111
5 PIN 1/4 X .550 STEEL - (4) 9 P 40550
6 O-RING 1 91 QV 1033-H

2 7/8 DUMP EQUALIZING VALVE ASSY

DESIGN SPECIFICATIONS

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TUBING SIZE : 2 7/8

SIZE ( LANDING NIPPLE ) : 2.313
MAX O.D. : 2.156
MIN I.D. ( W/O VALVE ) : 1.125
TOP/BOITCM THREAD : 1 3/4-12UN BOX X PIN
MATERIAL : 9 CR iM0
LENGTH : 5.47
SERVICE : STANDARD/H2S
PUMPED OUT DIRECTION : DOWN
PRESSURE RATING : 5000 PSI
PISTON AREA . : .99 SQ IN
SHEAR VALUE PER 3/16 STEEL PIN = 1700 = (PISTON AREA) = 1711 PSI/PIN
(CALCULATED) 3/16 BRASS PIN = 1250 = (PISTON AREA) = 1260 PSI/PIN

HOLES AVAILABLE FOR PIN = 4

DETAIL DESCRIPTION QTY PART NUMBER

1 VALVE HOUSING 1 888 S 48

2 DUMP VALVE SPOOL 1 888 S 47
3 O-RING 2 91 QV 1212-H
4 SHEAR PIN 3/16 X 1/2 STEEL 4 9 P 30500

2 3/8 Dump Equalizing Valve Assy

DESIGN SPECIFICATIONS

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TUBING SIZE : 2 3/8

SIZE (LANDING NIPPLE) : 1.875"
MAX O.D. : 1.600
MIN I.D. (W/O VALVE) : .750
TOP/BOR'TCM THREAD : 1 3/8-14 BOX X PIN
MATERIAL. : 9 CR 1MO
LENGTH : 5.47
SERVICE : STANDARD/H2S
PUMPED OUT DIRECTION : DOWN
PRESSURE RATING : 5000-PSI
PISTON AREA . : .44 SQ IN
SHEAR VALUE PER 1/8" STEEL PIN = 760 - (PISTON AREA) = 1727 PSI/PIN
(CALCULATED) 1/8" BRASS PIN = 525 - (PISTON AREA) = 1193 PSI/PIN

HOLES AVAILABLE FOR PIN = 4

DETAIL DESCRIPTION QTY PART NUMBER

1 VALVE HOUSING 1 888.5 46

2 DUMP VALVE SPOOL 1 888 S 45
3 O-RING 2 91 QV 1113-H
4 SHEAR PIN 1/8 X 3/8 BRASS 4 410 PD 292

WS-309-W RUNNING A DRIFT CUTTER. AND SCRATCHER

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In the BSP group the Drift Cutters for running on wireline must have a rope socket
installed. An "RB" pulling tool is made up on the standard wireline tool string and the
drift is latched into the pulling tool.

The tools are lowered into the well at a moderate speed. If an obstruction is met, the
drift is pulled back out of the hole and a swaging tool run to hold up depth, if the hold
up is thought to be a tight or mashed spot. In case of tubing scale, run a scratcher and /
or a tubing broach.

Note: Do not try to beat a drift through hold-up depths. The wall thickness of
the drifts are not thick enough and the outside diameter is not
case-hardened.

RUNNING A SCRATCHER.

Identical to the Drift Cutter, Scratchers are made up with a rope socket and run on a
RB pulling tool connected to a standard tool string.

They are usually custom built to the size needed for a particular job. The running speed
usually does not matter because in most cases the scratcher OD is larger than the ID
to be scratched, therefore slowing it down considerably.

Note When the scratcher is being used to locate or catch wire, it helps to run a
3' (0.9 m) weight bar between the rope socket and the scratcher. The main
reason for this is to have some weight to jar against if it becomes
necessary to get off the scratcher.

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CHAPTER 10
SLIDING SIDE DOOR OPERATIONS
TABLE OF CONTENTS

WS-310-A SLIDING SIDE DOOR OPERATION ..............................................................2

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Chapter 10, Sliding Side Door Operations Page 1 of 8
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WS-310-A SLIDING SIDE DOOR OPERATION

Sliding Side Door,s or SSD,s more often called, are installed in the tubing during well
completion to provide means of communication between tubing and annulus.
The most common uses are as follws:

1) To provide a circulation path.

- When putting a well into production after a drilling or workover operation, by
circulating the drlling fluid into the annulus and replacing it with a lighter fluid
in the tubing.
- To kill a well prior to pulling the tubing during a workover operation.
- To equalise pressure and fluid levels between tubing and annulus to change
gaslift valves, minimizing the risk of getting blown up.
2) To allow production to enter the tubing from the desired production zone.
3) To provide access to the formation for stimulation,

Opening Procedure for XO, XD and Halliburton DURASLEEVE.

Make up a "B" positive downshift positioning tool on the wireline work string.

Run the tools down to the "SSD" at a moderate speed, taking care when passing the
nipples, "SSDs" or side pocket mandrels on the way down. Let the tool pass through
the "SSD". When it is 2 to 3 m below the "SSD" pick the tool back up through the
"SSD". This trips the positioning tool and puts the locating keys in the engaging mode.
Lower the tool back down until it sits down. Open the jar about 0.5 m and start tapping
the tool down. Have a wireline helper observe the pressure gauge on the lubricator for
any pressure change. When the sleeve has moved to the equalizing mode pull the tool
up about 5m above the "SSD" and allow the pressure to equalize fully before opening
the sleeve completely.

When the sleeve is fully shifted, the positioning tool will fall through. Confirm the "SSD"
is fully open by passing the positioning tool up and down several times through the
sleeve.

Note: Never pull out of hole without confirming that the "SSD" is fully open.

Closing Procedure for XO , XD and Halliburton DURA SLEEVE .

An "B" upshift shifting tool is used to close the "SSD".

When the "B" shifting tool is in the proper recess in the upper part of the sleeve,
several hits upward with the wireline unit at high speed are usually sufficient to shift the
"SSD" closed. When the sleeve is fully shifted, the shifting tool will be automatically
released to travel up. Go back down through the "SSD" several times to double check
the sleeve is fully closed.. When the "B" positioning tool comes back to the surface
always check the shearpin , the sleeve might not be fully closed. Repin the"B" upshift
shifting tool and run back to the "SSD" for continued upward jarring until the sleeve is
closed.

NOTE: In the past it was practice to run the Shifting tool on a 3ft piece of stem with
rope socket and on a pulling tool.
This is no longer required , the tool must be attached directly to the 1.50”
toolstring as described in WS-304-A.However, this tool string configuration
may have to be altered depending on difficulties encountered as also
mentioned in the foot note in WS-304-A .Whenever sand is encountered ,
contact the Wireline Supervisors Office prior to opening the SSD.

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TYPE “B” SHIFTING TOOL

The Otis 'B' Shifting Tool was designed to open or close all of the Otis SSD's. Chart on
page 5 will show the correct tool for each respective size.

This tool has 2 pin connections to permit either opening or closing of the sleeve by
inverting the tool.,

1) With the 90° shoulder on keys facing DOWN.

Opens - XO, XD and DURA SLEEVE

Closes - XA.

2) With the 90° shoulder on keys facing UP.

Closes - XO, XD and DURA SLEEVE

Opens - XA..

Note: To open an XO, XD or DURA SLEEVE which is BELOW another SSD, the
SELECTIVE DOWNSHIFT tool must be used.

Operation

1) Select the direction in which the tool will shift the sleeve, and install on the
toolstring with the 90° shoulder facing the direction of the required movement.
2) Run into the SSD and locate.
3) Jar against the sleeve in the desired direction. If moving the sleeve up, jars
cannot be closed to hit a lick - run into the SSD from below, adjusting speed to
give the desired impact.
4) Observe the lubricator gauge pressure CAREFULLY. Stop when the pressure
changes and WAIT until the pressure is equalised. The pressure should be fully
equalised through the 4 small ports in the sleeve prior to the main flow ports
being opened.
5) Continue jarring to fully open the SSD. The tool will automatically release when
the raised portion of the keys is `squeezed' by the ID of the polished bore.
6) The tool should be passed completely through the SSD 3 times to check the SSD
is fully open (or closed).
7) Pull out of the hole and VISUALLY CHECK THE TOOL HAS NOT SHEARED. If
the steel shear pin has sheared, the sleeve MAY NOT be fully open. Repin and
rerun the tool. It is good operating practice to check / replace the pin before each
run as the pin could be partially sheared from the jar action.

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Positive Keys

When these keys are fitted the

pin must be sheared to retract
keys and release tool. They are
used to:

• Operation the drop sub on

TCP guns
• Open upwards one SSD
below other SSD’s; such as
an XA.

“B” SHIFTING TOOL, DOWN / UP

Selective Down Shift Tool

This tool was designed to `selectively' open XO, XD and DURA SLEEVE SSD's by
passing through the upper sleeve(s). It will ONLY shift sleeves DOWNWARDS, and
should never be inverted (hence only one pin end) as it could get stuck below a tight
sleeve.

Note : This tool does not have a shear pin.

1) Selective Shifting keys retracted to pass the upper SSD's locator

dogs extended to locate the packing bore.

2) Non-Selective Shifting keys extended to locate in the SSD.

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To Set the Tool in SELECTIVE

1) Grip the bottom of the main mandrel in the vice.

2) Insert the screwdriver in the slot through the hole (A) in the upper end of the
spring housing, and lever the housing downwards compressing the main spring.
3) At the same time as (2) above, squeeze the upper end of the locator dogs
inwards and release the screwdriver.
4) The tool should move partially to the SELECTIVE position.
5) Using the handle of the screwdriver, strike the lower ends of each shifting key
inwards.
6) The tool should snap into SELECTIVE. If not, repeat from (2) above.

Fishing Neck (1)

Key Ratainer (2)

Key Weldment (3)

Spring (4)

Lower Key Retainer (5)

Socket Screw (6)
Spring (7)

Spring Assembly (8)

Dog Retainer (9)

Spring (10)
Split Ring (11) not shown

Dog (12)
Tungsten Wear Insert

Main Mandrel (13)

“B” SELECTIVE DOWN SHIFTER.

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Operation

1) The tool is run in SELECTIVE to below the SSD to be shifted.

2) Pull upwards through the SSD to trip to NON-SELECTIVE.
3) Sit down in the SSD and jar down. OBSERVE EQUALISATION PROCEDURES -
AS FOR THE 'B' SHIFTING TOOL.
4) When the SSD has moved fully, the tool will automatically pass through the SSD.
5) Check by passing 3 times through the SSD.
6) Pull out of the well.

OTHER SSD,s

XA Sliding Side Door

The XA SSD opens- UP, i.e. in the opposite direction to the XO, XD and DURA
SLEEVE

It was a design progression from the original `type A' sleeve by adding an 'X' profile in
the top sub.

The disadvantage is that the shifting tool is above the flow ports when the sleeve
opens, so there is a greater risk of being blown up the hole.

Assembly # 121XA40 121XA38 121XA281 121XA38182

Size (inches) 2 3/8 2 7/8 3½* 4½
Material Alloy Alloy 9CR-1MO 9CR-1MO
Length (inches) 34.000 35.620 44.880 49.480
OD (length) 3.090 3.750 4.280 5.500
ID Nipple (inches) 1.875 2.313 2.750 3.813
Flow Area (square inches) 1.459 2.446 4.459 6.000
Shifting Tool (standard) 42-BO 116 42-BO 118 42-BO 147 42-BO 111
Selective Shifting Tool 142-BO 4 142-BO 3 142-BO 1 142-BO 7
* Also available in 2.813” nipple bore – uses 42-BO 146.

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XD Sliding Side Door

The XD has larger flow ports between the tubing and annulus. The ID through the bore
is the same as the XO. It is identical in operation to the XO (i.e. same overall
dimensions, opens down). It was developed for oil wells with heavy crude, so that SSD
ports would not restrict the flow of oil from the formation of the tubing.
Compare the flow areas in the following chart with the flow areas of the same size XO
and XA:

NOTE: The Halliburton DURA SLEEVE is identical to the Otis XD- SSD, the only
difference being the DURATEF non elastomer ECM seals.

Assembly # 121XD23 121XD2 121XD3 121XD7

Size (inches) 2 1/8 2 7/8 3 ½* 4½
Material 9CR-1MO 9CR-1MO 9CR-1MO 9CR-1MO
Length (inches) 33.940 41.000 44.880 46.000
OD (length) 3.090 3.750 4.280 5.500
ID Nipple (inches) 1.875 2.313 2.750 3.813
Flow Area (square inches) 2.854 4.200 5.900 12.600
Shifting Tool (standard) 42-BO 116 42-BO 118 42-BO 147 42-BO 111
Selective Shifting Tool 142-BO 4 142-BO 3 142-BO 1 142-BO 7
* Also available in 2.813” nipple bore – uses 42-BO 146.

X-Selective Shifting Tool

An alternate selective shifting tool is the Otis

‘X’ selective, which is still in use in many
locations.

The raised “dog” (5) section of the key has 2

positions.

If it is extended as shown in the diagram, the

tool is configured to latch the SSD profile.

The dog can be moved into a position close to

the 90° key shoulder by picking up the tool-
string and lowering it down again to ‘cycle’ the
tool into a non-latching position.

The SSD is then bypassed and the process of

reciprocating the tool-string repeated to put
the dog into the latching position.

This tool can be used selectively in either

Directions to open or close the SSD’s.

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CHAPTER 11
SLIDING SIDE DOOR OPERATIONS
TABLE OF CONTENTS

WS-311-A GASLIFT EQUIPMENT AND PRINCIPLE OF GASLIFT ................................2

WS-311-B SIDE POCKET MANDRELS SERVICE TOOLS OVERVIEW ........................4
WS-311-C SIDE POCKET MANDREL .............................................................................5
WS-311-D KICK-OVER TOOLS .......................................................................................8
WS-311-E PULLING AND RUNNING OF GASLIFT VALVES FROM SIDE POCKET
MANDRELS ..................................................................................................15
WS-311-F RUNNING TOOLS FOR GAS LIFT VALVES ................................................20
WS-311-G PULLING TOOLS FOR GASLIFT VALVES AND PRECAUTIONS .............22
WS-311-H LACTHES ......................................................................................................27
WS-311-I BASIC GASLIFT VALVE TYPES ...................................................................34
WS-311-J DUMMY VALVES ...........................................................................................35
WS-311-K SPECIAL TYPE VALVES ..............................................................................37
WS-311-L VALVE CATCHER .........................................................................................38
WS-311-M CX GASLIFT MANDREL, VALVE CARRIER AND 9/16” VALVES .............39

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WS-311-A GASLIFT EQUIPMENT AND PRINCIPLE OF GASLIFT

The most common method of controlling the lift gas flow is by the use of side pocket
mandrels installed in the tubing during the completion. Their main advantage is that
they do not obstruct the tubing ID, so plugs and BHP surveys etc. can be run to the
bottom of the well without disturbing the gaslift system.

A wide variety of valves or control devices can be installed, and the basic types will be
described in this section.

Uses of SPM's

The following devices can be installed in an SPM:

• Gaslift valve - Sensitive to casing pressure.

- Sensitive to tubing pressure.
- Orifice valve to control rate of gas flow.
• Dummy valve - Installed while running / pressure testing and prior to installing
a gaslift valve.
• Chemical injection valve.
• Differential Kill Valve.
• Electronic pressure / temperature gauges.

Latches

Latches are attached to the above devices to hold them in position in the `side pocket'
of the SPM.

Wireline Equipment

The following equipment is required to install and retrieve valves:

• Kickover tools - To align the valve or pulling tool in the SPM with the hole or the
valve in the side pocket.
• In all new SPM's an orientation sleeve rotates the kickover tool into the correct
position relative to the side pocket.
• Older style SPM's have no orientation sleeve, so spring centraliser kickover tools
(e.g. Camco 'L' or 'R') must be used. These do not function well in highly deviated
wells.
• Running tools - Matched to the type of latch in use and attached with shear pins,
the running tool screws into the kickover tool.
• Pulling tools - Selected to suit the latch in use, the pulling tool is attached to the
kickover tool to recover the valve.
• Spacer bars - In some deviated wells, spacers may be required between the
pulling tool and kickover tool to enable the skirt to pass over the top of the latch.
This situation usually occurs when the `belly' of the SPM is on the top side.
Gravity acts to pull the tools down and away from the pocket. This situation can
also occur when running valves, and a spacer can be installed between the
running tool and kickover tool. Good well records noting any such difficulties and
use of spacers and their length, can reduce misruns after this potential problem
has been identified.

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Produced Hydrocarbone Out

Produced Hydrocarbone Out

Produced Hydrocarbone Out

Injection
Gas In
Injection
Gas In

Side Pocket
Mandrels

Side Pocket
Mandrels

Completion Fluid

Dual Production
Packer

Produced
Hydrocarbone
Completion Fluid

Single Production Single Production

Packer Packer

Produced Produced
Hydrocarbone Hydrocarbone

Single Installation
Dual Installation

Side Pocket Mandrel Service Tools Overview

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WS-311-B SIDE POCKET MANDRELS SERVICE TOOLS OVERVIEW

Valve Type 1” 1.5”

Dummy E, DK-1 RD
LATCHES

Equalising EK RKED
Dummy EK-1 CEV
RKEO
Gaslift BK, BK-1, R-20
BKT. BKT-1, R-28
BKF-10, RMI
BKR-5, R-25
BKR-6, PK-1 RP-6
Chemical BKHLK-2 RCBH
Injection BKLK-2 RCB
SIDE POCKET MANDREL

LKH-3
LK-3
Differential DCK-2 DCR-1
Kill DCK-3 RDK
Circulating CSK-1 RCS
Valve BKFS RKFS

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WS-311-C SIDE POCKET MANDREL

There are a wide variety of Side Pocket Mandrels available from a wide range of
manufacturers. However the design and operating principles are very similar. In this
manual, we have selected the types in most common usage.
The main manufacturers are Camco, Otis (Halliburton), Macco, and Merla (Halliburton).

Types of Camco Side Pocket Mandrels

In the Camco system (available in sizes from 2 3/8" to 7"):

'G' 'G' series SPM's contain an orientation sleeve to position the kickover tool.

'K' SPM's containing the letter 'K' in their title have a 1" ID side pocket.

'M' SPM's containing the letter 'M' in their title, but without a 'K’, have a 1 '/2" ID side
pocket.

A wide range of SPM's are available for specialised applications, such as water flood
and chemical injection. Please refer to the manufacturer for further details.

Commonly used examples:

MMA Still in use in some older wells. This SPM accepts 1 '/2" valves on an RA latcl
It has no orientating sleeve, so a non-orientating kickover tool must be used.

(i) Camco Type 'L' or 'L-2D'.

(ii) Type 'R'.
MMG Accepts 1 ½ " valves with an RK latch. Similar to the MMA, but with the addition
of an orientating sleeve* and tool discriminator*.
Kickover Tool (i) OM series kickover tool.
(ii) Type ‘L’ * or 'L-2D'*.
(iii) Type 'R'*.
* Not recommended in highly deviated wells.

KBMG / KBUG Accepts 1" valves on a BK-2 latch. Similar internal design to the
MMG, including orientating sleeve* and tool discriminator*.

Kickover Tool OK series (OK-1 through to OK-6).

*Orientation Sleeve Positions the kickover tool `to kick' into the pocket when pulling
upwards.

*Tool Discriminator A built in `deflector' which ensures the tools of larger OD than
the gaslift valves, do not hang up' in the side pocket.

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Otis Side Pocket Mandrels

The central section of the Otis SPM's are machined from solid bar, with the tubing flow
area and side pocket drilled and honed as required. This method eliminates the
longitudinal weld. Full length internal transfer rails (deflectors) reduce the bending
forces on the valve as it is being installed or removed. End caps are welded in place,
and the complete assembly annealed to provide optimum strength. The Otis mandrels
are available in 2 main versions from 2 3/8" to 7".

`Tru Guide' - Oval cross-section SPM with 1" ID side pocket.

`Hi-Strength Tru Guide' - Round cross-section SPM with 1" and 1 '/2" ID side
pocket.

From the Otis part number, the following information can be ascertained:

211 = Oval Mandrel 211 W B * 1 19 01 Thread Connection

215 = Round Mandrel 01-99

Material Types
W = 1” valve 01-99
L = 1½” valve

B = with positioning sleeve and deflector. Nominal Size Size 1 – 9

N = without positioning sleeve & deflector. Specific Use Decription 1: 2 3/8” 4: 4” 7: 5½”
D = with deflector only.
P = with positioning sleeve only
2: 2 7/8” 5: 4½” 8: 6 5/8”
Blank : Standard porting 3: 3 ½” 6: 5” 9: 7”
K = Keyhole tubing with positioning sleeve. C: Casing Flow
F: Water Flood
H: Side String
S: Chamber Lift
X: Special Clearance.
D: Dummy/latch installed
P: Pumpdown mandrel
K: X + D above
T: Twin Flow
N: Chemical Injection

Merla SPM's (now part of Halliburton)

TMPD Mandrels - 1 " valves - Uses Merla TMP kickover
tool
(OK series tool compatible).
TPD Mandrels - 1 '/2" valves - Uses Merla TP kickover tool
(OM series tool compatible).
Macco SPM's
SPM-IA and SPM-1N - 1" valves - OK series kickover tools.
SPM-2 and SPM-2N - 1 '/2" valves - OM series kickover tools.

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WS-311-D KICK-OVER TOOLS

Kickover tools, sometimes referred to as positioning tools, are run on the wireline
toolstring. The running or pulling tool is attached to the lower thread on the kickover
tool. Upward movement in the SPM selected causes the kickover tool to rotate and
align with the side pocket.

Camco

OK-1 to 5 For 1" OD valves. Higher number indicates newer model. Similar
operation.
OK-6 Newer version of OK series (using detent balls in place of shear pins).
UK-5 Reduced OD version of the OK-5 for use in reduced 1D mandrels.
OM-1 to 5 For 1 '/2" OD valves in the MMG mandrel.
L Spring centraliser type - for 1 '/2" OD valves in MMA. Available in 2'/2".
L-2D Spring centraliser type - for 1 '/2" OD valves in 3 '/2" MMA. Available in
2'/2" to 3".
R Spring centraliser type - for 1 '/2" OD valves in the MMA mandrel.
Merla TMP For 1" valves in KBMG and KBUG mandrels (and compatible SPM's).
Merla TP For 1 '/2" valves in the MMG mandrels (and compatible SPM's).

Kickover Tool Quick Reference Chart

Kickover SPM Latch RunningTool Pulling Tool Pulling Spacer*
OK-1 KBMG BK-2 JK-2 1¼” JDC -
OK-6 KBUG 1.66” SM
OM-1 MMG RK RK-1 15/8” JDC +
Core extension 11 ¼”
1½” SB
R MMA RA JC-3 2” JDC 20 9/16”
2’’ SB
KBUG BK-2 JK-2 1½ » JDC -

L MMA RA JC-3 2” JDC 4¾”

L-2D 2” SB
MMG RK RK-1 1 5/8” JDS + 4¾”
Core extension
1½” SB
Merla TMP 2 7/8” KBMG BK-2 JK-2 1¼” JDC -
3½” KBUG 1.66” SM
3½” MMG 15/8” JDS + 12” SPACER
Merla RK RK-1 Core extension 1½”
4½” MMG SB 1” Spacer
TP
* Possible use in deviated wells.

Redress Procedure

Before preparing the kickover tool for service, make sure that all parts are in good
working order, do not bind or drag, and are free of any condition which would affect
their operation.

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Important: Shear pins must be either free cutting brass (ASTM Specification
B16 half-hard) or aluminium alloy 5052 with H38 temper. If the
shear pins are made of anything harder, the kickover tool could be
damaged or the pins might not shear.

1) Place the kickover tool in a large vice, so that the grip of the vice is on the lower
end of the finger cage and the locating finger is on the bottom.
2) Back out the locking set screw about 5 turns to allow positioning of the release
plunger table under the locking set screw.
3) Using a pin punch inserted into the hole in the finger cage, move the table of the
release plunger under the locking set screw.
4) Pivot the arm and lower adapter down into the housing and hold firmly. Tighten
the locking set screw into the arm adapter until it firmly contacts the table on the
end of the release plunger.
5) Rotate the kickover tool 180° in the vice.
6) Remove the set screw from the finger cage.
7) Rotate the kickover tool 180° in the vice to allow the pieces of the sheared shear
pin to fall out. A sight hole is provided 180° from the set screw to aid in aligning
and removing the shear pin.
8) Rotate the kickover tool 180° in the vice.
9) Insert a new shear pin in the shear pin holes in the finger housing and release
plunger.
10) Install the set screw into the hole in the finger cage.

Kickover – Sequence of Operation

Use the minimum amount of stem (e.g. 5 ') during all gaslift wireline operations. The
use of the minimum required jar force will reduce the chances of damaging the latch
and gaslift valve.

Running

Check that the kickover tool and latch are correct for the side pocket mandrel. Pin the
latch to the correct running tool.

1) Run into the well and lower the toolstring past the side pocket into which the
valve is to be set.

2) Pick-up. The kickover tool trigger will rotate the tool to face the pocket. This is
caused by the orientating sleeve which also guides the trigger into the no-go slot.
Pull up (approximately 80 kgs / 175 lbs) to lock the tool into the kickover position.

Note: The amount of overpull increases with the tool size and deviation.

3) Lower the toolstring down to locate the valve in the pocket.

4) Jar down gently to ease the valve into the pocket. The exact amount of
downward jarring is at the operator's discretion, but must be sufficient to position
the latch beneath the latch profile in the side pocket.

5) Jar up. This shears the 2 tangential pins on the running tool and shear pin on the
lower arm. Also the internal shear pin shears as the trigger hits the no-go slot.
This releases the tool to pull out of the hole.

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Pulling

Attach the appropriate pulling tool to the kickover tool.

In highly deviated wells where the `belly' of the SPM may be on the high side:

1) Check well records to establish and previous difficulties.

2) Use a spacer bar if previous difficulty has been encountered locating the pulling
tool on the latch. Add the additional kickover spring leaf (and longer screw if
necessary) to increase the `kick' force.

The sequence is the same as above, but with upward jarring to retrieve the valve.
Downward jarring will shear the pin in the pulling tool.

Valve Catchers

A valve catcher should be set below the side pockets to ensure the valves do not drop
into the casing. A valve catcher could be:

1) Appropriate lock and plug / valve cap assembly run with no packings below the
lowest SPM. The valve cap can be attached to a length of spacer pipe providing
sufficient length to accommodate any dropped valves.

2) A collar stop with a cross pin to prevent the valves passing out the end of the
tubing.

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CAMCO OK-6 KICKOVER TOOL

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CAMCO OM-1 KICKOVER TOOL

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SIDE POCKET VALVE PULLING SEQUENCE

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VALVE INSTALLATION SEQUENCE

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WS-311-E PULLING AND RUNNING OF GASLIFT VALVES FROM SIDE

POCKET MANDRELS

To pull a valve from a SPM.

Whenever a valve from a side pocket Mandrell has to be pulled, the following steps
should be taken
1) Always run a valve catcher below the SPM.
2) Ensure that pressure across the valve is equalised.
3) Gaslift supply should be confirmed closed.
4) Well should be closed in at the wing valve.
5) Fluid level should be checked, with the valve catcher, and used to calculate
differential pressure across the valve.

The design of BK-2 latch is not all that strong, therfore a light toolstring shall be used
and heavy downward jarring shall not be done.

Procedure to pull a valve from a SPM:

1) Rig up as per OPG procedure.

2) Toolstring 5' x 1 1/2" stem, 20" jar and ropesocket.
3) Take control of SCSSV, close gaslift supply valve and wing valve.
4) Run the valve catcher in a nipple or x-over while tagging the fluid level. Calculate
differential pressure across valve assuming annulus filled with gas and tubing
with crude oil. No attempt to pull the valve shall be made if pressures in annulus
and tubing are not equalized. This can result in stripping off the BK-2 latch from
the valve or getting "blown-up" by the gas in the annulus. In this case annulus
pressure should be bled down to reach equal pressure.
5) Install OK… kickover tool with 1 1/4 " JDC (Brass Pin) on toolstring.
6) Check pulling weight before entering the SPM.
7) Pull back slowly allowing the locating finger to orientate the kick-over tool.
8) Allow the tool string weight to increase about 25 lbs indication for positive
orientation and then take a further overpull of 200 lbs to kick out the arm holding
the pulling tool.
9) Repeat the above procedure in case the arm fails to kick over repeat the above
procedure applying an additional overpull of 100 lbs.
10) Go down slowly until JDC locates the valve, slack of weight and close jar slowly,
giving it a light tap to latch on.
11) Pull up to confirm latched on to the valve.
12) Jar lightly up to pull valve from the SPM and monitor the annulus pressure to
confirm valve is pulled from the SPM. POH with KOT.
13) Remove JDC and valve.

Note: If positive indication is seen that valves is pulled from SPM but valve is not
found on the JDC, then the valve will have fallen off. It should be retrieved
with a 1 '/4 " JDC and knuckle joint directly onto the toolstring, from the
valve catcher. Utmost care should be taken when passing a SPM in case
valve sits across the Mandrel.

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Running Procedure to Set a Side Pocket Valve

Steps 1 to 9 similar to pulling a valve

10) Valve with BK-2 latch should be pinned to JK running tool with two 1/8" brass
shear pins fitting under the running neck, and to be filed off properly.

Note: The gaslift valve shall have been fixed with "Lock tight" in the work shop
to the BK-2 latch. As shall all the other thread connections on the gaslift
valve. This prevents the valve and latch to become "unscrewed" during
service, by the vibration of the tubing caused by the injected gas.

11) Install OK-….KOT plus JK running tool with gaslift valve on the toolstring.
12) Run down until below the SPM and pull overpull to kick the OK-..KOT.
13) Go down slowly until valve locates the valve housing.
14) Jarr downward lightly, but be careful not to fully open the jars, since the valve will
be pulled out again.
15) Continue jarring until some solid blows are experienced.
16) Pull some overpull to make sure top latch has engaged.
17) Jarr upward to shear the two 1/8" tangential shearpins and pull to surface.
18) When valve change is completed the valve, catcher will have to be pulled.

Note: Changing out valves should be started from bottom SPM and then go up. This
will result in only one time differential pressure across the bottom valve. The others can
be pulled without differential thereafter. Be aware that by
pulling the bottom valve with possible pressure differential across it, the chance of
getting blown up is great. Therefore:
When jarring out the valve,the moment it pops out of the pocket DO NOT STOP
PULLING OUT until a safe distance away from the SPM.

Whenever a valve has been lost during pulling / running, always fish out the valve first
before pulling / running the next one. There might not be enough room in the catcher to
accommodate 2 valves and could make fishing inside the tubing very difficult.

When changing out valves from the lowest SPM and working upwards, it is good
practice to follow the “Pull-Set,
Pull-Set” method. This eliminates the chance of a dropped or lost valve to end up in an
empty pocket. If more then
1 SPM is empty it might take several wireline trips to "find" and recover the valve.

Valve Latch to Running Tool Pinning Procedure:

BK-2:

The BK-2 latch is the most commenly used 1" latch. It is similar with regard to handling
to the Otis BK, BEK-2 and 3 latches as well as to the 1 '/2" RK latch.

Running tool: JK.

Pulling`tool : 1 '/4" JDC or Otis 1 '/4" SM

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Running tool pinning Procedure

1) With the latch made up to the valve to be run:

2) Check that the latch "shear pin" (3) is not sheared.
3) Position the JK running tool over the top of the latch.
4) Insert 2 x 1/8" brass shear pins through the tangential holes.
5) Cut off the excess pin and file* flush to the running tool.

* Do not cut or file the running tool OD.

6) Attach the running tool to the appropriate kickover tool, e.g.

OK-6.

Pulling Procedure

1) The 1 1/4" JDC is attached to the kickover tool - with a spacer

bar if required.

A spacer bar may be required between the pulling tool and kickover
tool in highly deviated wells where the 'belly' of the SPM is on the
high side.

2) When the pulling tool is correctly positioned in the SPM, it

engages the fishing nec
3) Upward jar action shears the pin in the latch and lifts the "latch
body" (2)
4) Upwards.
5) The "latch ring" (5) can move sideways to provide clearance to
move upwards out of the profile.

Integral or Bottom Latch:

The Integral or Bottom Latch is used on 1 " valves when the upper latch profile is wom
or damaged. The bottom latch is also used in some flowing applications. It is attached
to the nose of the valve and a running head is attached to the upper end.

Running tool - GA-2.

Pulling tool - 1 l/4" JDC.

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Running tool pinning Procedure

Valve with integral latch:

1. Select the correct valve for the operation.

2. Check the packings and overall conditon of the valve.
3. Replace the two brass pins (1) of the shearring just
below the collet (2).

GA-2 Running Tool:

1. Remove any old pieces of shear stock.

2. Check that both steel "roll pins" (2) are in good
condition.
3. Move the “plunger” (1) to line up the “top shear pin
holes” (3) with the “stabiliser” (4).
4. Insert 2 x I/ 8'f brass
shear pins and file
smooth.
5.Back off the plunger by rotating anticlockwise (to the
left).
6. Place the latch fully into the running tool.
7. Insert 2 x 1/ 811 brass shear pins and file smooth.
8. Screw the plunger down to hold the valve firmly.
The internal adjustable plunger holds the valve more
firmly and straighter than the JK type running tool This
makes it easier to locate the valve into the SPM in
deviated wells.
9. Attach the GA-2 to the appropriate kickover tool for the
side pocket mandrel

Running Procedure - The GA-2 shears with downward

jar action.

GA-2 Running Tool

1) As with all kickover tool operations - do not use too much stem and avoid
excessive jarring action, as this can damage the valve and / or the SPM. Use a
minimum amount of stem.
2) Locate the SPM in the normal manner.
3) Tap downwards gently to insert the valve into the pocket.
4) Once the valve is fully located, the downward jar action achieves the following:
i) Shears the top shear pins and running neck shear pins simultaneously.
ii) The plunger is moved upwards (relative to the body by the top of the
latch).
5) Put an upward pull on the latch.
6) Gentle jarring may be necessary to disengage the GA-2, but all pins are already
sheared.
7) The running tool is now free from the latch.

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WS-311-F RUNNING TOOLS FOR GAS LIFT VALVES

The Running Tools are attached to the 15/16”- 10 thread on the bottom end of the
kickover tool arm. The type of tool used depends on the latch. .

GA-2 Used to run the integral latch.

JK To run the BK and similar style latches.
RK-1 To run the RK style latch. Similar in function to the JK tool above.
JC-3 To run the 'R' and RA style latches.

All these tools except the GA-2 jar down to set the latch in the pocket, and jar up to
shear 2 tangential pins. The GA-2 shears downwards after the latch is fully set. Upward
jarring on the GA-2 could shear the collet latch pins on the integral latch.

Running Tool Summary Chart Variations (not illustrated)

Type Assembly # Maximum Fish Neck Length Latch to run
OD
JEK 15069 1.312” 1.187” 4.562” EK dummy valves*
JEK-1 15061 1.187” 1.187” 6.312” EK-1 dummy valves*
C-5 13112 1.750” 1.375” 7.750” R and RA latches in
Otis SPM’s
* Equalising type
JEK Varies from the JK by - No fishing neck.
Approximately '/2" longer.
JEK-1 Varies from the JK by - Approximately 1 '/2" longer.
JC-5 Varies from JC-3 by - 5 3/8" shorter.
(To allow for length variation in Otis SPM's.)

Running Tool Summary Chart + Critical Dimensions

Type Assy # Max OD Fish Neck Length Latch To Run
GA-2 15052 1.187” 1.187” 4.375” Bottom / Integral
JK 15072 1.312” 1.187” 3.984” BK and BK-2
RK-1 15079 1.437” 1.187” 7.000” RK
Body (5) JC-3 15065 1.750” 1.375” 13.125” R and RA
Stabilizer (4)
Shear Pin (3)
Roll Pin (2)
Adjustable Plunger (1)

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1/8” Shear
Pin Holes
1/8”
Shear Pin Holes

3/16” Shear
Pin Holes

Pinning

Shear pins are usually brass, although a combination brass / steel or steel pins can be
used. Take care not to damage the running tool when cutting / filing off ends of the
shear pins.

Design Principle

The GA-2 running tool is designed to use with the K, AK, L and OK series kickover
tools to run on a 1" OD control device with integral bottom collet latches in KB series
side pocket mandrels.

Operating Principle

The operating principle of the GA-2 running tool is mechanically connected to the
running head of 25 mm control device with a bottom latch by two 3 mm shear pins. The
GA-2 running tool is then attached to a K, AK, L or OK kickover tool. The kickover tool
is attached to a wireline work string and run in well to a known depth. The kickover tool
is cocked and the control device is positioned directly above the side pocket. The
control device is jarred down into the pocket until it stops. Then the downward jarring
shears the shear pins and the shear pins at the bottom of the body. The GA-2 running
tool is now free of the valve and can be pulled from the well.

Pinning Procedure

1) Check the roll pins to ensure that they are not damaged. These should be
checked every trip. Replace them if they are damaged.
2) With the body clamped in the vice on the lower part align the groove in the
stabiliser with the top holes in the body.
3) Install two 3 mm x 13 mm long brass shear pins.
4) With a screwdriver turn the adjusting plunger counter clockwise until it stops.
5) Insert the running head of a control device in the bottom of the body and align the
groove above the fishing neck with the lowest shear pin holes of the body and
install two 3 mm shear pins. Bend them slightly outward when approximately half
way in.
6) Screw the adjusting plunger against the top of the running head and tighten
slightly.
7) The GA-2 and control device is now ready to be attached to a kickover tool.

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WS-311-G PULLING TOOLS FOR GASLIFT VALVES AND PRECAUTIONS

The following tools are used to pull the common range of latches:
1¼" JDC Standard Camco jar down to shear pulling tool. Refer to the facing page
for details.
1 1/4" JDC-1 As for JDC above, but with a shorter reach and no threads in the core.
1.66" SM Otis version of the SB with a hole in the core to take the latch top.
1 5/8" JDS Camco jar down to shear pulling tool with a medium reach..
1 1/2" SB Otis jar down to shear pulling tool with a short reach.
2" JDC Camco jar down to shear pulling tool with a short reach.
2" SM Otis jar down to shear pulling tool with a hole in the core to take the latch
top.

It is recommended that Camco / Otis tools should match the latch manufacturer to
ensure compatible fishing neck angles.

Pulling Tool Critical Dimensions

Size Type Maximum Latches Reach Minimum Core Fish Length
OD Working OD* Thread Neck
1¼” JDC 1.291” 0.875” 1.937” 1.312” ¼”-20 1.187” 13.00”
1¼” JDC-1 1.291” 0.875” 0.906” 1.312” None 1.187” 13.00”
1.66” SM 1.188” 0.875” 1.680” N/A ½”-13 1.000” -
15/8” JDS 1.625” 1.187” 1.843” 1.640” ½”-13 1.187” 13.00”
1½” SB 1.437” 1.187” 1.297” N/A ½”-13 1.187” -
2” JDC 3.000” 1.375” 1.437” N/A ½”-13 1.375” 17.437”
2” SM 1.770” 1.375” 1.640” N/A ½”-13 1.375” -

Spacer Bars Attention should be paid to the use of the correct spacer bar, as this
provides the correct leverage and reach to enable the pulling tool to
engage the latch. This becomes critical in highly deviated well where
the SPM may be positioned `belly' upwards.

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1 1/4" JDC PULLING TOOL

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1.66” SM Pulling Tool 2” SM Pulling Tool

40SM7 40SM1

DESIGN SPECIFICATION DESIGN SPECIFICATION

SIZE 1.660 INCHES SPEC RELEASE DATE 2-12-82

OD 1.188 INCHES TYPE SPEC RELEASE REVISION
LENGTH 14.02 INCHES SIZE 2 INCHES
WILL ENGAGE 0.875 INCHES OD 1.776 INCHES
FISH NECK OD 0.875 INCHES LENGTH 15.68 INCHES
REACH 1.68 INCHES WILL ENGAGE 1.375 INCHES
TOP THREAD 15/16-10 UNS FISH NECK OD 1.375 INCHES
BOTTOM THREAD 3/8-16 UNC REACH 1.60 INCHES
TOP THREAD 15/16-10 UNS
BOTTOM THREAD ½-13 UNS

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There are no set rules as to pulling top or bottom valves first. In many areas it is left to
the preference of the operator. In other areas, the sequence is specified in the
programme. The following facts are relevant to recovering gaslift valves:

• By reducing the pressure differential between casing and tubing, the chances of
being blown up the well are reduced.
• Excessive tubing pressure differential can make pulling valves difficult.
• Balanced tubing / casing pressures at the surface does not mean equal pressure
at the valve depth.
• The hydrostatic pressure created by the difference in the tubing / casing fluid
depths can be difficult to calulate.

The vertical height and density of both columns of fluid must be known. While the
tubing fluid depth and gradient may be available and even the annulus fluid gradient
may be known, it is difficult to determine the annulus fluid depth. (It is possible by
conducting an Echometer survey, but this is not usually a viable option at most
locations.)

This pressure difference can be reduced / eliminated by:

• Shutting in the well in advance of wireline operations, and allowing the well to
stabilise.
However, if all the check valves are holding correctly they will prevent the fluid
levels from equalising.
• Decreasing casing pressure as far as is practical, e.g. to manifold pressure.
• Increasing tubing pressure.
• Opening an SSD above the packer and allowing the fluid levels to equalise.
• Pull the bottom valve and observe the following precautions carefully:

Preparation

The operator should be prepared for the valve to be blown out of the SPM by:

i) Maintaining high engine speed.

ii) Ensuring the unit is in high gear BEFORE beginning to jar up.
iii) If the weight indicator drops suddenly, pull upwards IMMEDIATELY and
do not stop.
iv) Retain line pull after each upward jar stroke and observe the weight
indicator to ensure the valve is not free.

Remember - By pulling the bottom valve first, the tubing and annulus will be
fully equalised prior to recovering the upper valves, thus
eliminating chances of being blown up.
- By pulling the upper valve first and working down the well, the
pressure differential is likely to be less therefore reducing the
chances of being blown.

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WS-311-H LACTHES

Latches are designed to screw onto each gaslift valve and latch' the valve into the side
pocket mandrel. The internal design of the SPM and OD of the valve determines the
correct latch.

Refer to the following pages for diagrams and further information.

Latch Summary Chart

Latch SPM Valve Latch Running Running Pulling Maximum OD Pulling Tool
Size Size Neck Tool Neck
BK-2 KB** 1“ Ring 0.750“ JK 0.875“ 1.358“ 1¼“ JDC
KBG 1.66“ SM
BEL-2 KB** 1“ Ring 0.750” JK 0.875” 1.358” 1¼” JDC
1.66” SM
R MMA 1½“ Cam 1.359” JC-3 1.370” 1.750” 2” JDC
2” SB
RA MMA 1½“ Cam 1.359” JC-3 1.370” 1.750” 2” JDC
2” SB
RK MMG 1½“ Ring 0.937” RK-1 1.187” 1.176” 15/8” JDS
1½” SB
RK-1 MMG 1½“ Ring 0.937” RK-1 1.187” 1.176” 15/8” JDS
1½” SB
Integral KB** 1” Collet 0.875” GA-2 0.875” 1.100” collet 1¼” JDC-1 +
1.130” top sub 1¼” JDC
* Core extension required to pull the BEL latch.
+ JDC-1 – Longer core (0.906” reach). Has no Prong threads in the core.

1” Latches

BK-2 : In common use worldwide. The spring-loaded latch ring moves up

and to the side as the latch enters the ‘C’ shaped profile in the SPM.
It locks in place until the pulling tool shears the pin and lifts the pulling
neck. Refer to page 10-20 for more details.

BEK-2 : Similar in apperance to the BK-2 latch and identical for running /
pulling. The BEK-2 (and BEK-3) have a 3/8” hole through the latch
centre for use with circulating or flow devices.

Integral Latch : The KB series mandrels have a profile at the lower end
which will also accept an integral latch (sometimes referred
to as a bottom latch.) This is used if the upper profile
becomes worn.

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2½” Latches

R : The ‘R’ latch use a spring-loaded rotating cam which deflects

upwards as the latch passes into the full circular at the upper end of
the side pocket. Upward jarring on the pulling neck sheard the pin,
and lifts the latch pin to allow the cam to rotate downwards permitting
recovery.

RA : Similar to the ‘R’ latch but with two O-rings to prevent solid particles
settling around the latch. This latch is used more commonly than the
‘R’.

RK : This latch is a scaled up version of the BK-2. Its principle of operation

is the same. It has two O-rings to prevent debris collecting around the
latch ring. It is the most commonly used 1½” latch.

RK-1 : Similar to the RK latch but without the two O-rings.

Camco / Otis / Macco equivalents are shown below each diagram.

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The BK-2 Latch is the most commonly used 1" latch. It has similarities with the BEK-2
and BEK-3, and also the 1 '/2" RK latches. The sequence of operation appears on the
facing page.

Running tool - JK.

Pulling tool - 1¼” JDC (Otis equivalent = 1¼” SM)

Pinning Procedure

With the latch made up to the valve to be

run:
Check that the latch "shear pin" (3) is not
sheared.
Position the JK running tool over the top of
the latch.
Insert 2 x '/8" brass shear pins through the
tangential holes.
Cut off the excess pin and file* flush to the
running tool.
* Do not cut lftle the running tool OD.
Attach the running tool to the appropriate
kickover tool, e.g. OK-6.

Pulling Procedure

The 1/4" JDC is attached to the kickover

tool -with a spacer bar if required. A spacer
bar may be required between the pulling
tool and kiekover tool in highly deviated
wells where the 'belly' of the SPM is on the
high side.

When the pulling tool is correctly positioned in the SPM, it engages the fishing neck.
Upward jar action shears the pin in the latch and lifts the "latch body" (2) upwards.
The "latch ring" (5) can move sideways to provide clearance to move upwards out of
the profile

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CAMCO “BK-2” LATCH

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CAMCO “RA” LATCH

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The RA Latch is a 1 '/2" latch used in MMA mandrels.

Running tool - JC-3.

Pulling tool - 1 5/8" JDS (Otis equivalent = 1 '/2" SB).

Pinning Procedure

With the latch made up to the valve to be run:

Check that the latch “shear pin” (3) is not sheared.
Position that JC-3 running tool over the top of the latch.
Insert 2 x 3/16” brass shear pins through the tangential
holes beneath the running neck.
Cut off the excess pin and file* flush to the running tool.
*DO NOT cut/file the running tool OD.
Attach the running tool to the appropriate kickover tool,
e.g. OM-1.

Pulling Procedure

The 15/8” JDS is attached to the kickover tool – with a

spacer bar if required.
A spacer bar maybe required between the pulling tool
and kickover tool in highly deviated wells where the
‘belly’ of the SPM is on the high side.

When the pulling tool is correctly positioned in the SPM

it engages the fishing neck.

Upward jar action shears the pin in the latch and lifts
the “latch stop” (4) upwards.
The “latch” (8) is now free to rotate downwards to
permit the valve to be jarred upwards out of the profile.

The Integral or Bottom Latch is used on 1" valves when the upper latch profile is worn
or damaged. The bottom latch is also used in some flowing applications. It is attached
to the nose of the valve and a running head is attached to the upper end.

Running tool - GA-2.

Pulling tool - 1 '/4" JDC.

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Pinning Procedure

1. Remove any old pieces of shear stock.

2. Check that both steel "roll pins" (2) are in good condition.
3. Move the "plunger" (1) to line up the "top shear pin holes" (3) with the
"stabiliser" (4).
4. Insert 2 x 1/8" brass shear pins and file smooth.
5. Back off the plunger by rotating anticlockwise (to the left).
6. Place the latch fully into the running tool.
7. Insert 2 x 1/8" brass shear pins and file smooth.
8. Screw the plunger down to hold the valve firmly.
The internal adjustable plunger holds the valve more firmly and straighter than the JK
type running tool.This makes it easier to locate the valve into the SPM in deviated
wells.
9. Attach the GA-2 to the appropriate kickover tool for the side pocket mandrel.

Running Procedure - The GA-2 shears with downward jar action.

As with all kickover tool operations - do not

use too much stem and avoid excessive
jarring action, as this can damage the valve
and / or the SPM. Use a minimum amount of
stem.
Locate the SPM in the normal manner. (Refer
to the "Kickover Tool Section").
Tap downwards gently to insert the valve into
the pocket.
Once the valve is fully located, the downward
jar action achieves the following:
Shears the top shear pins and running neck
shear pins simultaneously.
The plunger is moved upwards (relative to the
body by the top of the latch).
Put an upward pull on the latch.
Gentle jarring may be necessary to disengage
the GA-2, but all pins are already sheared.
The running tool is now free to be picked up
without any upward jarring.

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WS-311-I BASIC GASLIFT VALVE TYPES

The specific details of the extensive choice of flow control devices which can be
installed in SPM's are beyond the scope of this Wireline Operations Manual. However,
a brief overview of some of the more common devices is as follows:

Gaslift Valves

Casing Pressure Sensitive - (Also called injection pressure sensitive.) Operated by

casing gas pressure acting on a bellows against the force of the preset nitrogen
pressure inside the valve.

These valves are installed with the highest pressure valves nearest to the surface.
i.e. Each deeper valve has a lower pressure setting than the valve above. An orifice
valve is usually installed at the bottom and this becomes the `working' valve. The upper
valves are used to `unload' the column of fluid in the well only, and then shut in as the
casing pressure drops.

For Example 1" valves - BK / BK-1 / BKT / BKT-1.

1 '/2" valves - R-20 / RMI.

Tubing Pressure Sensitive - (Also called production pressure sensitive.) Operated by

pressure in the tubing acting against the preset spring through a `crossover seat'.
When the tubing pressure exceeds the spring force the opens and permits gas from the
casing to enter the tubing. Casing pressure will not open these valves.

The lowest pressure valves are nearest to the surface. i.e. Each deeper valve has a
higher pressure setting than the valve above. An orifice valve is usually installed at the
bottom and this becomes the `working' valve. The upper valves are used to `unload'
the column of fluid in the well only.

On the surface and while running in, these valves will be closed. The valve will only
open when the hydrostatic pressure in the well exceeds the preset spring tension.
Therefore all the valves should be open when installed at their correct depths.

For Example 1 " valves - B KR-5 / BKF-6.

1 '/2" valves - R-25 / R-25P.

Orifice Valves

Installed in the SPM for continuous tubing flow gaslift applications, sometimes below a
sequence of casing or tubing pressure sensitive valves.

For Example 1" valves - DKO-2 / BKO-3.

1 '/2" valves - RDO-5.

These valves are available with fixed orifices within the range of '/8" to 3/8" (in '/16"
increments) with a check valve in the nose to prevent back flow from the tubing to
casing.

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WS-311-J DUMMY VALVES

Dummy Valves are used to block off the ports in the SPM during the completion phase
to enable pressure testing of the tubing and other downhole components. The SPM's
with the dummy valves installed, should be pressure tested at the surface prior to being
run into the well.

The dummy valves remain in place until gaslift valves are required to be installed to
enhance / optimise the production rate of the well.

The following types of dummy valves are in use:

'E' dummy (1 ") - Run with a BK-2 latch into KB series mandrels.

DKO-11 (1 ") - Run with an integral latch.

RD Dummy (1 '/2") - Run into the MM series mandrels on an 'R' or RA latch.

Equalising Dummy Valves

Dummy valves are available with an equalising device to permit the balancing of the
pressure differential at the valve before pulling the valve from the pocket.

EK-1 / BKEO Types These have an internal sleeve which is moved downwards to
open an equaising port.

EK / RKED / CEV Types These have a removable inner prong which is recovered
in a separate run prior to recovery of the body of the valve.

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WS-311-K SPECIAL TYPE VALVES

Chemical Injection Valves

Used to permit the introduction of chemicals such as inhibitor, injected down the
casing. The production is treated at valve depth, which reduces the amount of tubing
subjected to corrosive fluids. Volumetric control is achieved by a metering pump on the
surface.

The valve is actuated by differential pressure between the tubing and annulus, and the
spring rate can be adjusted to the required injection pressure. A check valve in the
nose prevents reverse flow.

For Example 1" valves - BKHLK-2 (N2 charged) / LK-3 (spring set).
1 '/2" valves - RCBH (N2 charged) / RLC-3 (spring set).

Differential Kill Valve

Designed to hold differential pressure from the tubing, but can be `pumped' out with
pressure from the casing.

Pressure at which the internal sealing plug moves to permit the annulus pressure to
enter the tubing is predetermined by the number of shear screws inserted in the valve.
When this valve is opened (sheared) the piston remains in the locked open position.
The valve must be retrieved to be reset.

For Example 1" valves - DCK-2.

1 '/2" valves - DCR-1.

Water Flood Control Valves

Water flood flow regulator valves regulate water injection volumes into multiple zones
through a single tubing string.

For Example 1" valves - KCW.

1 '/2" valves - RW / RWW.

Pressure / Temperature Recorders

Several types of Electronic Memory Recorders (EMR) are available for installation in
the side pocket to record well flowing and shut-in pressures / temperatures over
extended periods of time without restricting well flow.

Metrol (UK) manufacture a system which permits inductive transfer of data and
reprogramming from an instrument positioned adjacent to the gauge in the pocket.

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Chapter 11, Gaslift Wireline Operations Page 37 of 40
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WS-311-L VALVE CATCHER

A Valve Catcher is installed in the tubing string below the lowest SPM prior to
commencing the change out of gaslift valves/ dummies / injection valves etc.

The Catcher is installed to recover valves that were lost during pulling or setting
operations or were not properly set and popped out of the SPM when lift gas was
opened up to the annulus after completing the change out. Once the valve is lost, it will
not fall out of the end of the tubing but drop into the Catcher. From there it can easily
be recovered by simply pulling the Catcher or run the appropriate pulling tool on a
standard toolstring and fish it out of the Catcher.

Several types of Catchers are available and consist off:

1) X-lock without packing, equalising valve without melon or perforated extension

pipe, valve cap.
To be set in a X nipple or SSD below the lowest SPM.

2) X-lock fishing neck welded onto perforated pipe (any length) closed at the
bottom.
To be set on top of X-over, separation tool or tubing plug.

3) A collar stop with cross pins to prevent the valve from falling through.
To be set in tubing with collar recess (EUE only).

4) A slip type lock with cross pins.

To be set in smaller size tubing without nipples and collar recesses (2” and 2 3/8”
tubing).

It is good practise to fish out a valve immediately after its lost. Most Catchers can
accommodate only one valve at the time. Having lost valves “Stacking up” makes it
very difficult to fish, especially in the larger tubing sizes.

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Chapter 11, Gaslift Wireline Operations Page 38 of 40
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WS-311-M CX GASLIFT MANDREL, VALVE CARRIER AND 9/16” VALVES

Otis concentric gas lift valves are made up as part of the production string during the
completion stage of the well.
It is primarily designed to accommodate concentric gas lift valves.

The mandrels have an integral Sliding Side Door circulating device, opened and closed
by standard wireline methods.

The Side Door feature provides communication between tubing and annulus for various
well procedures prior to housing a gas lift valve.

An X-landing nipple profile is machined into the upper section of the mandrel for
installing flow controls, plugs etc.

In BSP the mandrel is used to install a valve carrier with an external 9/16” gas lift valve
(CMOFS-Macco). The valve carrier is equipped with an X-lock with V-packing to seal
off in the upper seal bore and a lower packing sub to seal off in the lower seal bore of
the mandrel.

Prior to installing the CMOFS assembly, the SSD need s to be opened. (Ref: WS-310-
A).

Installation of the CMOFS assembly is similar to setting of a straddle tool (Ref: WS-
309-T) but without equalising valve.

Prior to pulling the assembly, the annulus needs to be bled down to 1500 kPa
below CITHP, this has proven to be the safest way to recover the assembly without
getting blown up. A GR pulling tool is used initially, if premature pin shearing occurs,
Run the GS pulling tool.

The disadvantage of this old type gaslift system is that any well intervention to be
carried out below the gas lift mandrel(s) requires additional wireline work: Pulling
valve(s) and closing sleeve(s) prior to the operation, opening sleeve(s) and setting
valve(s) upon completion of the operation. This problem has been solved by the
introduction of Side Pocket Mandrels in present completions.

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Chapter 11, Gaslift Wireline Operations Page 39 of 40
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

Assembly Number 121CX1 121CX3 121CX13

Thread Connection / Inches 23/8 EU 27/8 EU 3½ EU
Minimum I.D./ Inches 1.875 2.213 2.750
Maximum ºD./Inches 3.093 3.750 4.200
Shifting Tool 42B0116 42B0118 42B0147

DETAIL PART NAME QTY PART NO PART NO PART NO

1 Spacer Sub 1 121X3 121X10 121X150
2 O-Ring 1 91Q1229-H 91Q1234-H 91Q12377-H
3 Top Sub 1 121X1 121X8 121X153
4 Nipple 1 121A39 121A645 121X152
5 O-Ring 2 91Q1229-H 91Q1234-H 91Q1237-H
6 Male-Packing Adapter 1 121A18 121A21 121X51
7 Split-Ring Segment (*) 121A43(4) 121A48(4) 121X53 (6)
8 O-Ring 1 91Q1331-H 91Q131-H 91Q1338-H
9 Female-Packing Adapter 4 121A17 121A644 121X54
10 Closing Sleev 1 121A41 121A46 121X56
11 V-Packing (*) 91V83 (10) 91V84 (10) 91V3329 (12)
12 O-Ring 1 91Q1331-H 91Q131-H 91Q198-H
13 Female-Packing Adapter 2 121A17 121A644 121X52
14 Bottom Sub 1 121X2 121X9 121X151

(*) quantity shown in parentheses after part number

OTIS TYPE CX GASLIFT

MANDREL

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Chapter 11, Gaslift Wireline Operations Page 40 of 40
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

CHAPTER 12
TEST TOOLS

TABLE OF CONTENTS

WS-312-A “QN” TEST TOOL (BSP VERSION)................................................................2

WS-312-B “XO” SELECTIVE TEST TOOL .......................................................................4
WS-312-C MODIFIED “PX” TEST TOOL .........................................................................6

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Chapter 12, Modified “PX” Test Tool Page 1 of 6
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

WS-312-A “QN” TEST TOOL (BSP VERSION)

Uses of Test Tools

(i) To test tubing - usually immediately after running tubing and prior to perforating.
(ii) Set the hydraulic packer.
(iii) Protect the lower formation while stimulating the upper zone.

Actual Types of Test Tools

1) QN Test Tool.
2) XO Selective Test Tool.
3) PX Modified Test Tool

‘QN' Test Tool (BSP version).

Designed to run into the XN nipple and seat against the no-go ring while sealing in the
packing bore. As pressure will only be held from above, all V-packings face upward.

A built-in check valve permits easy equalising. This check valve has a rubber seal for
low pressure sealing, with a high pressure metal-to-metal seat included.

This same design of check / equalising device is utilised also on the 'XO' selective and
modified 'P' test tools.

It is usual to test against the 'QN' test tool after removing the toolstring from the well.
However if the wire and toolstring is to be left attached to the 'QN' test tool during the
pressure test, the following precautions should be observed:

1) Pressure test the lubricator assembly immediately prior to running the 'QN' test
tool. This is to ensure there are no minor leaks which could invalidate a tubing
pressure test.

2) Ensure the tubing is clean - pressure testing `flexes' tubing and will deposit any
scale and sand around the toolstring.

IF THERE IS ANY DOUBT - REMOVE THE TOOLSTRING DURING THE TEST.

3) After the test, bleed the pressure off SLOWLY while pulling a bind on the wire
with the hydraulics of the wirel unit.

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Chapter 12, Modified “PX” Test Tool Page 2 of 6
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

Q / N TEST TOOL

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Chapter 12, Modified “PX” Test Tool Page 3 of 6
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

WS-312-B “XO” SELECTIVE TEST TOOL

Running

Attach an "SSJ" or "RJ" or "JDJ" pulling tool onto the wireline work string. Latch the
"XO" selective test tool in the pulling tool and run the selective test tool to the "XN"
nipple if the testing procedure calls for it.

There is a no-go shoulder below the packing stack that allows for a test to be made at
that point. If there are "X" line landing nipples up in the tubing string that are to be used
in the test the "XO" selective test tool will be converted to the locating mode when it is
pulled out of the "XN" nipple and run through the next "X" nipple up the hole.

Setting

If the selective test tool is to be left there for some time, the pulling tool can be sheared
by jarring down and the tools retrieved.

If the test tool is to be moved up the hole for further testing, the work string can be left
in the hole and the test tool can be moved up the hole as the procedure calls for.

The "XO" selective test tool can be located in any "X" nipple profile and the "XN" nipple.
The "XO"selective test tool uses the locating dog and retracting locating key idea found
in the "B" positive downshift positioning tool.

Pulling

In instances where the "XO" selective test tool has been left in the hole for prolonged
testing and needs to be pulled, follow this procedure: Attach ajar down to shear pulling
tool to the work string and run the tools down to the test tool. After latching the fishing
neck screwed onto the drop a moderate bump up will lift the drop off its seat and allow
hydrostatic pressure above the test tool to equalize.

When equalizing has been completed, the test tool can be retrieved or raised to the
next test depth.

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Chapter 12, Modified “PX” Test Tool Page 4 of 6
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Chapter 12, Modified “PX” Test Tool Page 5 of 6
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

WS-312-C MODIFIED “PX” TEST TOOL

The Modified PX Test Tool holds

pressure from above ONLY. For
this reason, the V-packing on the
lock and prong FACE
UPWARDS.

The lock mandrel is run without

keys, so the position of the lock
fishing neck and expander
mandrel can be inserted into
plug and the whole assembly run
on an SB.

When pulling, it is occasionally

possible to recover the prong
and lock together. However, if
there is any sand or scale to
hold the plug, the prong will be
recovered first and the lock is
recovered with a GS or GR.

Use of this plug minimises the

risk of being stuck beneath sand
or scale after pressure testing
the tubing.

Note: The hole thru the

bottom of the sub. The
prong is a V-packing
type-not an element
seat design.

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Chapter 12, Modified “PX” Test Tool Page 6 of 6
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

CHAPTER 13
RUNNING AND PULLING OF BHP/T EMR GAUGES AND
SHUT IN TOOLS
TABLE OF CONTENTS

WS-313-A RUNNING AND PULLING OF AMETROLOG EMR GAUGES ......................2

WS-313-B “Z-I PROBE” DOWNHOLE SHUT IN TOOL ...................................................7
WS-313-C CAMCO DOWN HOLE SHUT IN TOOL .......................................................10
WS-313-D SAFE OPERATING, HANDLING, STORAGE AND DISPOSAL OF LITHIUM
BATTERIES ..................................................................................................14

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BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

WS-313-A RUNNING AND PULLING OF AMETROLOG EMR GAUGES

Formation Pressure and Temperature data is essential for reservoir evaluation and
monitoring. The instruments to obtain this information and currently used by BSP are:

AMEtrolog –B downhole memory gauges. For specifications see page 5of 5.

These EMR ,s (electronic memory recorders) are run on wireline and store data to be
downloaded to a computer when the gauges are returned to surface.

The gauges sensor pressure ranges are 3000, 5000 and 10000 psi

The temperature sensor goes to 150 degrees Celcius maximum.

Type of Surveys run in BSP.

• Static Gradient Survey

• Flowing Survey
• Flowing and Build Up Survey
• Long Duration Survey

Static Gradient Survey:

1) The tool string used for the survey consists of a rope socket, 3 or 5 foot of stem
depending on CITHP, swivel EMR gauge, swivel and second EMR gauge.
2) Assemle the gauges and thighten connections with open ended wrenches
provided. Never use pipe wrenches!
3) Make up gauges to the tool string and pull up in the lubricator.
4) Zero the counter on the wireline unit with the bottom of the lower gauge at the
tubing hanger flange. Pull gauges nto the lubricator as close to the stuffing box as
possible.
5) With bleed off valves open, stab lubricator onto BOP and tighten Quick union
(check o-ring for damage) record first 15 min. of the survey.
6) Close bleed off valves and open swab valve slowly. Record CITHP for 15 min.
7) Run in the and carry out the Static survey as per program requirements.
8) Maximum run in / pull out speed is 50m per min.
9) Slow down when passing through: SC-SSSV or TR-SSV, SPM,s, Nipples, SSD,s
and Packers.
10) When the survey is completed and gauges recorded last stop in the lubricator,
close swab valve bleed off lubricator slowly and record atmospheric pressure for
15 min.
11) Lift lubricator, lower tool string with gauges and remove same from tool string.

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BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

Flowing Survey:

1) Go through step 1 to 6 as described in Static Survey above.

2) Close bleed off valves and open swab valves slowly . Record FTHP for 15min.
3) Run in the hole at moderate speed (50m per minute maximum.) In case of
running the survey through the SC-SSV, stop about 25 m above the valve.
Remember the well is flowing.
4) Close the well in at the wing valve and pass through the valve with the gauges.
About 15 m below the valve, open the well up again by slowly opening the wing
valve.
5) Carry out the Flowing Survey as per program requirements.
6) When coming to surface ,close in the well when tools are15 m below SC-SSSV.
7) Pull slowly through the valve and when 30m above the valve re-open well
gradually with wing valve.
8) With last stop completed in the lubricator, bleed off and record atmospheric
pressure for 15 min.
9) Lift lubricator, lower tool string and remove gauges.

Flowing Build Up Survey:

Two types of FBU,s may be carried out :

A: With gauges suspended in X or XN nipple on X /XN lockmandrel (without V-

packing) , Cross over flow sub and Shock Absorber.

B: With gauges suspended in X or XN nipple, on X or XN lock mandrel with V-

packing , Equalising Sub, Z.I. Probe Down Hole Shut-In Tool or Camco DHSIT
and Shock Absorber.

The Z.I. Probe DHSIT. Can be programmed to close and open the well downhole to a
maximum of 12 sequences
(See WS-313-B for complete specifications.) Although the tool has a build in “self
equalsing” feature, the regular X
equalising assembly is run just in case the electronic system has malfunctioned.

The Camco DHSIT. Can not be programmed and requires an extra run with the closing
prong to shut the well in at the DHSIT.(See WS-313-C for operational details).

Running and pulling procedure is identical to running XX or XN plugs (See WS- 309-
L) with the exception of:

Survey A: No need for running and pulling prong as X-over flow sub is wide open
and no equalising valve has been incorporated in the assembly.

Survey B: No need for running prong as DHSIT is wide open. BUT need to run
equalising prong on the GR pulling tool in case of malfunctioning of the
“self equalising “ feature in the Z.I. Probe and always with the Camco
DHSIT.

Note: Running /Pulling speed for DHSIT is 30m per minute maximum.

Long duration Survey:

Identical to Flowing Build-Up survey but over an extended period of time (3 month is no
exception).
Running / setting and pulling procedures are as for Survey A (see above).

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Chapter 13, Running & Pulling of BHP/T EMR Gauges & Shut in Tools Page 3 of 20
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

Spring Working Load

1.250” 054 lb
1.500” 100 lb
1.750” 100 lb
The B.D.K. Shock Absorber is
Item Description used in the wireline toolstring
1 Top Sub to reduce the effects of shock
2 Retainer when running delicate gauges
3 Piston etc. The Shock Absorber is
4 Sleeve most effective when run
directly above the gauges.
5 Bottom Sub
6 Spring
7 Spring
8 Grub Screw

Cross Over Flow Sub

Note : Conversion rate 1” = 25.4mm

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Chapter 13, Running & Pulling of BHP/T EMR Gauges & Shut in Tools Page 4 of 20
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

AMEtrolog
high accuracy downhole pressure and temperature memory gauge
run with wireline (slick line) or as part of a testing string
Main applications

Reservoir and well testing AVAILABLE

Static, flowing and build-up serveys IN VERY SHORT VERSION
Long duration data recording FOR RUNNING IN
Production testing and artificial lif control SIDE POCKET MANDRELS
Multi well surveys without reprogramming

Main specifications

Maximum working pressure in psi (bar) 15000 (1000)

Temperature range in F° (°C) 0 to 300 (-20 to 150)

Pressure channel
Sensor type Piezoresistive
Standard sensor ranges in psi (bar) 3000, 6000, 8000, 10000 or 15000
- other ranges on request – (200, 400, 600, 700 or 1000)
Accuracy in % of full scale ± 0.05
Resolution in psi (bar) 0.02 (0.0015)

Temperature channel
Sensor type Semiconductor
Accuracy in °F (°C) ± 0.6 (0.3)

Memory
Type non volatile
Capacity (data points: Pressure or 43000 (1.25” or 1” OD gauges)
temperature) 174000 or 350000 (1.25” OD gauges only)

Max. n° of jobs without reprogramming 32

Mechincal charcteristics
Material Stainless steel
Service H2S and CO2
HPC test pressure I psi (bar) 18000 (1200)
Outside diameter in inches (cm) 1.25 (3.175) 1.00 (2.54)
Length in inches (cm) 29 (73) 65 (165)
Weight in lbs (Kg) 6 (3) 11 (5.5)
Thread connections (PU * BD) 15
/16” SR 11
/16” SR
Bottom nose connection (female) ¼” NPT ¼” NPT

Power supply
Battery type F H
Nominal battery voltage in volts 7 10.5
Cut-off voltage in volts 5 8.5

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BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

A minimum set of AMEtrolog includes: A complete set of AMEtrolog includes :

1 AMEtrolog downhole memory gauge 2 AMEtrolog downhole memory gauges
1 HPC interface cable (to connect to any PC) 1 HPC interface cable (to connect to any PC)
Operation software and user’s manual 1 Gauge Testing Interface & Programming
Gauge calibration sheet Module
O-rings, connectors and screws (for first jobs) Operation software and user’s manual
And a carrying case for all the above Gauge calibration sheets
O-rings, connector and screws (for first jobs)
And a carrying case for all the above

As all AMEtrolog gauges are serviced and programmed in the Gauge Workshop, at this
point it will not be nessecary to go into details about the operation of the gauge. The
operator carries out the survey as per program and does not get involved in the
assembly or dis-assembly of the gauge offshore. Once the gauges are returned to the
Gauge Workshop, the data will be down loaded and handed over to the Reservoir
Department.

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BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

WS-313-B “Z-I PROBE” DOWNHOLE SHUT IN TOOL

The “Z-I Probe” Down Hole Shut In Tool provides the ability to to obtain a flowing
pressure recording, then shut the well in downhole to enable a more rapid stabilisation
of the BHP as the whole tubing volume does not have to be pressurised.This tool
isolates the tubing from the formation thus removing the “tubing storage effect”.

Wireline Tool Description

The 2.50" Outer Diameter (OD) ST is usually run in 3 1/2" tubing. The Wireline
Company provides the required tool
string. These tools include an X-lock
and a mechanical equalizing sub. A
cross over may be required
depending on the lock and
equalizing sub used.

Below the equalizing sub hangs the

ST. At the bottom end of the ST, a
shock absorber is connected to the
gauges via a 5/8" sucker road (with
a 15/16" thread) on an adapter
(Shock Absorber Adapter).

It is mandatory that a mechanical

equalizing sub always be used when
running the Downhole Shut-in Tool
in the event that the Downhole
Shut-in Tool fails downhole. This will
result in a manual option to equalize
the well prior to releasing the tool
from the locking profile.

It is recommended that a Kobe

knock-out equalizing sub be used as
it has been proven to be reliable. Z.I.
Probes is able to supply a crossover
with a Kobe knock-out included.

WARNING

AN EQUALIZING SUB MUST

ALWAYS BE USED WITH THE ST
TO ENABLE THE WELL TO
EQUALIZE SHOULD THE ST FAIL
TO OPEN.

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BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

Theory of Operation

The shut-in tool is an electronic multi-stage tool which can be programmed to shut in
and to open the well automatically. It consists of a drive shaft driven by an electric D.C.
motor to operate a valve system that opens or closes the well downhole. In the open
position, flow occurs through the radial holes and in the close position the radial flow is
blocked, as shown in Figure 2-2. A `program' specifies the timing of the valve's
opening and closing sequences, which is determined by the user prior to the test.

It is important to note that while the ST valve is closed, there will often be a build up of
pressure difference between the well bore, which is above the ST, and the reservoir
pressure, which is below the ST (see Figure 2-1). This pressure difference must be
equalized prior to retrieving the ST. It is critical that the ST MUST be in the open
position prior to retrieving it from the hole. There must, therefore, always be a backup
mechanical equalizer to ensure pressure equalization in the event that the ST fails to
open.

FIGURE 2-2: ST FLOW DIAGRAM

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BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

Description Specification
FLOW SPECIFICATION:
90% Restriction Approximately 3.0 minute
100% Restriction Approximately 4.5 minutes
Flow Area 2.454 in²
MECHANICAL SPECIFICATION
Total Length 49.00”
Diameter (O.D.) 1.75” (Drive Section)
2.50” (Valve Section)
Lock Mandrel Adapter
Thread Specification: 2-¼ - 12- SLB – 2B
Shock Absorber Adapter
Thread Specification: 5
/8” Sucker Rod Box
15
/16”-10-UNC-2B
BATTERY:
Power Source  10.5 V Lithium Battery
Life Approximately 4 sets of Opening & Closing (4 tests)
The life of the battery depends on the well condition or
environment. The approximate 4 sets is base on the
average statistic test taken over the years.
PROGRAMMING:
Modes Open and Close
Program Steps Maximum 10 shut-in and openng Sequences
Time interval 10 minutes  T  1 Year
PRESSURE RATING:
External Maximum 10,000 psi
Differential Maximum 10,000 psi
ENVIRONMENT RATING:
Temperature Up to 150°C (300°F)
Sour – H2S < 5.0%

TABLE 2-1: TECHNICAL SPECIFICATION SHEET

Precautionart Actions:

Cleanliness

An adequate clean working area (eg. clean workbench) is required during disassembly
and re-dressing of the tool. After each test and prior to re-dressing the tool, all
components described in this manual must be cleaned of dirt and grease.

Power source

Check the battery voltage prior to a test. Take note of the number of tests the battery
has been on so as not to exceed its battery life which is a total of 4 sets of open and
close steps in a well test condition. Use a ST Battery Tester to load the battery pack
(refer to Figure 9-1). If the load reading is more than 0.600 it is OK to use.

Wireline Running Speed

Wireline speed should never exceed 30 metres per minute while running in the hole.

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BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

WS-313-C CAMCO DOWN HOLE SHUT IN TOOL

The Camco MD isolation tool is a Down Hole Shut-In Tool (DHSIT) that can be run on
solid wireline to suspend BHP / BHT gauges of either the mechanical (Amerada) or
Electronic Memory Recorder (EMR) type.

The ability to obtain a flowing pressure through the large flow ports and then shut in the
well with the DHSIT, enables a more rapid stabilisation of pressure as the tubing
volume does not have to be pressurised. This tool isolates the tubing from the
formation, thus removing the `tubing storage effect'. It has both `metal-to-metal' and
resilient sealing surfaces to ensure a seal.

Test Procedure

Use the following procedure to test the MD isolation tool for leaks prior to installation:

1) Attach the MD isolation tool to the appropriate lock mandrel.

2) Lock the isolation tool and lock assembly into a landing nipple.

3) Run the appropriate setting prong into the isolation tool to release the release
collet and close the tool.

4) Cap off the lower end of the landing nipple.

5) Fill the landing nipple with water.

6) Remove all air from the nipple and pressure the nipple to 5,000 psi.

7) Maintain the test pressure for 30 minutes and inspect the tool for leaks.

8) Bleed the test pressure and remove the isolation tool from the landing nipple.

9) Manually lock the tool open.

Running Procedure

1) Check all internal O-rings and "equalising piston shear pins" (4).

2) The DHSIT tool is attached to a lock mandrel, and a shock absorber is placed
between the DHSIT and the recording instruments to isolate the vibration from
the jarring action required to set the lock into the nipple profile.
3) Manually lock the DHSIT into the `open' position.
Lower the assembly into the well bore and lock into the nipple profile.

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BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

Operational Procedure

1) The well is flowed through the tool to obtain a flowing bottom hole pressure and
temperature.

2) When a shut-in is required:

i) Attach a prong to a toolstring.
ii) (It is recommended to use centralisers on the stem, especially in large
diameter tubing.)
iii) Lower the tools until the prong contacts the release collet and unlatches
the collet fingers.
iv) The upward pull on the toolstring closes the "plunger" (10) and blocks the
flow.

Pulling Procedure

1) Select the correct pulling tool for the lock mandrel.

2) Attach the equalising prong.

3) RIH with the pulling tool and prong.

4) When the tools reach the DHSIT, jar down very gently to shear the "tangential
pin" (4) in the "equalising piston" (5).

5) Observe equalisation at the surface.

6) When fully equalised - recover the complete assembly.

Manual Locking Procedure

Follow this procedure to lock open the MD isolation tool prior to installation. Refer to
the assembly drawing and parts list for the item numbers in parentheses.

1) Back off the "body connector" (15) until the milled window in the "housing" (11) is
fully exposed.

2) Completely depress the "plunger" (10) with a setting prong.

3) Insert a screwdriver through the milled window into the groove in the "release
collet" (12).

4) Move the screwdriver handle up to force the upset diameter of the "release collet"
(12) below the recess diameter of the "housing" (11).

5) While holding the screwdriver in the `up' position, release the force of the setting
prong on the "plunger" (10) to allow the "collet mandrel" (14) to move up and lock
the "release collet" (12) in place.

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BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

Roll Pin (1)

O-Ring (2)
O-Ring (3)
Lock Adapter (6)

Shear Pin (4)

Housing (11)

Equalizing Piston (5)

O-Ring (7)
Seat Insert (8)

Soft seat (9)

Plunger (10)

Release collet (12)

Collet Mandrel (14)

Return Spring (13)

Body Connector (15)

Setting spring (16)

Camco Downhole Shut in Tool

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BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

Annulus Fluid

Wireline
Weight Bar

Centralizer

Closing Prong

Lock

Packer

Equalizing Sub

MD Isolation Tool

Shock Absorber

Well Fluid

Pressure instrument

RUNNING ASSEMBLY

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Chapter 13, Running & Pulling of BHP/T EMR Gauges & Shut in Tools Page 13 of 20
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

WS-313-D SAFE OPERATING, HANDLING, STORAGE AND DISPOSAL OF

LITHIUM BATTERIES

Introduction

Since the mid-1999's, an increasing number of our daily well servicing equipment ,
particularly the survey gauges, are powered by lithium batteries.

Lithium battery technology has the following advantages over conventional battery
technology:
• Relatively light weight
• Wide range of operating temperatures
• High energy density
• Constant voltage profiles
• Long shelf life

When used properly, lithium battery technology is safe, and cost effective.

If basic operating and handling procedures are not adhered to when working
with lithium batteries, life-threatening situations can develop (including
explosion, chemical fire, venting of toxic fumes).

This document gives an overview of lithium batteries in Metrology Electronic Gauges &
Z.1. Probes Shut of Tool for well logging operations, and is aimed at helping the Field
Supervisor & Gauge Specialist to avoid mis-use or abuse of lithium battery technology
on the TSW-4 Well Services Worksite & Workshop.

Lithium Batteries - basic information

The designed of the lithium battery packs can tolerant adverse conditions, however,
these very active chemical systems have limitations. Certain hazards are associated
with exposure to heat and its subsequent effects on sealed cells. These hazards
include possible battery venting, explosion and/or fires. The initial source of heat can
be external (fire, soldering iron) or internal, such as heating caused by short circuit,
forced over-discharging, charging conditions or excessive mechanical abuse.

In particular, mechanical abuse in the form of excessive shock or vibration can result in
case deformation or crushing and damage to the electrodes and/or separator material.
Such excessive mechanical abuse could result in severe structural deformation of the
case or internal components leading to a sudden explosion. This is more likely to
happen to the high powered, multi-cell, series-connected lithium batteries which can
rupture or explode at high temperature, on forced discharge, or abuse

Pure lithium has a melting point of 179°C (355°F). At this temperature, lithium batteries
may rupture, vent or explode. The temperature inside the battery at any given time is
the sum of the ambient temperature and the induced temperature.

Coin-cell lithium batteries are generally considered not to pose an explosion/fire

hazard. They are graded in standard UL 1642 by the weight of metallic lithium in the
cell.

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Chapter 13, Running & Pulling of BHP/T EMR Gauges & Shut in Tools Page 14 of 20
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

Most primary Lithium cells have a warning printed on their label that cautions against
the following conditions:

• Short-circuit
• Charging
• Forced over-discharge
• Excessive heating or incineration
• Crush, puncture or disassembly.

General Hazard of Lithium Batteries

• Lithium metal reacts explosively with water.

• Thionyl and sulfuryl chloride are both toxic and corrosive. They will immediately
decompose on exposure to humid air, giving off toxic and corrosive fumes.
• Lithium batteries are sealed. However, they cannot withstand direct downhole
pressures, and are run in a pressure housing. If they are subjected directly to
downhole pressures, they are likely to be crushed. Crushing causes internal short
circuits, which in turn can induce a sufficiently large temperature increase that the
cell ruptures or explodes.
• Lithium batteries should not be fully depleted in normal operations.
• Areas of concern when working with Lithium batteries are rupture, venting and
explosion of the cell.
• Rupture of a cell is the breaking or external parting of the cell. This usually occurs
as a ' result of crushing, cutting or puncturing of the cell by an outside force.
Rupture exposes the lithium and thionyl chloride.
• Venting is a result of internal heat and pressure build up, creating a crack in the
external wall of the cell. Venting exposes the lithium and thionyl chloride.
• Explosion is the result of rapid internal cell heat and pressure build up, followed
by the violent release of the stored energy. This event will shower a wide area
with lithium particles and thionyl chloride.

All batteries supplied by Metrology Electronic Gauge have a special instrument device
(Clock) to measure the usage of batteries ( 95% utilization) and the Z.I. Probes Shut
Off Tool has four (4) safety fuses located on the bottom once a fuse blows the tool
stops functioning completey. The fuse reduces the possibility of a short circuit in the
assembled battery, and therefore reduces the possibility of an explosion occurring.

Occasionally, a fuse on a new battery will have failed. The failure may be simply a bad
fuse, or it may be due to an internal short as a result of a manufacturing or shipping
damage. Fuses should not, under any circumstances, be changed in the field. The
battery must be treated as suspect, and returned to the PTAS an agent for the
Metrology maintenance facility via the Well Service Gauge Specialist.

Standard Precautions When Working With Lithium Batteries

The following equipment uses lithium batteries as a power source:

Service Tool Open Voltage Minimum Maximum Comments

Mnemonic Circuit with Load Depleted Operating
Voltage Voltage Temperature
Z.I. Probes 11V 9V 6V 150 C Lil Cells
S.T.
AMEtrolog F15E 9V 9V 95% 150C
Usage
CGM F15E 9V 7V 95% 150 C
Usage

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Chapter 13, Running & Pulling of BHP/T EMR Gauges & Shut in Tools Page 15 of 20
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

• Batteries should be stored vertically in their shipping containers, or in a battery

storage drum, in a cool, dry place.
• A lithium battery field emergency kit must be available at the wellsite. The Field
Supervisor should ask the Gauge Specialist or operator to produce the kit on first
arrival at the wellsite. The Gauge Specialist or Operator should know how to use
the kit properly.
• Lithium batteries should not be short-circuited.
• No attempt must be made to charge a Lithium battery. No external voltage supply
should be connected to a Lithium battery.
• Lithium batteries must not be crushed, punctured or cut into. No attempt should
be made to try and get into a Lithium battery pack or cell.

Avoid any heavy impact on or sudden deformation of the housing of a Lithium battery
pack. Excessive force (such as hammering or repeated blows) should not be used to
try and free a battery pack lodged inside any type of housing.

• Do not throw Lithium cells into a fire.

• Do not subject Lithium cells to temperatures in excess of 150°C.

• Lithium batteries should not be loaded or unloaded in the rain.

• Do not dispose of Lithium batteries in public landfills or bodies of water.

Immersion in water typically discharges the battery, without explosion, as the
temperature is controlled.

• Battery terminals should be insulated with tape when not in use, to protect them
from accidental short circuit. Connections should be cleaned with approved
contact cleaner after removing the tape.

• Always take care when opening a battery housing after use. If there is any sign of
pressure or gas leakage, stop and take the proper precautions, including putting
on the proper personal protective equipment included in the lithium battery field
emergency kit.

• Lithium batteries should not be depleted at the wellsite below the minimum
voltage given in the table above. Full depletion, prior to disposal, should only be
carried out at a properly certified Well Services Workshop facility.

Working With Lithium Batteries at the Wellsite

Reported Lithium Battery Problems

Lithium batteries used in Metrology Electronic Gauges and Z.I. Probes Shut off tool
operations are generally trouble free. However, some problems have been reported.
There have been no instances of designed batteries exploding or causing major
problems at surface, or in transportation, in normal operations.

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Chapter 13, Running & Pulling of BHP/T EMR Gauges & Shut in Tools Page 16 of 20
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

Working With Suspected Lithium Batteries Failure at the Wellsite

When a downhole gauges is suspected of having a battery failure, the following

procedure should be followed, in order to minimise risk to personnel at the wellsite:

1) Hold a brief safety meeting with the rig crew, in order to explain the situation, and
what may happen.

2) Pull the electronic gauges out of to the lubricator (to surface) slowly, while Gauge
Specialist will be in-charged of the operation. If the electronic gauges housing is
breached, if fumes are present, or if it is suspected that a battery may have
ruptured inside the battery housing, then pull the gauges a short distance back
into the lubricator, and clear the work floor.

3) Put on full personal protective equipment (PPE). Only personnel wearing full PPE
should be allowed on the rig floor. Note the wind direction, and only work upwind
or crosswind. Only proceed if it is safe to do so.

4) Carefully remove the electronic gauge from the lubricator, and lay it down on the
work floor.

5) Move the electronic gauges in a safe work area, and place into the gauge
container / box a to retain any fluid.

6) Post an observer, wearing PPE, a safe distance from the electronic gauge to
prevent any casual access to the area where the tool is being worked on.

7) Normal work floor activity should be able to resume at this point.

8) Leaves the electronic gauge container / box complete with the gauges in a safe
place and let it be cool at least for 5 days.

9) The Gauge Specialist is required to contact his Field Operation Supervisor before
attempting to disassemble the gauge.

10) Full PPE must be worn during gauge disassembly.

11) Damaged battery housing should be allowed to vent slowly, and to cool off.

12) If pressure or fluid/gas has been vented at any point in the disassembly, or if the
housing was ruptured downhole, no attempt should be made to remove the
battery or battery pieces from the housing. The entire housing should then be
wrapped in plastic wrap (saran wrap, cling film etc.) and dispose according to the
HSE Standard Module 51 Waste Management.

13) The shorting plug should be slightly loosened from the battery connector. The
back up wrench should then be put on the shorting plug. The shorting plug should
then be unscrewed, while working from the other end of the battery housing. If
resistance is felt, then trapped pressure should be suspected.

14) The pressure vent hole should be angled towards the ground, and away from
personnel.

15) 15. If any fumes are released, stop and wait for the pressure to bleed off slowly.
Continue venting with PPE on until all pressure is relieved.

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BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

16) Break the connection between the electronics module and the battery module.
Place a PVC sheet below the connection to contain any fluid, and be prepared for
any trapped pressure. The vent hole should be oriented as per 14 above. Vent
any pressure as per 15 above.

17) The battery should be held in a well-ventilated area until it can be removed from
the Well Services Workshop to SSU/22. (no threat to local population).

Faulty gauges - lithium batteries

Battery problems are rarely seen in electronic gauges operations, and are usually
associated with premature depletion of the battery pack.

In the Electronic gauges, the battery packs are used sequentially through a sequential
depletion circuit. The Gauge Specialist is required to track the position of each battery
pack in a gauge by using special instrument to break the crystallize depressive to
prevent from premature depletion.

When an electronic gauge fails during a run, care should be taken when laying down
from work bench. Signs to watch for when working with a failed gauge.

Resistance that does not decrease while unscrewing the battery jam nut. This may be
due to trapped pressure.

If any of these signs are encountered, the Gauge Specialist should notify the Operation
Supervisor / Field Supervisor, before proceeding with full personal protective
equipment being used (splash suit, gloves, goggles and respirator).

The area around the suspect electronic gauge should be secured, and an observer
posted. Attention should be paid to the wind direction, to ensure no personnel are
exposed to toxic fumes.

If it is determined that a battery has leaked or exploded, then the complete gauge, with
the battery still in place, should be returned to SSU/22 via Gauge Specialist in Well
Services Workshop.

Handling Lithium Batteries

Lithium batteries should be handled with care at all times:

Avoid direct shock or deformation of the cells, batteries, and battery pack housings

Never use excessive force to try and free a battery pack lodged inside electronic gauge
housing - an internal short circuit may occur

Never short circuit a Lithium battery pack - this may cause a leak or an explosion

Never try to charge a Lithium battery pack - this may cause a leak or an explosion
(note batteries at the wellsite should never be fully depleted, in order to reduce the risk
of accidental charging)

Handle leaking battery packs with extreme care. The liquid and fumes are corrosive
and toxic.

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Chapter 13, Running & Pulling of BHP/T EMR Gauges & Shut in Tools Page 18 of 20
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

Explosion

LTC batteries will explode if operated at temperatures above the melting point of
lithium. This may occur during downhole operations, or by attempting to "charge" the
battery, or by excessive impact on the housing.

Fire

If a fire develops involving lithium batteries, evacuate the area immediately.

Do not attempt to fight a fire involving lithium batteries, due to the explosion hazard,
unless loss of life is imminent.

Advise any professional fire fighters (HSE/1) of the presence and danger of the lithium
batteries.

In the past, instructions have been issued to purchase Class D (Lithex) fire
extinguishers for emergency response to fires involving lithium batteries - this
instruction is wrong. Lithex extinguishers are designed to smother fires involving
lithium metal. In wellsite fires, involving Lithium batteries, the lithium is contained inside
the battery packaging. The risk is of an explosion occurring, due to internal heat build
up.

The danger posed by the volume of lithium metal is minor compared to the danger of
the battery exploding.

Do not fight fires involving Lithium batteries from close range, due to the explosion
hazard.

Provided the battery packs are intact, there is no particular hazard in using regular fire
fighting equipment. There is a preference for using water spray as the best means of
reducing the temperature in the vicinity of the battery packs - this judgement should be
made by qualified professional fire fighters.

If a battery pack explodes, exposing lithium metal, do not use water, C02, or halogen
extinguishers, and avoid fume inhalation. Lithium, if exposed, will react vigorously with
water, producing corrosive hydroxides, sulfuryl chloride, and chlorine. These gases are
toxic, corrosive and explosive in the right concentrations.

Baking soda should over all exposed parts which are not burning.

Leakage

The elctrolyte in the battery is either thionyl or sulfuryl chloride. Both are corrosive and
react violently with many substances, producing corrosive by products. Electrolyte may
leak from a battery due to rupture downhole, if current continues to be drawn from a
depleted battery, or if an attempt is made to charge the battery.

Special care should be taken with cells that are abnormally warm, cracked, swollen or
which have leaked electrolyte. Full PPE should be worn when handling leaking or
ruptured batteries. Any cells that are damaged should be neutralised, wrapped in
plastic, and sealed for transport.

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BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

Should leakage occur, the electrolyte may be neutralised by baking soda (NaHC03).
Prolonged flushing with water will dilute the chemicals, but will not neutralise the
electrolyte. Flushing with water should be avoided if there is any risk of contact with the
lithium metal.

Trapped Pressure

Gases produced by battery leakage or rupture downhole may store large amounts of
energy. Caution should always be exercised when removing batteries from the
housing.

Storage

The number of Lithium batteries at the wellsite should be kept to the minimum required
to carry out the current work schedule.

Lithium batteries at the wellsite should not be fully depleted, since wireline crew will
probably move them to another location/platform for another job. This means that there
is an explosion hazard from any batteries stored at the wellsite.

Batteries should be stored in a well-ventilated area due to the risk of corrosive gases
and fumes.

Batteries should be stored away from sources of heat and water due to the risk of
explosion.

Store batteries in a cool, dry place in a storage room.

Never store damaged battery packs with other packs. Damaged battery packs must be
isolated and disposed of with extreme caution.
• Avoid storing lithium batteries in the following areas:
• the living quarters/logging unit
• where exposed to direct sunlight
• near oxy-acetylene work stations (cutting and welding areas)
• near heaters, dryers, heat exchangers etc.
• near generators or high voltage electrical sources
• near sources of water or other conductive liquids
• near oil drums, paints, thinners or high pressure bottles
• near other hazardous materials, radioactive sources, chemicals or gases
• near heavy equipment
• near the BOP's

The Gauge Specialist is required to notify the Field Supervisor, on arrival at the
wellsite, of the hazards of Lithium batteries, and the location of the wellsite storage
point.

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Chapter 13, Running & Pulling of BHP/T EMR Gauges & Shut in Tools Page 20 of 20
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

CHAPTER 14
SETTING & PULLING OF TWCV, BPV AND HANGER
PLUGS
TABLE OF CONTENTS

WS-314-A CAMERON TWO-WAY CHECK VALVE AND BPV........................................2

WS-314-B FMC HANGER PLUG......................................................................................6
WS-314-C PETROLINE ‘ABC’ BPV ..................................................................................9
WS-314-D RUNNING AND PULLING OF PETROLINE UNISET LOCK .......................16

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Chapter 14, Setting & Pulling of TWCV, BPV & Hanger Plugs Page 1 of 18
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

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WS-314-A CAMERON TWO-WAY CHECK VALVE AND BPV

Design Principle

The two-way "H" check valve is designed to test the tree up to 5,000 psi (34,500 kpa).
After the test is completed the tubing pressure can be bled off or equalized across the
BPV for retrieval with a special removing tool. For higher test pressures the solid test
plug is used.

Operating Principle

The two-way check valve has a steel plunger which sits on an upper seat to seal off
the tubing and a lower seat which seals off pressure from above. The body has
threads on the OD which screws into the "H" BPV thread in the hanger with a seal ring
above the threads. The 1D is threaded to allow the removing screw to thread into it for
depressing the plunger for equalizing and retrieving.

It is impossible to pump through this check valve. If the fluid in the tree needs to be
displaced for testing, it must be done before installing the two-way check valve or a
standard "H" BPV must be installed and then replaced with a two-way check for testing
the tree.

BPV Lubricator

There are two valves connected by a manifold that links the areas below and above
the yoke. The polished rod can be raised or lowered with pressure and the friction
wrench to reach the tubing hanger and pull back up above the master valve. There is
about 12" to 15" (305 to 381 mm) of polished rod exposed in the yoke between the
stuffing boxes.

Installation Procedure

1) Install the valve inserting tool Pt. No. 10428 on the bottom of the rod of the BPV
lubricator.
2) Install the pin and set screw.
3) Close swab valve on X'mas tree.
4) Bleed off any pressure and remove tree connection.
5) Install the BPV lubricator on the X'mas tree with the help of the gin pole,
scaffolding or the cat line of the rig.
6) Close the bleed off valve "B" and open valve "A".
7) Open the swab valve on the X'mas tree.
8) Using the friction wrench, push the rod with the BPV down to the receptacle in
the tubing hanger.
9) Pushing down on the friction wrench turn the polished rod in a counterclockwise
direction, the BPV will thread into the hanger. Keep turning the BPV until it is
made up all the way and rotation stops.
10) Turn the polished rod hard until the BPV is tight, then pull up on the rod to free it
from the BPV.
11) Close valve "A".
12) Carefully open valve "B". By bleeding off the pressure very slowly the rod can be
eased up out of the X'mas tree.
13) When the polished rod stops, rotate the polished rod a little to make sure it is all
the way up.
14) Close the swab valve, open valve "A" and bleed off the pressure in the BPV tool.
15) Remove the BPV lubricator from the X'mas tree.

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Chapter 14, Setting & Pulling of TWCV, BPV & Hanger Plugs Page 2 of 18
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

Back to top
Note: After closing the swab valve, tie the friction wrench so it strains upward or
tighten one of the packing nuts so the rod does not drop and damage the
swab valve.

Pulling Procedure

1) Install removing tool Pt. No. 21851-1 on the bottom of the rod of the BPV
lubricator. Install pin and set screw.
2) Close the swab valve, bleed off any pressure and remove the X'mas tree
connection.
3) Install the BPV lubricator on the X'mas tree with the help of the gin pole,
scaffolding or the cat line of the rig.
4) Close the bleed off valve "B" and open valve "A".
5) Open the swab valve on the X'mas tree.
6) Using the friction wrench, push the rod down through the X'mas tree until the
removing tool contacts the BPV.
7) Push down on the friction wrench and rotate the polished rod clockwise. This
screws the valve removal tool into the BPV.

In case of pressure being trapped below the ball: The nose of the removal tool
contacts the plunger after the removal tool has threaded into the body about 1"
(25 mm). Continued strain on the wrench to screw into the body will off-seat the
plunger and equalize the pressure in X'mas tree.

In case of pressure above the plunger: Any bleed off facility will relieve the
pressure so the two-way check valve can be retrieved.

Continue turning the polished rod until the rod starts up. When it stops moving
up, the BPV is unscrewed out of the tubing hanger.

8) Lift up on the friction wrench to check that the BPV is free:

9) Shut valve "A"
10) Very slowly open valve "B". By bleeding off the pressure the rod can be eased up
out of the X' mas tree.
11) When the polished rod stops, rotate the polished rod a little to make sure it is all
the way up.
12) Close the swab valve, open the valve "A" and bleed off the pressure above the
swab valve.Remove the BPV lubricator from the x-mas tree.

Design Principle

The "H" back pressure valve is designed to seal off pressure from below up to 15,000
psi (103,400 kPa) while removing the BOP stack and installing the X'mas tree. The
"H" back pressure valve is essentially a check valve and will allow fluid to be pumped
through into the tubing if necessary.

Operating Principle

The "H" BPV has a spring loaded check valve that seals off against the lower part of
the body and effects a seal which isolates any well pressures from the tree for repairs
to the X'mas tree valves, removal of the X'mas tree to change out leaking seal rings or
complete exchange of X'mas tree for reworking. The removing tool pushes the check
valve off-seat for pressure equalization when removing the BPV.

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Chapter 14, Setting & Pulling of TWCV, BPV & Hanger Plugs Page 3 of 18
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

Back to top

The main types are the Cameron Type 'H' BPV and
Petroline'ABC'. Back Pressure Valves are installed in
the tubing hanger to hold pressure from below during
the following operations:

• Nipple down drilling BOP (or nipple up BOP).

• Nipple up Xmas tree (or nipple down Xmas tree).
• Test the Xmas tree (2-way check).
• Replace the master valve.

BPV LUBRICATOR

Cameron Type 'H' BPV

These are used extensively in Cameron hangers to safely seal well pressure to 20,000
psi during removal of the blow-out preventer and installation of the Xmas tree. Fluid
may be pumped through the BPV. If the tree above the BPV is to be pressure tested,
the type 'H'2-way check valve may be landed in the tubing hanger for pressures to
20,OOO.psi.

If during the life of the well it becomes necessary to remove the Xmas tree or repair the
lower master valve, the back pressure valve can be reinstalled in the hanger without
killing the well. The `lubricator' consists of a rod which works through a yoke provided
with two `stuffing boxes'. By closing the vent valve and opening the equalising valve,
well pressure acts on both the top and bottom of the rod. The rod can then be moved
up or down by means of a friction wrench. Experienced operators can utilise the well
pressure in moving the rod by manipulation of the valves.

The running tool is inserted into the left hand thread at the top of the valve, and then
attached to the polished rod. When the valve has been lowered into the hanger, the rod
is lowered so that the cross pin in the running tool engages in the slot on the top of the
valve. Right hand (clockwise) rotation is applied to insert the valve. Once the valve is
fully seated, moving the rod up to lift the pin from the slot and continuing a right hand
rotation backs out the running tool.

The pulling tool is attached to the rod and lowered to the valve. Left hand
(anticlockwise) rotation makes up the pulling tool and then removes the valve.

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BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

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Chapter 14, Setting & Pulling of TWCV, BPV & Hanger Plugs Page 5 of 18
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

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WS-314-B FMC HANGER PLUG

Design Principle

The FMC hanger plug is a device set in the FMC tubing hanger to plug off the tubing.

With the tubing plugged at this point such operations as removing the blowout
preventer or installing it, removing or installing the Xmas tree and repairs to any part of
the tree from the master valve down can be performed safely.

Operating Principle

The "IS" type back pressure valve is a no-go shoulder locating assembly that seals in a
polished bore ID immediately below the no-go shoulder in the FMC hanger. The "IS"
plug has large ports right below-the no-go shoulder through which fluid can be pumped.
Note: No abrasive fluid is to be used for flushing.

The "IS" plug features a large diameter positive seal check dart that is spring loaded.
This check dart has a small spring loaded bypass check dart that is physically held
off-seat by the running or pulling tools during setting and retrieval operations.

The BPV will allow fluid to be pumped through it for the purpose of displacing mud out
of the tubing. A certain amount of caution must be used here. The fluid used for
flushing must not contain abrasive material, usually clean water or diesel is used. The
pump rate must not be high enough to erode the BPV.

Running and Pulling Tools

The running and pulling tools are shown in the attached Drawings The running tool has
no moving parts; it has centralizer rings close to the ends which act as guides to
prevent the BPV from being set or hung in the Xmas tree.

The pulling tool, called an IS/ISA retrieval tool, consists of five parts:
1) Mandrel
2) Collet dogs
3) Dog releasing cap
4) Shear pin
5) Roll pin.

• The names assigned to the retrieving tool parts are the author's, not FMC.

The function of the retrieving tool is simple. The retrieving lip of the collet dogs are
actually shaped like a standard outside fishing but upside down and split into a four
finger collet. A shear pin (11) anchors the mandrel (1) and the collet dogs (2) together.
In the retrieving process, if the BPV is stuck or hard to pull, upward jarring can shear
the pin (4). This allows the mandrel (1) to move up taking the dog releasing cap (3) with
it. As the dog releasing cap (3) moves up the tapered ends of the collet dogs (3) move
in. This inward movement of the fingers causes the retrieving lips to move out from
under the fishing neck inside the upper end of the BPV mandrel (11). The retrieving
tool can be pulled from the Xmas tree bore.

If the BPV is retrieved properly with the retrieving tool, the tool can be released by
wrapping a worm' drive hose clamp around the heavy shoulder in the middle of the
forgers, and closing the hose clamp just enough to release the fishing neck in the
mandrel (11).

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Note: When attaching the retrieving tool to the lubricator rod connection, wireline
tools or sucker rods do not make up by wrench as the shear pin (4) can easily
be sheared. Make up tool by hand or if it must be wrenched up insert a ball
bearing or small nut on the pin before making it up. This will cause the top of
the pin to bottom up to the inside of the box.

Installation Procedure

1) Clamp the running tool in the vise.

2) Tap the shear pin in about a 1/4" (6 mm).
3) Install the running tool as per the Drawing No. II Align one of the holes in the
mandrel (11) over the shear pin hole in the stinger (1).
4) Using a punch from the opposite side of the shear pin hole, line up the holes in
the running tool and the stinger and drive the shear pin in.
5) Attach the running tool to the wireline work string. After tightening the running
tool, lower the tools down alongside the Xmas tree until the BPV dogs are even
with the hanger with the jars closed. Mark the tool string or flag the braided line.
6) Lower the BPV through the Xmas tree or BOP stack. When the valve starts to
enter the hanger it will probably stop, body weight applied to the tools or slight
bumping down with the mechanical jars will push the BPV down to the no-go
should. Listening to the sound being made close to the base of the Xmas tree will
tell when the no-go shoulders meet.
7) Three to five good full stroke downward blows will shear the shear pin (9), moving
the mandrel (11) down and forcing the dogs (8) out into a recess in the hanger.
An upward strain on the wireline will determine if the BPV is locked in the hanger
or not.
8) If the BPV is locked a couple of upward blows will shear the pin holding the
running tool and the stinger together.
9) Remove the tools and lubricator and proceed with the next operation.

Pulling Procedure

After rigging up on the Xmas tree or the BOP stack attaching the retrieving tool* and
zeroing the counter, install the lubricator on the wireline BOP and drop the tools into
the bore and proceed as follows:

1) When the retrieving tool reaches the BPV allow the jars to close and rest the
weight of the work string on the retrieving tool.
2) Pick up the weigt of the work string and jar up by hand three or four blows.
3) Pull the BPV and the tools into the lubricator.
The retrieval is complete.

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Stinger (Assem) (1)

Mandrel (11)
Cap (10)
Shear Pin (3/16” x ½ LG roll pin) (9)

5/32” x ¼ LG roll pin (15)

Spring Clip 7 H.S. (12)

5/32” x ½ LG roll pin (f/Dogs) (14)

Dogs (8)
‘O’- Rings (7)
Body (5)
‘O’ – Ring (13)
Valve (3)
Spring F/valve, 7 H.S. (4)

5/32” x 5/16 LG roll pin (16)

Spring retainer nut (6)

Spring F/Stringer 7 H.S.

FMC HANGER PLUG

Max. O.D. 2.605 Max. O.D. 66.2mm

LENGTH 7.125 LENGTH 209.5mm

Mandrel (1)
Shear Pin (4)
Collet Dog (2)

Dog Realeasing Cap (3)

Roll Pin (5)

RUNNING TOOL PULLING TOOL

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WS-314-C PETROLINE ‘ABC’ BPV

The 'ABC' BPV consists of three main parts:

Uniset QXT Lock Mandrel - Run and pulled as per the uniset lock procedure (Ref:
WS-314-D) of this manual. The lock has the following modifications to make it suitable
for use in the tubing hanger:

• Uses low friction ST seals in place of O-rings or V-packings to seal inside the
hanger bore.

• The length above the no-go has been minimised to keep the top of the fishing
neck below, or flush with the hanger. This makes its use safer while removing the
BOP / tree.

'AB' Equalising Device (AB = Anti Blow-out) - Required to equalise the pressure prior
to pulling the BPV. The 'AB' assembly includes a pressure sensing piston which
prevents the entry of the prong, and latching of the pulling tool (GS or DU) until the
pressure is equalised.

As shown in the 2 small sectional diagrams in the adjacent drawings, the trip sleeve
moves upwards and the 3 sensor keys protrude into the internal bore. This permits the
equalising prong to move the equalising melon from the ports to allow the pressure
differential to equalise, but prevents the pulling tool dogs from latching the fishing neck
of the lock mandrel.

Once the pressure has equalised, the sensor keys retract and allow the pulling tool to
latch the lock.

This feature prevents the complete assembly from being blown up the hole by
premature unlocking of the lock mandrel.

'C' Back Pressure Valve - This device holds pressure from below only. It has a
primary metal-tometal seal with a backup elastomeric seal. If it is necessary to pump
through the type 'C' BPV, an internal spring moves the protector sleeve to isolate and
protect the elastomeric seal.

Pressure Testing From Above

'ABC' Test Dart - If it is necessary to pressure test above the BPV, such as when
testing the BOP / tree seals, the test dart can be installed with an SB running / pulling
tool. The dart seals across the polished bore of the adapter sub, as shown by the
shaded line in the adjacent diagram. The length of the test dart is such that the fishing
neck protrudes from the top of the lock mandrel.

General

The 'ABC' BPV can be set on slickline or polished rods.

Run in one trip - pulled in one trip.

Running Tool Petroline QXD.

Pulling Tool Petroline DU or Otis type GS.

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Pressure rating - Available in 5,000 and 10,000 psi as standard (15,000 psi on
request).

Preparing Tubing Hanger Plug* Prior To Running

In order to install the Tubing Hanger Plug into the relevant profile, the following
instructions should be observed.

1) The assembly to be run should have been assembled as per previous

instructions.

2) Install correct Pulling Probe onto correct Pinning Handle.

3) Insert Pinning Tool into Lock Mandrel against Inner Mandrel and push down to
compress Spring until Pinning Tool bottoms out on top of Fishing Neck.

4) Insert a 3/16" punch into punch hole in the Lock Body.

5) Once the punch is securely inserted into the punch hole, the Pinning Tool can
now be removed.

6) Check the Running Tool has a Shear Pin installed (either Brass or Steel) in the
Tell Tale Collet. Assemble the Running Prong to the Running Tool & again check
that a Shear Pin has beer installed into the Collet on the Running Prong. Insert
the Running Tool into the Tubing Hanger as follows :

a) If the ABD is for a fluid application, insert a punch through one of the flow
ports into the groove on the equalising melon. Push the running tool into
the assembly until the running prong collet goes through the melon and the
prong butts on the melon. Remove the punch from the melon and push the
running tool into a position where the shear pin holes in the running tool line
up with the appropriate holes in the fishing neck.
b) If the ABD is for a gas application with flow ports that are too small to insert
a punch through then it is necessary to remove the plug screw from the
hole located between the flow ports anc insert the punch in this hole. The
rest is the same as 6a. Ensure the plug screw is replaced after pinning up
running tool.

7) Insert 4 Shear Pins into the lower holes on the Lock Mandrel (setting pins) and 2
Shear Piny into the upper holes (releasing pins) centre punch all Pins to ensure
retention of Pins wher sheared.

8) Remove punch from punch hole on the Lock Body.

9) Assembly is now ready to run.

* Tubing Hanger Plug consists of QXT/TB Uniset Lock, Anti-Blowout Device &
Junkcatcher or Back Pressure Valve.

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Running Procedure For Tubing Hanger Plug

1) Make-up the Tubing Hanger Plug Assembly complete with Running Tool to the
toolstfng. (Applying a film of grease to the external Seals on the Lock Body will
aid insertion into the Nipple seal bore).

2) Zero Plug on rig floor and make-up lubricator.

3) Slowly run in hole with Assembly taking care through well head area.

4) Continue to run in hole until Seals enter Nipple seal bore.

5) Light downward jarring will overcome any seal resistance until Plug body locates
No-Go shoulder.

6) Continued downward jarring will shear the lower set of Shear Pins allowing the
Lock to be activated.

7) A light upward pull on the wireline unit (equal to pull weight) will lift the Lock off
the No-Go, allowing the Locking Keys to expand into the Nipple profile.

8) An overpull of approximately 4001bs over pulling weight will confirm Lock is set.

9) Upward jarring will now shear the upper set of Shear Pins (brass) and release the
Running Tool from the Lock Mandrel. The Running Prong will pull the Equalising
Melon on seat (to the sealed position) while the R/Tool is being retrieved however
a 3/16" brass Shear Pin will have to be sheared prior to the R/Tool and Prong
assembly moving free from Lock.

10) Upon retrieval of the Running Tool at surface, inspection should now be made of
the Tell Tale Collet on the Running Tool, if the Shear Pin is still intact, this
indicates a correct setting. If the pin has sheared this indicates a malfunction in
the running procedure, and the Tubing Hanger Plug must be retrieved.

* Note:- Collet on lower end or running prong will be sheared due to ensuring that
the equalising assembly is on seat.

Note: If possible it is advisable to exercise all production bore Christmas tree

valves prior to running the assembly, as this will expel any excess tree
grease, and ultimately ease recovery of the BPV Assembly.

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Pulling Procedure For (Pressure Unbalances) Tubing Hanger Plug

(Differential pressure present below the Tubing Hanger Device).

1) Assemble the appropriate GS Pulling Tool, Pulling Probe and Pulling Prong to the
toolstring.

2) Make up lubricator.

3) Run in hole with toolstring until the Equalising Prong enters the Tubing Hanger
Plug (note: Tubing head pressure).

4) Continued running of the wire will allow the Equalising Prong to push the
Equalising Melon below the equalising ports (observe if tubing head pressure
changes).
5) When all toolstring weight is set down, pull back on the wire by hand to determine
if the GS has latched the Fishing Neck, if unable to latch this will confirm ABD
has been activated.

6) Pressure build up in excess of 20 psi below the Plug assembly will activate the
Anti-blowout Device, which forces the 3 Sensing Keys into the bore of the Plug
Assembly.

7) Leave toolstring in this position allowing pressure to equalise. Once pressure has
equalised the Return Spring in the Anti-Blowout Device will force the Pressure
Sensing Piston downwards, thus removing support from behind the Pressure
Sensing Keys allowing the Keys to retract.

Note:- It may be necessary to lift the Toolstring weight off the Sensor Keys to remove
binding forces and allow the Piston to travel down.

8) The GS Pulling Tool will now drop and latch into the Fishing Neck of the Plug.

9) The Tubing Hanger Plug may now be recovered from the well.

NB: In the event that the GS Pulling Tool will still not latch it is possible that
the equalising ports may be blocked and pressure still trapped below the
device. In the event that you are unable to equalise mechanically,
pressure up from above to balance well pressure before attempting to
retrieve. If you are still unable to latch contact Petroline.

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Pulling Procedure For (Pressure Balanced) Tubing Hanger Plug

As this Tubing Hanger Plug is fitted with an Anti-Blowout Device which comes into
operation if pressure build up below the Tubing Hanger Plug exceeds 20 psi, it must be
noted that only in very extreme cases should the GS be run in without a Prong, and
then only when the pressures above and below the Plug are 100% known to be equal.
This is an essential safety requirement.

1) Assemble the appropriate GS Pulling Tool, Pulling Probe and Equalising Prong to
the toolstring.

2) Make-up lubricator.

3) Run in hole with toolstring until the Equalising Prong enters the Tubing Hanger
Device.

4) Weight should be set down to allow the Equalising Prong to push the Equalising
Melon below the Equalising ports, in the event that no pressure is evident below
the Plug, the Sensing Keys in the Anti-Blowout Device allow full travel of the
Equalising Prong, thus allowing the Pulling Probe to push down the Inner
Mandrel and the GS to latch the Fishing Neck.

5) Pull back on wire to determine if GS latched onto Fishing Neck.

6) The Tubing Hanger Plug may now be recovered from the well.

Note: As the GS actually engages the Fishing Neck, the Lock Out Keys will be
retrieved from the Nipple Profile, it is now only necessary to overcome the seal
friction, to recover the Plug Assembly from the Nipple.

Important Points To Be Noted Regarding Correct Use of Tubing Hanger

Plug

1) Never pull the Plug without the Equalising Prong. Unless it has firmly been
established equalisation has taken place.

2) If the 'GS' will not latch the Fishing Neck do not attempt to jar down to latch. (The
Stem weight alone should be sufficient for the GS to latch and will certainly be
enough to move the Equalising Melon. However, a few light taps may be
necessary to displace grease and compress the GS Spring.

3) The phosphor bronze ball in the Test Dart should be replaced after each series of
tests.

4) The Seals on the Melon should be replaced after each series of tests.

5) When retrieving the device a minimum of 8 to 10 feet of 1 7/8" Stem should be

used. This will allow the internal Springs to be overcome without the need for
jarring.

6) Always use a GR (shear up type Tool) in conjunction with the Bleed Down Prong.

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To Pressure Test Tubing Hanger Plug From Above

In order to pressure test the Tubing Hanger Plug from above it is necessary to install a
Test Dart. This locates and seals in the crossover between the Lock section and the
Anti-Blowout section.

1) Run and set Tubing Hanger Plug as per previous instructions.

2) Attach correct size Running Tool (JDC, SB or similar style tool) to the Rope
Socket Fish Neck of the Test Dart.
Make-up appropriate toolstring.
3) Run in hole slowly and locate Test Dart into Plug Body.
4) Any resistance (due to Chevron seal friction) can be overcome by light downward
hand jarring.
5) Continued light downward jarring will shear the pin in the Running Tool and the
toolstring can be recovered.
6) Pressure test to desired pressure from above Plug/Dart.
7) Retrieval of the Test Dart is opposite from installation. Always replace Ball in Test
Dart after every use.

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WS-314-D RUNNING AND PULLING OF PETROLINE UNISET LOCK

Running Procedure

1) Lower the lock mandrel into the wellbore taking care when passing through the
wellhead, other nipple profiles, or restrictions in the tubing string.

2) When the appropriate landing nipple is reached, then light downward jarring is
required to position the V-packings into the seal bore and locate the no-go
shoulder of the lock mandrel onto the no-go in the nipple.

3) Further downward jarring is required to shear the lower set of setting pins on the
running tool, thus allowing the inner mandrel to move partially upwards.

Note: Always ensure enough downward jar action is applied to shear the setting
pins.

4) In order to lift the lock off the no-go, jar upwards lightly with the spang jar 10 to 15
times, then take a check pull and hold it for approximately 5 minutes.

If the lock is not set correctly, you should see a drop off in weight.

If this is the case, repeat the setting procedure.

If this is not the case and the lock is secure, upward jarring will shear the upper pins
releasing the running tool.

On retrieving the running tool to the surface, always check the shear pin holding the
telltale collet in place. If the pin is sheared, this indicates the lock is not set correctly
and must be retrieved.

Note: If height allows it, incorporate an upstroke jar in the toolstring for setting and
pulling lock mandrels.

Pulling Procedure

1) Make up the correct pulling probe to the appropriate GS or DU pulling tool.

2) Lower the toolstring into the wellbore and locate the uniset lock mandrel, then
take an upward pull on the wireline to confirm latching.

3) Upward jarring will retrieve the lock assembly from the nipple profile.

Note: Never attempt to retrieve the lock mandrel if there is a pressure differential
below the assembly.

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The QXD Running Tool is designed to run the uniset locks. The telltale collet provides
a positive indication that the lock is correctly set. If it is sheared, the lock is not correctly
set and must be pulled and rerun.

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Preparation

1) Install the "pulling probe" on the "pinning tool handle".

2) Insert into the "lock" and push down to compress the spring.
3) Insert a punch in the "pinning hole" in the main body and withdraw the probe.
4) Insert the QXD running tool until the shear pin holes on the "fishing neck" of the
lock are lined up with the corresponding holes in the QXD "shear off sub" and
"inner mandrel".
5) Insert 2 brass pins into the lower (setting) pins and centre punch them to prevent
the broken pieces falling out.
6) Insert 2 brass pins into the upper (retaining) holes and centre punch them.
7) Remove the punch.

The running tool and lock assembly is now ready to run.

QXD Running Tool

QLS Connection
Option available

Top Sub (1)

Shear off sub (3)

Grub screw (6)

Inner mandrel (2)

Tell-tale collect (4)

Grub screw (6)

Bottom sub (5)

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CHAPTER 15
NON ROUTINE WIRELINE OPERATIONS
TABLE OF CONTENTS

WS-315-A EQUALIING OR PRESSURISING OR TUBING OR ANNULUS ....................2

WS-315-B WAX CUTTING PROCEDURE .......................................................................5
WS-315-C TUBING SCALE REMOVAL BY BROACHING ..............................................6
WS-315-D RUNNING AND PULLING OF “DB” AND ARMCO STANDARD VALVE ......7
WS-315-E SAND BAILING OPERATIONS.......................................................................8
WS-315-F RUNNING AND PULLING OF PERTROLINE PUMPOPEN PLUG .............13
WS-315-G RUNNING AND PULLING OF “PX” STRADDLE PLUG ..............................15
WS-315-H RUNING AND PULLING OF PETROLINE BRIDGE PLUG .........................17
WS-315-I PACK-OFF ANCHORS ...................................................................................21
WS-315-J OTIS TYPE ‘A’ PERFORATOR .....................................................................24
WS-315-K RUNNING AND PULLING OF TYPE “F” COLLAR STOP............................27
WS-315-L RUNNING AND PULLING OF TYPE “D” COLLAR STOP............................28
WS-315-M TYPE “F” TUBING STOP..............................................................................29
WS-315-N TYPE “G” TUBING STOP .............................................................................30
WS-315-O TYPE “T” PERFORATOR STOP ..................................................................31
WS-315-P TYPE “F” COLLET STOP ..............................................................................32
WS-315-Q RUNNING AND PULLING OF PES-HE-3 RETRIEVABLE BRIDGE PLUG 33

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WS-315-A EQUALIING OR PRESSURISING OR TUBING OR ANNULUS

Equalising or Pressurising of Tubing or Annulus may be rquired in order to open

SSD,s, pulling of gaslift valves, equalise across SC-SSSV,s or assist in equalising
across tubing plugs.

Preparation and Inspection Procedure

1) Ensure the wireline lubricator is fitted with a unicell block and bleed valve.
2) Ensure a connection is fitted to unicell block and bleed valve.
3) Ensure seal on the connection is in good working condition.
4) Ensure the hydraulic hose is fitted with connection on both ends.
5) Wireline operator to install a temporary connection to the pressure source point.

NOTE 1: Do not join the hydraulic hose to extend its length.

NOTE 2: At any one point the hydraulic hose should be connected to two fixed
points one being the lubricator and the other the pressure source
point.

6) The wireline operator to inspect the hose prior to carrying out the operation. To
satisfy himself that the hose is suitable for the intended operation.

NOTE 1: Do not use non-colour coded hoses for equalising/pressurising

operation.
NOTE 2: Do not remove or change any fitting.

Operating Procedure

1) The wireline operator to check the integrity of the hook up prior to

commencement of the operation.
2) Install a correct range of pressure gauge on the unicell block and bleed valve.
3) Open the swab and the master valves, and close off the wing and flowline valves.
4) Ensure the surface control subsurface safety valve is open, if installed.
5) Prepare lubricator to receive pressure from source.
6) The wireline operator should ensure that all- personnel not connected with the
operation stay well clear from the hose and the work area.
7) Open the pressure source valve carefully and slowly. At the same time observing
for any abnormalities on the hose and in general the rig up.
8) On completion of the operation shut off the pressure source valve. Isolate the
hose and release the pressure. Bleed down the lubricator and hose via block
and bleed valve located on the lubricator prior to disconnecting.
9) Rig down work gear and remove all temporary fittings.

NOTE 1: The hydraulic hose will be standard for all wireline associated
operation. However, only colour coded hoses are to be used for
pressurising and equalising operation.
NOTE 2: The nut which connects the male and female part has to be
connected hand tight.
NOTE 3: Dust caps must be fitted upon completion to prevent damage on
fittings.

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Maintenance Procedure

1) All hydraulic hoses used for equalising and pressurising operation must be colour
coded in the same line as the wire rope sling established system.
2) The wireline field supervisor must dispose off all hoses every 6 months and
obtain new replacement hoses with appropriate colour coding from the workshop
supervisor.
3) The workshop supervisor should ensure all hoses are tested to maximum test
pressure and appropriately colour coded before any new issue.
4) Do not use non-colour coded hoses for equalising or pressurising operation.
5) Do not remove or change any fittings on site.

Do not use any sub-standard hoses.

Type 2000ST Rogan and Shanley Hose Construction

Outer cover: Extruded nylon II, or for size 6 to 13 can specify

polyurethane

Hose Core: Nylon II

Pressure Supports: Two spiral wound plus one braided layers of plated
high strength steel wire

PIONEER 3000-2 HIGH PRESSURE COUPLINGS

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ROGAN & SHANLEY HOSE RIG UP FOR EQUALIZATION

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WS-315-B WAX CUTTING PROCEDURE

Wax or paraffin cutting situations differ from well to well. The wax build-up can be
hard or soft and the depth of the build-up varies, depending on the well's flowing
temperature, percentage of water cut and rate of flow.

BSP uses a scratcher which is made from a piece of sucker rod. Holes are drilled at
different angles along the length of the rod and set screw holes are drilled and tapped
to anchor the length of stranded line. The ends of the strands are bent out to form
whiskers or small brushes.

The scratcher is equipped with a rope socket latched into a RB pulling tool which
is made up to the tool string. With the well flowing on a small choke,the scratcher is
run to hold-up depth plus 1.5 m. After making 1.5 m of hole the tools are pulled back
into the lubricator. The swab valve is closed and the lubricator pressure is bled off. The
lubricator is then disconnected, and the tools are lowered to clean the scratcher. The
process is repeated until the well has been cleaned of all paraffin buildup.

The last trip to clean the tubing is made with a standard gauge cutter to 600 m.

The only other way BSP uses to remove paraffin is when a well is plugged to a point
that it cannot flow. The hot oil method is used. This is done by pumping hot crude oil
down the casing and melting the paraffin build-up in the tubing or by bull heading down
the tubing if there is no circulating feature down the tubing.

When a Gauge Cutter is used to cut paraffin, it also needs to be run with a rope socket
latched into a RB pulling tool.

Gauge Cutter

Wire Scratcher

A Wire Scratcher provides a means to clean the

ID of the tubing, nipple profiles and SSD’s etc.

It is run on a standard tollstring and run up and

down to clean the affected area.
Locking Allen
It is most commonly made from an old piece of Screw
stem or sucker rod drilled and tapped, as shown,
Braided Line
to accept pieces of braided line cut in lengths to
suit the well diameter.

A variation of this tool, thread with slickline in a long

continuous loop, can be used to locate broken wire.

Refer to section 13 on “Fishing” for surther details

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WS-315-C TUBING SCALE REMOVAL BY BROACHING

The Tubing Broach is made up of 3 major parts:

1) Top Sub
2) Mandrel
3) Spool.

The spool is tapered and used to cut burrs in the tubing ID caused by perforation, rust,
bent tubing etc. A small OD spool is run first followed by the next larger size, and finally
one corresponding to the original ID of the tubing.

The Tubing Broach must be run with a rope socket installed and latched into a
RB pulling tool.
It is good practice to include hydraulic jars in the toolstring in case the broach is tight to
remove.
In BSP broaches are mainly used to remove scale deposits from the tubing wall.
Other types of broaches used in BSP are:
The Diamond broach and Pineapple broach.
The method of operating is identical to the broach above. Other versions are also
available as shown below:

One Way

Two Way

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WS-315-D RUNNING AND PULLING OF “DB” AND ARMCO STANDARD
VALVE

The two valves in this section are adapted to "X" locks with "X" equalizing subs and are
run and pulled on wireline under pressure the conventional way.

The ball and seat part of the standing valve are not disturbed or tampered with.

Design Principle

The standing valve is simply a check valve in a vertical position. The purposes of its
function are:

1) To keep the hydrostatic pressure in the tubing off the formation.

2) In gas lift installations to prevent the injected gas pressure from pushing well fluids
into the formation.

Operating Principle

In the BSP group the standing valve is always run attached to a locking mandrel. The
Armco standing valve comes with a plug drain type equalizing device screwed into the
housing a couple inches above the cage insert.

The "DB" standing valve consists only of a cage housing, ball, seat and a lower
housing.

Both standing valves are adapted to an "X" equalizing sub which is screwed on to an
"X0" or "XN" locking mandrel.

They are run on wireline exactly like an "XO" or

"XN"lock mandrel is run and they are retrieved by
wireline as an "XO" or "XN" lock would be retrieved.
(Ref.WS-309-L)

The equalizing sub is a safety precaution to ensure that

a hydrostatic fluid head will not prevent retrieval of the
standing valve. The Armco also has the drain plug
which can be broken off if necessary to equalize across
it.

ARMCO STANDING VALVE

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WS-315-E SAND BAILING OPERATIONS

Occasionally wireline service involves sand bailing prior to the actual pulling or setting
of subsurface flow controls. Techniques vary, but the operation of sand pumps are very
much the same. After a few trips the operator should know what he will have to do to
get a bailer full each trip; that is, how long he must stroke the pump, whether it is
necessary to drive down on the bailer (this seldom helps), or how fast he must work the
plunger.

Short bridges in the tubing will require some more precautions due to the possibility of
pressure trapped under a bridge. The most important of these precautions is that the
operator should never stroke the pump and stop at the top of the stroke. He should
keep the tools moving on up the tubing until he is sure there is no pressure, then set
the pump back down to make another stroke.

When the bailer falls through a bridge, the tools should be pulled back up several feet
above the point where the bridge was first encountered to make sure the bridge of
sand is completely clear before going deeper.

Sand is prone to become packed tight on the top when pressure has been applied to
the tubing above, which is very often done to keep the pressure equalised above and
below the sand bridge. This makes it difficult to pick-up with the sand pump. In this
case, it might be necessary to run a tool to loosen it. This could be a pointed tool with
barbs welded on it, to drive down into the hard sand and pull back out. A round tool
with teeth cut around the bottom edge will sometimes loosen it enough for the pump to
pick it up (e.g. serrated gauge cutter).

Sand bailers are of 2 basic designs:

1) Pump Bailers.
2) Hydrostatic Bailers.

Pump Bailer

The Pump Bailer is used to remove the bulk of sand above the wireline tools /
equipment.

Description

It is a hollow tube with a check valve (ball or flapper) at its lower end, which is usually
muleshoed (cut at 45°). It contains a piston and valve attached to a rod which passes
through a loose hold (for fluid bypass) at the upper end of the tube. This rod is attached
to the toolstring.

Operation

As the bottom of the bailer sits on the sand, the weight of the toolstring pushes the
piston to the bottom of the tube. As this piston is picked up, it sucks sand and debris
into the bottom of the bailer. This slow `stroking process' continues until the bailer is
full.

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Note: As the size of the bailer is smaller than the tubing ID, a hole will be bailed
through the sand, leaving a considerable amount of sand sticking to the tubing
wall. It is good practice to run a drift or gauge cutter of the appropriate size to
scrape this off the wall after every few meters bailed. Once this sand wall
caves in, it could foul up the jars easily.

Hydrostatic Bailer

A Hydrostatic Bailer consists of a chamber sealed at atmospheric pressure. When the

bailer reaches the top of the sand and is jarred down, a shear disk is ruptured and the
bottom hole pressure surging into the chamber sucks up the sand. A ball check in the
bottom serves to trap the sand in the chamber.

These bailers are used to clean off sand or foreign materials from around a fishing
neck very successfully, and are not recommended for normal bailing operations. In soft
sand, this bailer will bury itself each time it goes off. It usually requires a hard object
against which to shear the disc.

ALWAYS use a pump bailer to remove the bulk of sand etc. until the pump bailer is
resting on the plug or whatever is to be removed. A hydrostatic bailer can then be used
to clean around the fishing neck.

Hydrostatic bailers are not recommended for normal bailing operations because:
1) Too slow.
2) A high possibility of sticking in the sand due to the suction action when the
sealed chamber is opened.

Caution: Sand pumps and hydrostatic bailers can be dangerous after pulling them to
the surface and when unloading the sand, due to pressure trapped inside
the chamber. Caution should be taken when removing the check valve on
the bottom to make sure there is no pressure inside. This can be
determined usually by how hard the bottom is to unscrew. You should
never completely remove the bottom while the bailer is pressured up. Do
not hammer on a bailer to remove sand. These bailers are subject to
bottom hole pressure. It is a good idea to visually inspect these bailers for
wear and wall reduction.

Hydrostatic bailers have pressure relief valves, and some have an automatic pressure
relief valve. These become plugged easily and can be dangerous to handle, so
observe the above caution when unscrewing the bottom.

Before running check the following points:

1) Upper manual pressure relief closed (fully IN).

2) Automatic pressure relief - Check the O-ring and that the disc is in position.
3) Insert the shear disc - to ensure 100% sealing. It is helpful to wrap teflon (PTFE)
tape around the edge or grease the disc.
4) Check the skirt is tight.

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Sequence of Operation

1) Hydrostatic is run to a solid obstruction. The tubing pressure outside is much

greater than the atmospheric pressure inside. Downward jar action shears the
disc.
2) The disc is forced inside the cylinder as the sand, scale and fluid rushes in to fill
the cylinder. The pressure inside and outside is now equalised.
3) As the bailer is pulled out of the well, the tubing pressure decreases near the
surface. Pressure trapped inside by the check valve is now greater than the
tubing pressure. The automatic relief valve should release excess pressure.

Caution: This relief valve can be easily blocked by sand.

On the surface, the manual relief valve should be loosened (do not remove
completely) and the ball check pushed off the lower seat by a brass rod to ensure no
pressure is trapped inside. Remove the lower housing.

Note: Clean threads and grease before reassembling.

Below some examples of pump-bailer bottoms used by BSP.

1) Regular ball and seat arangement.

2) Flapper type is more effective due to less internal restrictions.
3) Mule shoe type,breaks up hard sand easier.
4) Teethed version for very hard packed sand.

1 2 3 4

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WS-315-F RUNNING AND PULLING OF PERTROLINE PUMPOPEN PLUG

The Pumpopen Plug was developed to enable wells to be brought into production
safely, faster and more economically than wells plugged by conventional methods.

Revenue optimised: By utilising the Pump open Plug downtime is substantially

reduced for one well and the benefits are greatly enhanced when a number of wells
have to be plugged.

Simple to operate: A sustained pre-determined pressure above the Pumpopen Plug

will open it and allow the well to be brought into production.

Fits any Downhole Lock Arrangement: The Pumpopen Plug can be supplied to fit
any Otis, Cameo or Baker Lock Mandrel. A wireline manipulated equalising assembly
can also be supplied to run above the Plug if required.

Plug cannot open accidentally: It requires the application of a sustained load or

pressure before the Plug will open and jarring during Plug installation will have no
effect. Shear pins can be providbd to shear at the pre-determined differential pressure.

Virtually eliminates bailing: The Plug can be opened even if a substantial column of
sand or paraffin wax has settled on it. Long and expensivc bailing operations are not
likely to be required. Any sediment is quickly washed away when the well is flowed.

Stuck plug assemblies don't stop production: If a plug assembly is stuck and a
Pump open Plug has been fitted, it can be pumped open enabling production to
continue and there is no immediate requirement for a workovcr.

Fishing reduced: Pressures are always equalised when retrieving the Plug after it has
been pumped open and there is no equalising prong that can cause equipment to be
"blown up the hole."

Operation of the Pumpopen Plug:

The Pumpopen Plug has only 4 moving parts.

Apart from the body, the Plug consists of:

1) Piston with latches machined into its skirt.

2) Floating cylinder.
3) Spring.
4) Shearpin (which is not always required).

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The spring chamber is fully charged with hydraulic fluid.

Closed: In the closed position, the piston and floating cylinder stop any flow of
oil.

Intermediate: To open the Plug, pressure is 'increased above it. As the pressure
increases, the piston and floating cylinder move against the spring.
Movement is dampened by the flow of hydraulic fluid from the spring
chamber through the annulus between the piston and the bore of the
Plug.

As pumping continues, the shearpin reaches the shearing face

located at the bottom of the flow ports. The pin shears under the load
of a pre-determined differential pressure. The piston continues
downward until it latches in the lower position. The Plug is now in the
Intermediate position.

Pump-Through: Further pumping will move the piston down to the PumpThrough
position thereby allowing fluid to pass down through the Plug.

Open: A reduction in pressure or allowing the well to flow will cause the
floating cylinder to move upwards to the Open position.

For Running and Pulling Procedure refer to WS-309-L (XX and XN plugs).

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WS-315-G RUNNING AND PULLING OF “PX” STRADDLE PLUG

The PX-Straddle plug is used to plug off the well in the X nipple profile of a TR-SSV
which has been permanently locked open and accommodates a Wireline retrievable
insert valve. It has 2 packing stacks, which seal off in the upper and lower seal bores in
the TR-SSV.

It allows for testing the integrity of both seal bores and the control line connections in
case of malfunctioning of the SC-SSV i.e: continues stroking of HP pump in control unit
indicates loss of control line pressure and fluid. This could be caused by previous
extensive wireline operations through the TR-SSV, resulting in grooves cut in the seal
bores.

Setting procedure for the PX- Straddle plug is similar to setting the X-Straddle Tool
(Ref. WS-309-T) with the difference that the running prong is not used as the
equalising sub has been omitted. An additional run has to be made to set the prong (as
per standard procedure on a SB pulling tool).

For testing the lower seal bore, the upper packing stack needs to be removed prior
to running and replaced by a dummy sleeve. When Straddle plug and prong are set,
the plug may be inflow tested to confirm the integrity of the lower seal bore.

For testing the upper seal bore, the lower packing stack needs to be removed and
replaced by a dummy sleeve. When Straddle plug and prong are set, the plug may now
be inflow tested to confirm integrity of the upper seal bore.

For testing the control line and its connections, run the Straddle plug with both V-
packing stacks and prong. Once set, apply control line pressure from an external
source, preferably an MO or SSR pump unit and check the integrity of the control line
and connections as well as both seal bores.

Pulling procedure is identical to pulling a PX plug (Ref: WS-309-M).

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WS-315-H RUNING AND PULLING OF PETROLINE BRIDGE PLUG

Petroline Retrievable Bridge Plugs can be set and retrieved by wireline methods,
coiled tubing and drill pipe. For acurate pin point setting, it can also be set on electric
line utilising the CCL, but needs to be retrieved by regular wireline methods.

Applications: Shallow set barriers for tree maintenance.

Contingency plugging of completions with damaged nipples.
Zone isolation, water or gas shut-off.
Tubing leak identification.
Data acquisition near the producing interval.

Specification for 3½” Bridge Plug

Setting : Mechanically on Slick Line, Running tool: QXD.

Retrieval : Using 3" GS and Pulling Probe
Tool : 2.720"

Length with Running Tool (to P.O.P. Thread) : 9.1'

Length minus Running Tool (to P.O.P. Thread) : 7.5'

Pressure Differential : 5,000 psi above and below

Temperature Rating : 250 Degrees Fahrenheit

The Tool is designed to be set and retrieved in 3 1 /2" 9.2 Ib/ft tubing while being able
to pass through a 2.75" 1 D restriction.

3½" / 4½" Bridge Plug Procedures

Proposed, Toolstring

1.875" Rope Socket, 2.125" Accelerator, 8ft x 1.875" Stem, 2.125" Adjustable Upstroke
Jars, 1.875" Knuckle Joint, 1.875" Long Stroke Mechanical Jars.

Surface Equipment Checks

Wire records checked and wire tested, Martin Decker load cell in calibration. All other
associated wireline tools are to be in good working order.

Drift Run

The Bridge Plug drift is as supplied by Petroline, any other form of drift, ie gauge cutter
etc will not give an accurate resemblance of downhole conditions which will assist the
setting operation of the Bridge Plug.
Pinning procedures for Bridge Plugs will be established after the drift run is completed,
as this will indicate any problem areas within the well.

The maximum pick up weight should not exceed 800 Ibs if a 108 wire is used. Greater
pick up weights would not allow heavy jarring operations which may result in the Plug
not being set.

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Standard Programme for Running Bridge Plugs

1) Make-up Bridge Plug drift to wireline toolstring with JU type Pulling Tool.
2) Run in hole to setting depth taking care when passing through down hole
assemblies and restrictions.
3) Continue to run in hole with drift and tag hold up depth.
4) Pull out of hole with drift and record maximum pick up weight.
5) Make-up Bridge Plug to wireline toolsfring ensuring that the Pump Open Plug
and/or Equalising Device are installed.
6) Run in hole with Bridge Plug assembly at a maximum speed of 150ft/min, slowing
down when passing through all down hole assemblies.
7) Run in hole to approximately 25ft past setting depth then pick up to 2ft above
setting depth. By the slacking off the tools the Bridge Plug should rest on lower
slips. However, should it be necessary to move the Plug to a different depth, this
can be achieved by picking up on the Plug and repeating step 7.
8) Once landed on the lower slips, downward jarring will shear (4 x 1/4") Shear
Screws in the Upper Slip Holder to allow Upper Slips to move onto Cone
Assembly.
9) By jarring down for approximately 15 minutes - 25 jars, this will complete the
setting of the Upper Slips.
10) At this point an overpull of 150 Ibs above pick up weight will be applied to confirm
the Bridge Plug Upper Slips are set.
11) Upward jarring is now required to pack off the Element. Spang up approximately
30 times fairly lightly. (Should the Plug appear to move up hole during upward
jarring, jar down a further 15 times approximately).

Gradually build up the spang force and jar up a further 30 times (unless the
running tool shears off first). If the running tool has not yet sheared off, start firing
the spring jars until shear off is achieved.

12) Pull out of hole with wireline toolstring and secure.

13) Testing of Bridge Plug will begin with test from above to above SITP. Then leak
of test to be applied (see testing procedures).

After the rework on completion is completed, Bridge Plug pulling operations will
commence.

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Standard Programme for Pulling Bridge Plug

1) Ensure all other barriers have been removed prior to run in hole.
2) There can be two types of equalising device incorporated within the Bridge Plug
assembly and if the Pump Open Plug is sheared out and communication across
the Bridge Plug confirmed, there is no need to run the Equalising Prong on
wireline.

If however equalisation is preferred then the following steps should be followed.

3) Run in hole with Equalising Prong ensuring slight over balance in tubing
pressure. Continue to run in hole until Equalising Prong engages the Bridge
Plug.
4) By jarring down the shear pin in the top centraliser will shear and allow the Prong
to travel into the qualising device. Approximately 10-15 downward jars will shear
pins in the assembly allowing equalisation to commence.
5) Pull out of hole -and confirm centraliser shear pins are sheared. (Note: Tell Tale
Ring at top of Prong must be sheared).
6) Make-up GS with Shearable Prong probe to wireline toolstring.
7) Run in hole and engage into release mechanism of Top Sub and jar down then
pick up to confirm tool is latched if not, then repeat again.
8) When GS is latched this will confirm that the release mechanism has operated.
9) The toolstring should be picked up around aft and left to sit around 20 minutes (to
relax the element). Light jarring may be required to get the Plug off the Bottom
Slips.
10) Pull out of hole with Bridge Plug assembly.

Note: It is recommended that the 'J' be operated prior to pulling out of the hole as
this will allow the tool to land on bottom slips in the event of wire breakage.
Also, if any other problems arise it would be possible to shear off the pulling
tool.

General Assembly Notes

1) Ensure parts are clean and that none are damaged prior to assembly.
2) Apply copperslip to all threaded connections and Wave Springs.
3) Apply grease to Seals and seal surfaces.
4) Care must be taken to ensure non of the thin external sleeves are damaged by
overtightening in the vice.

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ITEM DESCRIPTION QTY PART NUMBER ITEM DESCRIPTION QTY PART NUMBER
01 FISHING NECK 1 500-3501-01-45 31 SLIP 4 500-3501-05-10
02 RATCHET RING 1 500-3501-02-45 32 SLIP HOLDER 1 500-3501-28-45
03 RATCHER END CAP 1 500-3501-07-45 33 FLAT SPRING 4 500-3501-47-17
*04 GRUB SCREW 1 G5-023 *34 BUTTON HD SCW 4 MC-075
05 SLIP HOLDER 1 500-3501-03-45 35 WAVE SPRING 1 WS-008
*06 BUT. HD. SCREW 1 MC-076 36 TRANSFER SLEEVE 1 500-3501-30-45
07 UPPER MANDREL 1 500-3501-08-45 *38 SHEAR SCREW 2 SS-043
*08 BUT. HD. SCREW 4 MC-075 *39 SHEAR SCREW 4 SS-021
09 FLAT SPRING 4 500-3501-47-17 40 END PIECE 1 500-3501-33-45
*10 SHEAR SCREW 4 S5-006 *41 GRUB SCREW 6 GS-023
11 SLIPS 4 500-3501-05-10 42 BOW SPRING 6 500-0000-01-08 /
12 UPPER CONE 1 500-6801-10-45 500-0000-02-17
13 TRIP KEY 2 500-3501-11-09 43 MAIN BODY 1 500-3501-34-45
14 SHEAR SLEEVE 1 500-3501-14-45 44 J-SLEEVE 1 500-3501-39-45
*15 SHEAR SCREW 4 S5-021 45 SEGMENTS 2 500-3501-38-09
16 SLIDING KEY 2 500-3501-13-45 46 END CAP 1 500-3501-36-45
17 RETAINER SLEEVE 1 500-3501-12-45 *47 GRUB SCREW 1 GS-023
*18 GRUB SCREW 1 GS-015 48 J-SCREWS 2 500-3501-37-09
19 SLIDING SLEEVE 1 500-3501-15-45 *49 GRUB SCREW 2 GS-012
*20 GRUB SCREW 1 GS-020 50 J-SLEEVE COVER 1 500-3501-40-45
21 PROTECTOR SLEEVE 1 500-3501-16-45 51 FEM. SET. SLEEVE 1 500-3501-41-45
22 INNER MANDREL 1 500-3501-17-45 52 TRANSFER KEYS 3 500-3501-42-45
*23 GRUB SCREW 1 GS-015 *53 GRUB SCREW 1 GS-015
24 COMP. END PIECE 1 500-3501-18-45 54 MALE SET. SLEEVE 1 500-3501-43-45
25 LOWER MANDREL 1 500-3501-26-45 55 SEAL-OFF SLEEVE 1 500-3501-00-70
*26 ELEMENT 1 500-3500-21-XX *56 SHEAR SCREW 4 SS-004
27 ANTI EXT. RING 1 500-3501-22-45 *57 GRUB SCREW 1 GS-020
28 SPRING 1 WS-007 58 BOTTOM SUB 1 210-2750-37-45
29 LOWER CONE 1 500-3501-23-45
*30 GRUB SCREW 1 GS-023

SCREW DESIGNATION
GS-012 : MS X 8.0mm LG.ST.STEEL NOTE:- ITEMS WHICH MAY NEED
GS-015 : MS X 5.0mm LG.ST.STEEL REDRESS AND ARE NOT CALLED OUT
GS-020 : ¼” – 20 UNC X ¼” LG.ST.STEEL
GS-023 : ¼” – 20 UNC X 3/16” LG.ST.STEEL AS REDRESS ITEMS ARE:
SS-043 : ¼” – 20 UNC X 10.5mm LG.ST.STEEL 1: SLIPS (ITELMS 11 & 31). THESE ARE TO BE CHANGED
SS-004 : ¼” – 20 UNC X 5mm LG.BRASS OUT AT THE DISCRETION OF THE SUPERVISOR. THEY
SS-006 : ¼” – 20 UNC X 8mm LG. BRASS SHOULD BE CLOSELY INSPECTED AFTER EACH RUN FOR
SS-021 : 3/16” – 32 BSF X 5 mm LG. BRASS SIGNS OF DAMAGE.
SEAL REQUIREMENTS 2: WAVE SPRINGS (ITEM 29 & 35). THESE MUST BE
OV-026-075 QTY 1 CHANGED OUT WHEN THE FREE HEIGHT OF THE
OV-031-075 QTY 2 SPRINGS IS LESS THEN 24.00mm & 42.00mm
OV-032-075 QTY 1 RESPECTIVELY.
OV-121-075 QTY 2 3: FLAT SPRINGS (ITEM 29 & 33). THESE SHOULD BE
OV-123-075 QTY 1 CHANGED OUT WHEN THEY BECOME UNABLE TO HOLD
OV-126-075 QTY 1 THE SLIPS IN THE COLLAPSED POSITION.
OV-130-075 QTY 1 4: BOW SPRINGS (ITEM 42). THESE SHOULD BE CHANGED
PB-121-090 QTY 4 (BACK UP F/OV-121) OUT AT DISCRETION OF SUPERVISOR. SPRING
BU-0357-0314-51 QTY 2 (BACK UP F/OV-123) CONDITION WIL DEPEND ON DISTANCE SPRINGS HAVE
BU-0454-0410-51 QTY 2 (BACK UP F/OV-130) COVERED AND RESTRICTION THRU’ WHICH THEY’VE
PASSED.

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WS-315-I PACK-OFF ANCHORS

Pack-off”s are designed to "straddle" or pack off holes and any other communication
between the tubing and annulus, while still permitting production to pass through the
hollow centre of the pack - off.

A pack - off is made up of the following components:

Upper Hold down

Upper Seal

Spacer Pipe

Lower Seal

Lower Anchor Stop

The Pack off is installed with the upper and lower seals on either
side of the leak in the tubing. The spacer pipe length is limited by
the lubricator length and the deviation of the tubing. If spacers
longer than approX 6' - 8' are required a seal extension is used
and spacers are "assembled" downhole.

The most common and reliable Pack-Off is the Otis type ‘G’.

It has the following design advantages:

1) Internal running/pulling neck permits large flow bore.
2) Proven ‘G’ element seals (used in ‘D’ collor locks).
3) Can be set in collar type or smooth joint tubing, using 2
different botom stops.
4) Upper and lower seal assemblies are identical
5) Straight forward running and pulling procedure.

The bottom stop is run first. The type is determined by type of

tubing.
1) EU or NU tubing (with collar recess)
- Type ‘D’ colar stop.
2) Smooth joint tubing (e.g. HCS or VAM)
- ‘G’ tubing stop

The bottom stop must be run first, separately.

The reminder of the pack-off is run onto this stop, either in one
piece or with the pack-off and upper hold-down run separately.

The upper hold-down is also a ‘G’ tubing stop, and both of these
components are run and pulled on a GS.

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The G Element Assembly is used on both ends of the spacer pipe. It is shown in the
upper position but by inverting the complete assembly it can be used as the lower seal.

After setting the lower stop the pack-off assembly

is lowered into position using a GS running tool.
Downward jar action compresses the elements
and they expand against the tubing wall.

Spacers ( * )can be added beneath the expander

to alter the expanded OD of the element to suit
the tubing weight.

As a lower seal : Collet is screwed into lower

end. This latches into fishing neck of D Collar
lock or G Tubing Stop. When pulling the pack off
this collet ensures, both elements are
fully-retracted before the pack - off is pulled.

As an upper seal : G tubing stop can be directly attached or a fishing neck can be
attached to the internal thread.

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WS-315-J OTIS TYPE ‘A’ PERFORATOR

Purpose:

In certain cases where tubing-casing communication cannot be achieved by normal

wireline methods for various reasons, a hole will have to be punched. A non explosive
mechanical puncher OTIS type” A” is used for this. The perforator locates on top of an
F tubing stop.

Preparation of the Otis ‘A’ Perforator

The perforator should be stripped down, checked, greased and assembled before
operation .
1) Remove Dowell pin lock screw (10) and remove Dowell pin.
2) Remove shear pins (2 and 12).
3) Remove punch holder from body and depress catch stop (6) when fully stroked
out. Be careful that catch and spring are not lost.
4) Perforator is now ready to be checked.
5) Check if punch travels freely and smooth over the tapered wedge and that the
punch is straight and sharp.
6) Grease the perforator with grease.
7) Assemble perforator paying attention to the way puncher is installed on the
tappered wedge. The punch should remain vertical when travelling over the
wedge. When it is installed 180° wrong, the punch will tilt slightly during
perforating and will get jammed in the body.
8) Install shear pins 2, 12 and Dowell pin.
9) Perforator is now ready for use.

Perforating Tubing with an Otis ‘A’ Perforator

1) Rig up as per
2) Tool string as per
3) Before perforating an F- tubing stop should have been set at the required depth.
4) Be sure pressure between annulus and tubing is equalised.
5) Run perforator till it lands on lop of F- tubing stop.
6) Jar down lightly in order to shear two top pins. Do not jar down too hard since
bottom put will shear and perforator will lock in closed position and can not be
operated anymore. This is the safety feature in case perforating should not take
place after the two top pins have been sheared.
7) By jarring up rapidly, the perforator punch will be pushed out by the tapered
wedge and perforate the tubing wall. Ten jars up should be suff icient to
perforate.
8) When tubing is perforated, the punch will retract automatically and tool can be
pulled to surface.
9) Perforation is now completed.
10) Retrieve F-tubing stop.

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OTIS ‘A’TUBING PERFORATOR

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WS-315-K RUNNING AND PULLING OF TYPE “F” COLLAR STOP

The "F" collar stop is run on an Otis "SB" pulling tool. Before latching the "F" stop into
the pulling tool, install a 1/8" shear pin when the mandrel is fully extended at the top of
the collet weldment. Close the collet fingers together and hook the collet springs over
the opposite roll pin. Latch the "F" stop into the "SB" pulling tool.

When picking the "F" stop up into the lubricator after zeroing the counter, have a helper
guide the stop in so the collet springs are not released.

Run the tools down to the desired depth plus 1.5 or 3 m. Pick the tools up about 5 m
and then lower them to try and find a collar. If a collar is not found, pick the tools up
about 8 m and lower them again. A third try may be necessary at 10-11 m.

When a collar is located and the jars are closed, pick the tools up about 0..25m and hit
down moderately. That should shear the 1/8" shear pin and let the large OD at the end
of the mandrel start past the stop shoulders about a third of the way up the fingers.
Three or four more downward jars lock the low end of the mandrel below the stop
shoulders and shear the shear pin in the "SB" pulling tool. The work string can be
brought back to the surface.

To pull the "F" stop an "RB" or "SB" is run on the work string to the stop. Latched on to
it and one or two jars upward pull the large OD of the mandrel past the stop shoulders
inside the fingers, and the "F" stop can be pulled up the tubing.

To check that the stop is on the pulling tool after pulling up about 11 or 12 m, stop and
lower the tool string back down the hole. Approximately 9 or 9.5 m above the pulling
depth the stop should sit down again. Now the work string can be pulled to the surface.

‘F’ COLLAR STOP

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WS-315-L RUNNING AND PULLING OF TYPE “D” COLLAR STOP

Design Principle

The D collar stop is designed to provide a locking mechanism that can withstand high
impact from wireline tool strings falling. It can also be the anchor for several other
subsurface assemblies such as tubing packoffs. It will lock in EU and NU collar
recesses, and the D collar stop can withstand 34,500 kPa pressure differentials.

Operating Principle

Before attempting to run the D collar stop in a well, a full size gauge tool should be run
to a point just below where the D collar stop is to be set. The stop is pinned to the C
running tool and run to a depth just below the desired depth. The tool string is then
pulled up until the dogs engage the first recess. If the recess is too far above the
desired depth the stop can be run down below the next recess and locked in at that
depth.

NOTE: The D collar lock can be moved down if an overstrain that would lock the
shoulder of the mandrel in the collet of the sleeve has not taken place.

A few upward strokes will shear the pin and the wireline tools can be pulled from the
well.

A GS pulling tool is used to retrieve the D collar stop. The GS pulling tool is made up
on the work string and run down to the D collar stop. After the tools contact the stop
and they sit down, pick the tools up slowly to ensure engagement of the fishing neck.
Several downward blows will knock the mandrel down and release the dogs.

NOTE: The D collar stop cannot be released by upward jarring.

The 'D' Collar Stop is run on a 'C' running tool which is pinned to the lower end of the
mandrel. It can be located in any EU or NU tubing collars.
It is lowered to below the collar and then picked . up
until the dogs latch in the collar recess. Jar up . to
shear the pin and pull the running tool to the surface.

The collar stop is pulled on a GS.

Holes marked 'A' are lined up and locked with a

punch to unscrew the mandrel cap when stripping this
tool

‘C’ Running Tool

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WS-315-M TYPE “F” TUBING STOP

The 'F' Tubing Stop is designed to set in all tubing (except plastic coated) and hold the
force from the top.

It is run and pulled on an SB.

Run slowly to the desired depth, then overrun the

slips to grip the tubing wall. If the position is
incorrect, pick-up and reposition. Jar down to set
tight and shear the SB.

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WS-315-N TYPE “G” TUBING STOP

The 'G' Tubing Stop can be run and pulled on a GS. To set, the assembly is run in the
hole slowly. At the depth at which the tubing stop is to be set, the rate of descent is
increased until the slip mandrel overrides the slips. If the position is incorrect, pick-up
and reposition. Jar down to set.

An alternative running is the type ‘G’ quickset. This permits accurate positioning and
setting.

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WS-315-O TYPE “T” PERFORATOR STOP

The 'T' Perforator Stop is attached to the perforator.

Running in slowly, the whole assembly can be

lowered to perforating depth. Rapid downward
movement `overruns' the slips. The stop then
provides a firm base on which to trip the perforator.

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WS-315-P TYPE “F” COLLET STOP

The 'F' Perforator Collet Stop is designed to screw directly into the base of the
perforator (or via the knuckle joint).

It is set in the same manner as the 'F' collar

stop but by attaching to the perforator, time
is saved setting and pulling the collet stop.

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WS-315-Q RUNNING AND PULLING OF PES-HE-3 RETRIEVABLE BRIDGE
PLUG

Description

The Model HE3 Retrievable Bridge Plug is a new generation wireline retrievable well
bore plugging device with a built-in, mid-mounted, mechanical pressure equalisation
facility. The HE3 may be set on slickline, electric line, coil tubing or a workstring.
Retrieval of the plug is by slick line, braided line, coil tubing or a workstring. When run
on slickline or electric line, a Pyrotechnic Pressure Setting Tool (PPST) or a Type E4
Wireline Pressure Setting Assembly (WLPSA) using a slow burn power charge, will be
required.

Dimensional and Performance data are detailed on the Specification Sheet page 3.

Application

The HE3 is designed for deployment in any type of well, whether horizontal or vertical,
oil, gas or water, and is specifically adapted for applications where well bore debris
may be anticipated.

Features: Benefits:

One piece dual modulus packing element The patented packing element offers the
best inservice performance possible.
Selection of reinforcing materials and
fillers, greatly enhance the stability of
the element when exposed to
temperature and pressure.

Compact design Innovative engineering has resulted in a

short compact design which eases
deployment in restricted work areas.
The HE3 is ideally suited for use where
the height above the well is limited and
access is difficult or where doglegs are
resent in the well.

Mid-mounted equalising feature Simplifies pressure equalisation prior to

retrieval even when debris has filled the
sump.

Modular design From one basic chassis several casing

sizes can be catered for simply by
changing the element, gauge rings and
slips. This can dramatically reduce
inventory.

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Features: Benefits:

Full circumferential slips The full circumferential slip design

results in a smooth profile, which
reduces the risk of premature setting
whilst running in hole, and hanging-up
on retrieval. Loads are distributed
uniformly within the HE3 plug and the
tubing, minimising potential damage and
facilitating recovery operations.

Packing element above the slips This protects the slip mechanism from
casing debris and greatly improves
retrievability.

Controlled setting action The setting tools deliver a controlled,

sequenced force into the packing
element and slips. This distributes
setting loads uniformly, both within the
tool body and in the tubing, and make
the HE3 ideally suited for applications
which require gauges to be suspended
beneath the plug.

Controlled setting avoids the stresses

and damage to tubing or plug, which are
associated with systems which use a
jarring action to set. As a result, impact
damage, scoring or permanent
deformation of the tubing or plug is
avoided.

The setting action is not dependent on

plug/tubing contact, and there is no
need for the added complexity of a drag
block or friction mechanism.

Setting method flexibility May be set using conventional slickline

or electric line setting tools, and on
coiled tubing or workstring.

Various slip options Different slip designs are available,

allowing deployment in all environments.
Standard slips for carbon steel tubing,
scale slips for heavily corroded or scaled
tubing, and insert slips for high chrome
applications, where conventional slips
may allow plug slippage.

Field redressable Due to its simple and robust

construction, the HE3 is fully field
redressable, using the minimum of
equipment and operating and assembly
instructions.

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Features: Benefits:

Slips mechanically retained in the When the HE3 has been released the
retracted position slips are mechanically held in the
retracted position to prevent hanging up
during retrieval.

SPECIFICATION SHEET
Commodity No. 801HE3359200

Dimensional Data
Size 3592
Casing OD 3 – ½”
Weight 9.2 lb/ft
Gauge Ring OD 2.710”
Element OD 2.650”
Minumum Bore 0.125”
Fishing neck (Internal) 1.380”
To pass Through Restriction 2.750”
Length 64.41”
Weight (approx.) 106 lb.
Top Connection None
Bottom Connection Bull Nose
Drawing No. M11922

Performance Data
Working Pressure 7,500 psi
Maximum Working Temperature 275°F
Base Material AISI 4140 18-22 Rc
Elastomer Material Therban/Viton
Class of Service Standard & H2S

Assembly Construction Commodity No.

Chassis Sub Assembly 020759 – 00
Conversion Kit 021258 – 00

Assembly Equipment Commodity No.

Redress Kit 801HER359202
Initiation Devices TDI – C 320TD0C00000
SLIDE – C 320IC0236200
Setting Tools PPST Size C 320PT0C00000
DR Workstring Size C 270DR0C00002
E4 WPSA Size 10 804E40100000
PX Adaptor 303PX0450001
Running Tool 303RO0400005
Pulling Tool 303PO0350004

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PARTS LIST: 801HE3359200
ITEM COMMODITY QTY PART
NO NO. DESCRIPTION
1 020741 – AE 1 Body Lock Ring Sleeve
2 020742 – AE 1 Inverted Body Lock Ring
3 020743 – AE 1 Main Mandrel
4 020744 – AE 1 Running Head
5 020745 – AE 1 Fishing Neck
6 020746 – AE 2 Split Ring
7 020747 – JR 1 Snap Ring
8 020624 – ZH 2 Element Back Up Ring
9 020749 – AE 2 Cone Body Lock Ring
10 020750 – AE 1 Lower mandrel
11 020751 – JR 1 Inner Mandrel
12 020752 – AE 4 Release Dog
13 020753 – AE 1 Dog Support
14 020754 – AE 1 Bull Nose End Sub
15 021030 – MB 6 Bow Spring
16 020626 – ZA 4 O – Ring Back Up
17 020756 – ZA 2 O – Ring Back Up
18 020757 – ZA 2 O – Ring Back Up
19 020758 – ZG 6 O – Ring Back Up
20 010PSV222040 2 O – Ring
21 010PSV215040 1 O – Ring
22 010PSV129040 1 O – Ring
23 010PSV114040 4 O – Ring
24 001PQB252004 6 Brass Shear Screw
25 002PQS252004 2 Stainless Steel Set
26 001PQB252005 6 Brass Shear Screw
27 002PQS252005 16 Stainless Steel Set
28 022637 – FC 1 Key
29 003PQS252052 3 Socket Head Cap Screw
30 303R16423 1 Shear Ring (30k max)
31 003PQS103206 2 Socket Head Cap Screw
32 021263 – AE 1 Upper Gauge Ring
33 021264 – AE 1 Lower Gauge Ring
34 021265 – AC 1 Upper Cone
35 021266 – AC 1 Lower Cone
36 021267 – AH 3 Slip
37 021268 – AE 1 Slip Ring
38 021269 – AE 1 Settling Adaptor Ring
39 021247 – 00 1 Packing Element
Note: Highlighted items included in conversion Kit {021258–00}

DIMENSIONAL DATA (Inches)

A 64.410
B 2.710
C 2.710
D 0.125

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Running Procedure

Detailed instructions covering use of the associated equipment mentioned in these

procedures, will be found in the respective Technical Documents covering those
devices.

More detailed running and pulling instructions can be provided for individual
applications.

Notes: Prior to running the HE3, it is recommended that a Junk Basket/Gauge Ring
run should be made, to ensure that the tubing is clear.

The HE3 Retrievable Bridge Plug may be run with a PPST, E4 WLPSA or by DR
Workstring Setting Tool. Procedures for attaching these devices are written in the
appropriate Technical Documents, which should be consulted.

Electric Line Operations

1) Make up the RO Running Tool to the Plug.

2) Make up the Running Tool and HE3 assembly to the PPST or E-4 WLPSA.

Note: Both the PPST and E-4 use a slow burn power charge, to control setting
speed.

3) Install tools in the riser or lubricator and confirm pressure equipment integrity.
Run in the hole.

Note: Do not exceed a maximum running speed of 7,500 ft/hr. Reduce speed when
passing through restrictions.

4) Perform a correlation pass. Bring tool back up hole to setting depth.

5) Send power to set the tool. Once set, the Running Tool will release automatically
from the plug when failure point of the shear-ring is reached, and the tension
device will show loss of tool weight.

Note: On no account attempt to tag the plug after setting.

6) Pull WLPSA out of hole and make tools safe following standard procedures for
the tool.
7) Disasseble, clean and redress the Setting Tool and the Running Tool, then
protect them with an anti-corrosion coating for further use.

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Slick Line Operations

Slickline operations involve the use of the Time Delay Initiator (TDI) or the Slickline
Initiator Device (SLIDE).

1) Follow the running procedure for electric line, steps 1 – 2.

2) Arm and attach the TDI or SLIDE following the appropriate procedure.
3) Install tools in the riser or lubricator and confirm pressure equipment integrity.
Run in the hole.

Note: Do not exceed a maximum running speed of 7,500 ft/hr. Reduce speed when
passing through restrictions.

4) Confirm setting depth from sllickline depth counter, or predetermined No-Go

depth indication. If the TDI is used, wait until the end of the selected time delay,
at which time the plug will set. If SLIDE is used, command the tool using the
correct wireline manipulation sequence.
5) Observe the loss of tool weight as the plug is set.

Note: On no account attempt to tag the plug after setting.

Continue with the running procedure for electric line, step 6.

Drillpipe or Coiled Tubing Operations

1) Make up the RO Running Tool to the Plug.

2) Make up the RO Running Tool and Plug to the DR Workstring Setting Assembly.
3) Make up the assembled toolstring to the coiled tubing or drillpipe.
4) Run in hole to setting depth. The workstring or coiled tubing will fill automatically
with well fluid whilst running in the hole.
5) Drop the Setting Ball and pump down (or allow to fall under gravity) to the Ball
Seat in the DR Setting Assembly.
6) Pressure up to 1,000 psi. to initiate setting. Increase pressure up to
predetermined setting pressure (as shown in Specification Guide) to fully set the
Plug. Once set, the RO Running Tool will release automatically from the Plug.
7) Note the weight loss shown by the weight indicator.

Note: On no account attempt to tag the Plug after setting.

8) Pull out of hole with the workstring or coiled tubing, which will drain automaticaaly
during recovery from the well.

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Retrieving Procedure

9) Rig up and run in with the Model PO and Model PX Anti Pre Shear Adapter, on a
string which includes a jar facility. Procedures for attaching theses devices are
written in the appropriate Technical Documents, which should be consulted.
10) Slow down on approaching the plug, in preparation for pressure equalisation.

Note: It is essential that pressure across the plug is fully equalised before attempting
to pull the HE3. This may be achieved by manipulation of surface pressure to
balance pressure across the plug, or by operating the integral shear down
equalising feature.

11) Latch into the HE3 and tap down to shear the pins in the HE3 Fishing Neck,
which will move the Inner Mandrel into the equalising position.
12) Wait until equalisation is complete, then jar upwards to shear the retrieval pins.
This allows the Inner Mandrel to move up fully, permitting the slips to retract and
allowing the element to relax.
13) Wait for 30 minutes to allow the packing element to contract fully.
14) Retrive HE3 slowly (maximum 10,000 ft/hr.) to avoid swabbing the well. Reduce
speed further on approaching restrictions.
15) When at surface, lay down the HE3, taking care not to impose excessive
sideways force on the Pulling Tool Latch Fingers. Release the Pulling Tool from
the HE3, by pulling back the Spring Latch using two pin punches. This operation
is done via the Spring Module windows.
16) Disassemble, clean and redress the Pulling Tool and HE3 following procedures
described in the relevant Technical Documents.

NOTE: As proven in the field, a heavy toolstring with spring jars incorporated is
required when pulling the plug. Additional swelling of the element due to Co2
will make it necessary to jar it through nipples and sleeves on the way out.

Model PO Pulling Tool

Description

The Model PO Pulling Tool is a latch type mechanical device run on slick line or
braided line, for the pulling of the PES range of Retrievable Bridge Plugs, with the
exception of the Model WI Water Injection Retrievable Bridge Plug, which requires a
specific pulling tool

Application

Used in wireline plug retrieval operations, except in horizontal well completions, when a
Model DP Drillpipe Pulling Tool or a Model PU Pulling Tool is required.

Dimensional and Performance data, together with an Accessory Equipment list, are
detailed on the Specification Guide page.

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Features: Benefits:

Standard fishing neck and threaded Permits deployment without requirement

coupling for crossovers.

Shear down emergency release Pulling string can be released if the plug
is stuck, to allow access with heavier
pulling equipment.

Lower threaded connection (except on Allows use of pressure equalising prong,

smaller sizes 23 and 28) where this facility is required.

PARTS LIST 303PO0350004

ITEM COMMODITY QTY PART
NO NO. DESCRIPTION
1 303P16221 1 Fishing Neck
2 008PQB120035 1 Brass Shear Stock
3 303P983 1 Snap Ring
4 303P15934 1 Shear Pin Housing
5 020P985 1 Spring
6 019340-AC 1 Latch Housing
7 019339-AC 1 Latch
8 303P980 1 Core
9 0029QS252006 2 Soc Head Set Screw
10 002PQS102408 4 Soc Head Set Screw
11 021684-AE 1 Centraliser Ring

DIMENSIONAL DATA (INCHES)

A 20.25
B 2.710
C 1.750
D 1.530
X 1 – 1/16” – 10 UNS Pin
Y 7/16” – 14 UN Box Thread

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Model PX Anti-Pre-Shear PO Pulling Tool Adapter

Description

The PIES Model PX Anti-Pre-Shear Adapter, is a device used in conjunction with the
model PO Pulling Tool. It is used to prevent accidental operation of the emergency jar
down release mechanism in the PO Pulling Tool, when engaging the fishing neck and
jarring down to equalise pressure across the Bridge Plug. Operation of the emergency
jar down release mechanism in the PO Pulling Tool prior to release of the Bridge Plug,
would require the retrieval and re-pinning of the PO Pulling Tool, necessitating a
second run in the hole. Jarring up to release the Bridge Plug, disables the PX Anti
Pre-Shear Adapter, subsequently allowing the emergency jar down release mechanism
to operate, if the Bridge Plug will not come free.

Application

The PX Adapter is used in conjunction with the PO Pulling tool where it is envisaged
there will be engagement problems into the relative fishing neck, due to deviation,
debris, depth, etc. Once the PO, PX Pulling tool has engaged the fishing neck, the PX
Adapter can be `cocked' to return the PO Pulling tool into a jar down to release.

Features: Benefits:
Conversion Turns existing jar down release pulling
tools into jar up.
Anti pre-shear Anti pre-shear allows continued heavy
jarring on the assembly with no
detrimental effect to the shear pin, unlike
similar designs where inertia causes the
release pin to pre-shear.
Re-cocking facility The PX Adapter, is attached to the PO
Pulling tool and is made up jar up to
shear. The tool can however, once
latched into the fishing neck, be cocked
to return to jar down to shear.
No re-design of existing pulling tools Attachment to the PO Pulling tool is via
a simple box / pin connection. No
requirement to alter existing design of
the PO Pulling tool.
SPECIFICATION SHEET
Commodity No. 303PX0450000
Dimension Data
Size 45
Maximum OD 2.640”
Minimum Bore N\A
External Fishing Neck 1.750”
Length 19.937”
Weight (approx.) 5 lb
Top Connection 1 – 1/16” 10 tpi. UNS 2 pin
Bottom Connection 1 – 1/16” 10 tpi. UNS 2 Box
Drawing No. M10208
Performance
Tensile Rating 47,180 lb.
Base Material AISI 4140 18-22 Rc
Class of Service Standard H2S
Associated Equipment Commodity No.
Used with Size 45 PO Pulling Tool 303PO045000X

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PARTS LIST 303PO0350004

ITEM COMMODITY QTY PART
NO NO. DESCRIPTION
1 303P16221 1 Fishing Neck
2 008PQB120035 1 Brass Shear Stock
3 303P983 1 Snap Ring
4 303P15934 1 Shear Pin Housing
5 020P985 1 Spring
6 019340-AC 1 Latch Housing
7 019339-AC 1 Latch
8 303P980 1 Core
9 0029QS252006 2 Soc Head Set Screw
10 002PQS102408 4 Soc Head Set Screw
11 021684-AE 1 Centraliser Ring

DIMENSIONAL DATA (INCHES)

A 20.25
B 2.710
C 1.750
D 1.530
X 1 – 1/16” – 10 UNS Pin
Y 7/16” – 14 UN Box Thread

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CHAPTER 16
WIRELINE FISHING OPERATIONS
TABLE OF CONTENTS

WS-316-A INTRODUCTION TO WIRELINE FISHING OPERATION ..............................2

WS-316-B LEAD IMPRESSION BLOCK ..........................................................................7
WS-316-C BLIND BOX......................................................................................................8
WS-316-D WIRE CUTTERS GENERAL INFROMATION ................................................9
WS-316-E CUTTER BAR ................................................................................................10
WS-316-F GO-DEVIL ......................................................................................................12
WS-316-G FLOPETROL CUTTER .................................................................................13
WS-316-H KINLEY SNEPPER .......................................................................................15
WS-316-I SIDEWALL CUTTER ......................................................................................16
WS-316-J WIRE FINDERS .............................................................................................17
WS-316-K BOWEN WIRE FINDER ................................................................................18
WS-316-L PETROLINE COLLAPSABLE WIRE FINDER ..............................................19
WS-316-M WIRE FINDER – SLOTTED BODY ..............................................................20
WS-316-N WIRE FINDER GRAB ...................................................................................21
WS-316-O WIRE GRAB ..................................................................................................22
WS-316-P WIRE CENTRE SPEAR ................................................................................23
WS-316-Q WIRELINE GRAB - EXPANDABLE ..............................................................24
WS-316-R UNIVERSAL BELL GUIDE AND SKIRT .......................................................25
WS-316-S BOWEN AND O’BANNON OVERSHOTS ....................................................26
WS-316-T BDK WIRELINE OVERSHOT........................................................................29
WS-316-U FLOPETROL RELEASABLE OVERSHOT ...................................................31
WS-316-V PERTOLINE HEAVY DUTY RELEASABLE OVERSHOT ............................33
WS-316-W BULLDOG OR CENTRE SPEARS ..............................................................35
WS-316-X WIRELINE RELEASABLE SPEAR ...............................................................37
WS-316-Y BDK INTERNAL FISHING TOOL WITH TAPERED MANDREL ..................40
WS-316-Z BDK INTERNAL FISHING TOOL WITH PARALLEL MANDREL .................41
WS-319-ZA ALLIGATOR GRAB .....................................................................................42
WS-316-ZB ACCELERATOR..........................................................................................44
WS-316-ZC BDK HEAVY DUTY ACCELERATOR ........................................................47
WS-316-ZD CENTRALISER ...........................................................................................49
WS-316-ZE MAGNET .....................................................................................................50
WS-316-ZF SWANGING TOOL ......................................................................................51
WS-316-ZG TUBING END LOCATOR ...........................................................................52
WS-316-ZH WIRELINE BRUSH .....................................................................................53
WS-316-ZI WIELINE TUBING DRIFT AND DRIFT CUTTER ........................................54
WS-316-ZJ WIRE SCRATCHER ....................................................................................55

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WS-316-A INTRODUCTION TO WIRELINE FISHING OPERATION

Introduction:

Fishing techniques are extremely varied and depend largely on the circumstances and
well conditions for each individual situation.

The aim of wireline is to complete the set programme as quickly and safely as
possible without getting the tools stuck or breaking wire. Towards this objective the
following practices should be observed:

1) Check and maintain equipment regularly.

2) Function test hydraulic jars and equipment to be run.
3) Check pulling / running tools move to the sheared position by removing the shear
pins and function test.
4) Run the gauge cutter - larger than the tools to be run - before running the tools.
5) Always be sure to run a tool with an OD larger than the rest of the toolstring,
BELOW the jars.
6) Observe load limitations on the wire - DO NOT OVERPULL.
7) Keep the wire oiled - to reduce wear and friction.
8) Avoid kinking the wire.
9) Check the counter is correctly threaded and zeroed (odometer re-engaged).
10) Keep the hydraulic pressure relief valve correctly adjusted.
11) Use correct equalising procedures - Correct prongs.
- Wait until equalisation is complete.
12) Concentrate on what you are doing.
13) Try to `visualise' (i.e. sense) what is occurring downhole, as the wire is
manipulated on the surface.
14) If you are unsure - ask for assistance.
15) Keep a careful record of the toolstring lengths and OD's.
16) Think AHEAD - prepare for the unexpected!
17) Check the well records for previous problems encountered.

Unfortunately however careful an operator is, fishing jobs will still occur. The following
section describes the fishing tools, their uses and limitations.

Practical fishing exercises will be set on the training well by your instructor.

REMEMBER: The practical skills of fishing are the most difficult, but the most
important is that you can learn.

Discuss a fishing programme with your supervisor and consider all possible results of a
run and plan for the varied possibilities.

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Fishing for wire

Of all the possible fishing situations broken wire is the most common, and for this
reason it will be discussed first.
The 2 possibilities are:

1) Wire broken on surface, and remaining visible.

2) Wire broken downhole.

Wire Remains Visible

The wire is reconnected using a nut, link from the chain, or disc from the rope socket
(see sketch below) and spooled back onto the drum. The hay pulley may have to be
repositioned to permit the knot to pass. Wire can be removed from the counter head.

If the toolstring is stuck, refer to the `cutting wire' information in this section.

Wire Broken Downhole

The first objective is to locate the top of the wire, but first we must estimate its position
to provide a starting point.

The following factors must be considered:

1) Size and age of wireline (wire becomes less flexible with age).
2) Tubing ID (the bigger the ID - the greater the fall).
3) Well fluid (oil, water, gas etc.)
4) Strain (load) on the wire when it broke.
5) Where it breaks (near the surface or near the bottom).
6) Whether the tools were stuck or free to fall.

While the effect of all these factors cannot be accurately determined, the following `rule
of thumb' allows an approximation of the position of the wire

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Wire fall calculations

The amount of fall is measured from the level where the wire would be if it was
standing straight.

The following table is for IPS and alloy steel lines (excluding stainless steel, which is
approximately 50% of these values):

Tubing Size Wireline OD Fall in Feet per 1,000’ % of Wire in Hole

8”
23/ 0.092” 10 1.0
2½” 0.092” 12 1.2
3½” 0.092” 16 1.6
3½” 0.108” 15 1.5
3½” 3/ ”
16 20 2.0
4½” 0.108” 27 2.7
4½” 0.092” 29 2.9
4½” 3/ ”
16 35 3.5
5½” 0.108” 40 4.0
5½” 0.092” 45 4.5
5½” 3/ ”
16 50 5.0
7” 0.108” 90 9.0
7” 3/ ”
16 100 10.0

Wire remaining in the well is what is important, and this can be determined by the
reading on the counter when the broken end returns to the surface.

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Wire fall calculations

To determine the actual depth of the top of the wire, we must find the following
information in this order:

1) How much wire remains in the hole.

2) Where the top of the wire would be if it was standing straight.

Depth of the toolstring - Wire remaining in the hole = Top of the wire.

3) How much the wire will fall.

4) Where the wire actually is.

Straight depth - Approximate wire fall = Actual wire depth.

Example Wire Breaks - hen the broken end appears on the surface, the
counter reading is 960 metres. Allowing for the distance from the
counter head to zero (tubing hangar) via the hay pulley and lubricator
(40), the wire remaining in the well is 1,000 metres. i.e. Another 1,000
metres of wire would be needed to return the counter to zero.

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General Fishing Guide Lines

1) Keep accurate records of toolstring (length / diameters) and tools run in the well.
2) Prior to running a fishing tool, carefully consider the options.
3) Think of 2 other tools which could be run if the first is not successful.
4) Carefully consider what action can be taken if the result of a run is not the
expected / desired outcome.
5) Attempt to remove the broken wire first - then the tools (unless you know the
tools have been blown above the wire).
6) Use an impression block when necessary to check downhole situations.
7) Keep all wire recovered from the well until the fishing job is complete. Record the
length of pieces as they are recovered. This method will provide a check on the
wire remaining in the well.
8) Discuss the operation with several operators / supervisors to gain as many ideas
as possible.
9) Carefully CHECK the fishing tools and equipment on the surface to ensure they
will latch the tool / equipment you wish to latch downhole.
10) Add up the toolstring length and length of tools to be removed.
11) When running a Blind box through the middle of the wire to box it off at the rope
socket, run the tool string prepared with a “weak” rope socket (i.e. a rope socket
complete with spring, spring support and disk. Make 2 wraps for 0.108” wire and
4 wraps for 0.092” wire only). Do not use the Tear Drop type rope socket. The
same applies to running a LIB through the middle of the wire to get an impression
of the top of the rope socket. In both cases a tubular jar must be installed in the
tool string.

ALWAYS ENSURE THAT YOU HAVE SUFFICIENT LUBRICATOR LENGTH TO

GET THE COMPLETE ASSEMBLY ABOVE THE MASTER VALVE.

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WS-316-B LEAD IMPRESSION BLOCK

The Impression Block (LIB = Lead Impression Block) is similar in appearance to the
blind box, but it is filled with lead which extends below the bottom edge. The lead is
`keyed' in position by a roll pin or a hex headed bolt. Either of these are installed prior
to pouring molten lead inside.

Uses

To obtain a `picture' of the downhole blockage.

Example Rope socket (with or without wire).

Prong.
Lock mandrel.
Parted tubing.

Preparation

Roughly flatten the face with a hammer, then smooth with

course rasp. Finish with a smooth file and a piece of steel
shear stock rubbed across the face to give a `polish'.

Ensure there are no indentations in the surface prior to

running.

Check that there is no `overlap' around the edges, as this

could hang up in the collars when pulling out and dislodge a
chunk of lead.

Caution: (i) When refilling, melt the previous lead out and replace continuously.
Do not stop and restart, as this will create a weak flaw which could
separate downhole.

(ii) Jar down ONCE only, multiple impressions will only cause confusion
and mis-interpretation.

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WS-316-C BLIND BOX

The Blind Box is used when heavy downward jarring is required to dislodge a fish, or
push something down the hole. It is flat on the bottom and hardened to reduce wear
and damage.

It is available in a range of sizes to suit the application.

As a `cutter bar', it is made up below a piece of stem and

rope socket then dropped in the well to cut wire downhole.

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WS-316-D WIRE CUTTERS GENERAL INFROMATION

Cutting of the wire can be made necessary in the following circumstances:

1) Loss of jar action when - The toolstring gets blown up the hole.
- The jars get fouled with wire.
- The toolstring gets buried in sand / scale.
- The toolstring gets stuck above the jars.
- The tools are latched and cannot be sheared off.

2) When the toolstring is in the casing and will not re-enter, the tubing wire can be
cut to abandon the toolstring but recover the wire.

3) When wire is broken further up the well but the toolstring is stuck, consider
cutting the wire BEFORE running the wire finder to ball up the wire.

Tools used to cut wire can be divided into 2 categories:

A. To cut the wire at the rope socket after the wire is broken higher up the well.

B. To assemble around the wireline above the BOP and drop using the wire to guide
the cutter to the rope socket, then cut.

In group 'A' we have 2 types of tool:

1) Cutter Bar.

2) Sidewall Cutter.

In group 'B' we have 3 types of tool:

1) Bevelled Go-Devil.

2) Flopetrol Cutter.

3) Kinley Snepper.

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WS-316-E CUTTER BAR

The purpose of the Cutter Bar is to cut the wire at the top of the
rope socket of a toolstring which cannot be retrieved.

It is made up of a rope socket, stem and blind box, and is dropped

from the surface. Alternatively the cutter bar can be run on an SB
tool.

Stem Select the length to suit well conditions. Heavy oil will
require a long length of stem. Extreme caution must be
taken in gas wells as very short lengths of stem (or just
the rope socket and blind box) will travel very quickly.

Blind Box Size (OD) to suit ID of tubing and OD of rope socket.

(i) Minimum size determined by the distance from the

tubing wall to completely cover the wire diameter.

( ii ) Maximum size determined by fluid bypass round the

blind box and by the nipple ID's.

Problems: The cutter bar may cut against the X-over, tubing
hanger, or side pocket mandrel. Not assured of
successfully cutting at the rope socket. The cutter bar
can pick-up the top of the wire and ball it up.

Alternative Running Options

1) Run the cutter bar on an SB pulling tool pinned with an

aluminium shear pin (or even a wooded pencil). Lower the
toolstring below the calculated top of wire and `jerk' the
toolstring to the shear pin, then drop the cutter.

2) Run the blind box directly on the bottom of the toolstring and
run down to the rope socket, then `box off by downward
jarring.

Caution: Use a weak rope socket knot with this option to permit
the toolstring to be left behind if the upward movement
picks up the loose end of the wire.

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To calculate the minimum diameter blind box to ensure cutting of the wire the following
information is required:

Line Diameter : d

Tubing ID : Td

Rope socket diameter* : D

* Check body v’s fishing neck diameter.

The following formula determines blind

box dia (BBd):

BBd = Td – D/2 + d/2

The worst possible case should be

assumed with the Toolstring laying
against one wall of the tubing.

Warning: Blind box diameter must be

large enough to prevent the
cutter bar from passing the
side of the toolstring.

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WS-316-F GO-DEVIL

The Go-Devil is similar in appearance to the stem. It is available in 1 '/2" and 1 7/8"
sizes, in lengths from 18" to 60" (5'). It has a slot milled along its length and a filler plate
which is held in position with roll pins, leaving a hole in the centre to run smoothly down
the wire.

There are 2 major types of go-devil:

1) Bevelled Go-Devil is used to slide down wire and cut at the rope socket by a
`slicing' action.

Length is determined by well content.

Long in heavy oil.
Short in light fluid.
This tool is not recommended in gas.
Ensure the diameter is sufficient to prevent the go-devil wedging alongside the
toolstring.

2) Flat Bottomed used to:

(i) Trip a Flopetrol cutter and Kinley.

( ii ) Provide a cutting base on sand / wire.
( iii ) Add weight to the toolstring to jar down.
( iv ) Assist the toolstring back into the tubing (past the muleshoe).

Note: When assembling the go-devil above the BOP or tree connection, pack the
quick union with rags to prevent pieces being dropped inside.

Cutter Type Flat Bottom Type

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WS-316-G FLOPETROL CUTTER

The Flopetrol Cutter is a highly effective method of cutting the wire close to the rope
socket, and returning to the surface attached to the cut end of the wire. By changing
the components, it can cut all sizes of slickline and braided line up to 1/4" diameter.

Operation

1) The interface version is more common. It is dropped first, then followed by a flat
bottomed go-devil (as for Kinley).
2) When the go-devil strikes the hammer, the impact force slides the rotating knife
against the stationary knife.
3) When the knife rotates, it cuts the wire, bends the end of the wire, and drives the
tapered wedge upwards. The action of bending and gripping the wire holds the
wire cutter and go-devil above it, onto the wire.
4) It is ESSENTIAL that the slots are assembled facing in opposite directions, or
the wire will not be cut.

Advantages

1) Will not cut at interface or restriction in the tubing.

2) Cutter and go-devil recovered with the wire.
3) Clean cut, close to the rope socket.
4) Can be used in oil or gas (vary the length of go-devil).

Note : With all cutters and go-devils dropped down the well, the following
precautions should be observed:

1) ALWAYS COVER THE HOLE WHEN ASSEMBLING THE TOOL ON THE WIRE.
2) CHECK the tool l tubing sizes to ensure the tools cannot bypass the wedge.
3) Pull a light bind on the wire during dropping l cutting (equal to the jars open
weight).
4) Depending on fluid - allow approximately one minute per 300 m for the cutter to
drop.

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WS-316-H KINLEY SNEPPER

The Kinley Snepper is assembled on the wire above the BOP. All pieces are split to
enable assembly around the wire.

This `upside down' version is used to prevent cutting on the fluid level at restrictions
and side pocket mandrels.

A flat bottomed go-devil is dropped to strike the top cap plunger. This causes the `knife'
to slide the `slipper' sideways, which slices the wire.

Go-devil and kinley snepper are usually recovered in separate runs.

CHECK the OD's of the go-devil, cutter, and toolstring, to ensure they cannot bypass or
become wedged in the tubing ID.

Remember: Cover the hole when assembling to prevent pieces falling down
the well.

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WS-316-I SIDEWALL CUTTER

The Sidewall Cutter is designed to run

down the well beside the broken wire and
cut against the tubing wall.

This tool can be run on a shear down tool

(SB) or on a 'C' running tool. The cutters
have a shear pin which prevent them
expanding prematurely.

Cut wire must be recovered before any

attempt is made to pull this cutter as the
loose end of the wire would bail up
ABOVE the cutter.

When running, it is advisable to use a

rope socket knot with only 1 '/2" wraps. It
is possible for the cut end of the wire to
become entangled in the toolstring, and
the use of this `weak' rope socket knot will
allow the toolstring to be left behind.

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WS-316-J WIRE FINDERS

It is important to estimate the approximate depth of the broken wire to have a

STARTING POINT to look for the wire. It is very easy to bypass the end with the wire
finder, especially if the broken end is tucked in a collar recess, nipple bore, SSD etc.
For this reason we must continue to search either side of the calculated depth. It is not
good practice to continue running in the hole past the top of the wire.

The main types of wire finders are shown in this section.

Wire Scratcher Description

A Wire Scratcher can be fabricated by passing the
wire through holes in a bar (or old piece of stem or
sucker rod) until loops form a `snug' fit in the
tubing size in which fishing is to be performed.

This type of wire finder can be used in any tubing

at any depth. Nipple profiles / SSD's cause no
problems.

However exercise caution near the side pocket

mandrels, as a loop of wire can get caught around
the latch.

If the wire finder threaded with wire fails to locate

the top of the line, it can be `baited' with a piece of
rope. By weaving a 1 to 2 m length of 1/2" to 3/4"
diameter rope through the wire, the chances of
the finder bypassing the top of the wire are
reduced.

Operation

All designs of wire finder should be run in the well

to approximately 50 m above the estimated wire
depth. Run slowly past the expected wire top to
10 m below the wire depth, while carefully
observing the weight indicator for a drop in the
weight. Pick-up and continue covering this area
until the wire is located. If not, continue running in
with 10m increments repeating up and down
passes until top of wire is located. Do not go too
deep.

Line Location

When the weight is lost indicating the wire finder has located the end of the line, jar
down gently to make a ball of approximately 3' to 6' (1 to 2 m) ONLY. Excessive jarring
and / or downward movement will make too large a ball, which can cause a problem.
The aim is to loop the wire over sufficiently to permit a wire grab to become entangled.
Too large a ball will make it difficult to extract the wire grab and wire ball from the
lubricator and / or get the BOP closed and sealing.

NOTE: Always install a rope socket on the wirefinder and run it on a RB pulling tool
made up to a tool string with tubular jars instead of spang jars.

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WS-316-K BOWEN WIRE FINDER

The Bowen Wire Finder has a

flexible spring steel skirt which is
available in a range of sizes to
suit the tubing size (ID). The
fingers of the skirt can be flexed
gently to a `snug' fit in the tubing.

Limitations

If the wire is below a nipple, care

must be taken not to jar down
against he nipple ID as it is
possible to bend or break the
fingers of the skirt. It can be
difficult / impossible to
successfully pass a nipple
profile.

Therefore if the top of the wire is

expected / calculated to be below
a nipple profile, the use of this
tool hould be carefully
considered.

Operation

As the tool is lowered

downwards, the skirt rides
upwards. The fingers press
against the tubing wall and are
designed to locate the top of the
wire, then direct it up inside the
finder.

As the toolstring is picked up the

internal taper is designed to grip
the wire, but in practice this
rarely occurs.

However, this tool is an efficient

method of finding the top of the
wire.

NOTE: Always install a rope socket and run the wire finder latched into a RB pulling
tool made up to a toolstring with tubular jars incorporated.

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WS-316-L PETROLINE COLLAPSABLE WIRE FINDER

The petroline Collapsable Wire Finder is

designed to run through a nipple without the
finger catching in the profile

The housing is selected to match the nipple

profile and the collapsable finder is run into the
well. Several housings are available to suit the
various nipples in use.

The housing is fitted over the expanding finder

and shear pinned in place. As the finder is run
into the well, the housing will stop in the nipple
bore.

Downward jarrings shears the pin and allows the

finder to be lower out the bottom end and past
the profile.

The toolstring is then lowered to the calculated

or expected top of the wire. After making a small
loop or ball at the top of the broken line, the
finder is retrieved.

As the finder passes back up through the nipple

profile, the housing is collected and the complete
assembly is returned to the surface.

NOTE: Always install a rope socket and run the finder on a RB pulling tool made up to
a tool string with tubular jars instead of spring jars.

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WS-316-M WIRE FINDER – SLOTTED BODY

The B.D.K. Wireline Finder is used to collect and ball up broken

wire or cable downhole prior to running the Wireline Grab for
retrieval.

NOTE: Always install a rope socket and run the wire finder on a RB pulling tool made
up to a tool string with tubular jars instead of spang jars.

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WS-316-N WIRE FINDER GRAB

Description

The B.D.K. Wireline Finder Grab is used in the same way as the standard wireline
grab to retrieve broken wireline from the well bore. However, by using a skirt with the
grab, the chances of passing the top of the broken wire line are reduced.

NOTE: Always install a rope socket and run the Wire Finder Grab on a RB pulling tool
attached to a tool string with tubular jars instead of spring jars.

Maintenance

It is recommended that the Wireline Finder Grab is thoroughly checked for any signs of
wear or corrosion after each operation.

Disassembly

1) Unscrew Grub screws (2) from Skirt (3)

2) Unscrew Skirt (3) from Top Sub (1)
3) Unscrew Grub screws (4) from Body (5)
4) Unscrew Body (5) from Top Sub (1)
5) The Wireline Finder Grab is now ready for inspection.

Assembly

1) Screw Top Sub (1) into Body (5)

2) Install Grub screws (4) into Body (5)
3) Screw Skirt (3) onto Top Sub (1)
4) Install Grub screws (2) into Skirt (3)
5) The Wireline Finder Grab is now ready for use.
ITEM DESCRIPTION BDK PART NO BDK PART NO BDK PART NO QTY
1 TOP SUB (THREAD CONNECTION) 12268-01-A3 12269-01-A3 12270-01-A4 1
TOP SUB (QRJ CONNECTION) 12268-01-B3 12269-01-B3 12270-01-B4
TOP SUB (HD QRJ CONNECTION) 12268-01-C3 12269-01-C3 12270-01-C4
TOP SUB (THINITY CONNECTION) 12268-01-T3 12269-01-T3 12270-01-T4
2 GRUBSCREW G010NF018 G250NF025 G250NF025 1
3 RETRIEVER SKIRT 12268-02 12203-03-2250 12270-02 1
4 GRUBSCREW G010NF018 G010NF018 G250NF025 2
5 BODY 02107-1500-3 12003-02 02108-2000-3 1

GRAB O.D. 1.50” 1.75” 2.00”

SKIRT O.D. 1.80” 2.25” 2.70”
NUMBER OF PRONGS 3 3 3
MAKE-UP LENGTH 15.56” 15.72” 22.50”
ASSEMBLY NUMBER 12268-1800-1500-3-XX 12269-2250-1750-3-XX 12270-2700-2000-3-XX

Explanation of assembly number

e.g. Part Number – Skirt O.D. – Prong O.D. – Number of Prongs – Connection Code

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WS-316-O WIRE GRAB

The Wireline Grab is used to retrieve broken

wireline from the wellbore after making a small
`ball' with a wire finder.

When a wireline breaks and a considerable

length of it is left in the wellbore, the upper
section of the line tends to coil and conform to
the ID of the wellbore creating friction or
resistance which prevents the entire length of
the line from dropping.

Important When attempting to retrieve the

wireline, it is imperative that the
top of the wire first be located and
balled with a wire finder before
running the wireline grab.

If this is not done, the wire grab may miss the

top of the wireline and bypass several feet of
wire before engaging it. Once this happens,
the wireline that is above the grab will tend to
`stack' around the grab as it is being retrieved
and, if more than a few feet of line has been
bypassed, it will foul the grab to the extent that
it cannot be retrieved short of further fishing
operations.

Caution ALWAYS RUN ATTACHED TO A

ROPE SOCKET and latch into an
RB (or equivalent) pulling tool. If
the grab becomes entangled and
cannot be retrieved, the RB can
be sheared and the toolstring
returned to the surface.

Wire grabs come with 2, 3 or 4 prongs,

depending on the size of the tubing being
fished in, condition and position of fish and
preference of the wireline operator carrying
out the fishing operation.

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WS-316-P WIRE CENTRE SPEAR

The Centre Spear is not recommended for general

wire fishing operations.

It is made by welding barbs on a pointed rod,

staggered around the outside and vertically. This tool
can be very difficult to move up the tubing should it be
run too far below the end of the line and become
engaged in the wire. The wire above it will ball up and
become tighter as it is jarred up the tubing until it is
impossible to move it. It cannot be released from its
bite once the wire is wrapped around it.

About the only time this tool should be used is in a

case where the wire is balled up so badly that it is
impossible to get hold of it with a two prong grab. The
pointed spear can sometimes be driven into such a ball
and break off a small piece at a time until the ball has
been loosened enough to be able to move it up the
tubing. In this case, it is recommended that the two
prong grab then be used, since it will come nearer to
straightening out the wire making it easier to pull.

This tool should also be run with a rope socket, and

latched into an RB in case it becomes entangled.

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WS-316-Q WIRELINE GRAB - EXPANDABLE

The B.D.K. Expandable Wire Grab is generally run after the

Wirefinder. The spring loaded prongs of the Grab continually
run against the tubing wall ensuring that the wireline will
entangle inside the prongs of the Grab.

The advantage of this Grab over the more conventional tool is

that the Grab will not pass through the centre of the wire coils if
the line has not been balled correctly using the Wirefinder. Also
will pass through restricted internal diameters of nipples etc.
and then expanding into larger internal diameters further
downhole.

Manufactured with a central box thread so a centre spear can

be attached if required.

NOTE: Always install a rope socket and run the Expandable

Grab on a RB pulling tool made up to a toolstring with tubular
jars instead of spang jars.

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WS-316-R UNIVERSAL BELL GUIDE AND SKIRT

The B.D.K. Universal Bell Guide is designed as an

alternative to the use of Bell Skirts. These guides
eliminate the need to thread the Pulling Tool or
Overshot body and offer the versatility to interchange
the size of the centralising Bell Guide efficiently.

Nominal Size Thread Fish Neck Item Description

Pulling Tool no.
2.000” 15/16” – 10 1.375” 1 Cylinder
2 Top Sub
3 3.5” Skirt
4 5.5” Skirt
2.500” 15/16” – 10 1.375” 1 Cylinder
2 Top Sub
3 3.5” Skirt
4 5.5” Skirt
3.000” 1 1/16” – 10 2.312” 1 Cylinder
2 Top Sub
3 3.5” Skirt
4 5.5” Skirt

The B.D.K. Bell Skirt is attached by a O.D. of Skirt

compatible thread machined on the 2.500”
Pulling Tool / Overshot and is 3.000”
3.500”
designed to centralise and guide the
4.000”
fishing neck of flow control device into 4.500”
the body of the Pulling Tool or
Overshot

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WS-316-S BOWEN AND O’BANNON OVERSHOTS

Overshots are used to grip downhole tools when:

( i ) The fishing neck is worn or broken.

( ii ) There is no fishing neck (e.g. on the Bowen jar body).
( iii ) When a larger upward force is required than could be pulled on standard pulling
tools.
( iv ) Upward jar action only is required.

The main types of overshot are:

1) O'Bannon.
2) Flopetrol Releasing Overshot..
3) Bowen.
4) BDK Overshot

The principle of all overshots is the same. A set of hardened steel slips, with sharp
upward facing teeth, grip the `fish'. A spring assists these slips to engage initially.
However, the upward pull and upward jarring set the slips tighter because of the
tapered ID in the skirt. This moves upwards against a matching taper on the slips,
increasing the `grip' force.

Bowen O'Bannon and BDK overshots cannot be released once they are latched, so
they must be run attached to a rope socket. This is latched into a shear down tool (SB)
so that the overshot may be released and the toolstring returned to the surface to tie a
new rope knot, redress hydraulic jars, or add a stem etc.

The slips are available in a range of sizes. Choose the slips required and CHECK BY
LATCHING THE SAME SIZED OBJECT ON THE SURFACE prior to running.

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O’BANNON BOWEN

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O’BANNON OVERSHOT

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WS-316-T BDK WIRELINE OVERSHOT

Desceiption

The BDK Wireline Overshots are designed for use when wear and other mechanical
damage prevents the engagement of a regular pulling tool. A Wireline Overshot is
designed to engage equipment of a specific diameter, although a given size tool may
be used to engage a range of diameters, simply by installing the appropriate size of
slips.

Operation

The Overshot operates by sitting down the toolstring weight onto the fish, this will allow
the slips to expand around the fish. When the toolstring is picked up the slips will
engage the fish.

PLEASE NOTE: There is no release system to this type of Overshot, therefore

install a rope socket and latch the overshot into an SB pulling tool
made up to a standard tool string

Maintenance

It is recommended to inspect the tool thoroughly after each operation. If Slips are left
inside the tool after maintenance then it is also recommended to tag the tool with the
slip range.

Disassembly

1) Remove the Grub Screw (5) and back off the Top Sub (1) from the Cylinder (2).
2) Remove the Spring (4), Slips (6) and Retainer Ring (3) from the Cylinder.
3) The Overshot is now ready for inspection.

Assembly

1) Assemble the Slip Segments (6) around the Retainer Ring (3) and install into the
Cylinder (2).
2) Place the Spring (6) into the Cylinder (2) and ensure that it seats correctly onto
the Slips.
3) Make up the Top Sub (1) and install the Grub Screw (5).
4) The Overshot is now ready for use.

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ITEM DESCRIPTION QTY

1 TOP SUB 1
2 CYLINDER 1
3 RETAINER RING 1
4 SPRING 1
5 GRUBSCREW (NOT REQUIRED FOR 1.40” DIA) 1
6 SLIP TAPERED 1 SET
SLIP TAPERED

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WS-316-U FLOPETROL RELEASABLE OVERSHOT

The Flopetrol Releasing Overshot will retract the slips and release the fish by jarring
down. It has a wide range of slips from 1/2" to 2 7/8", to fit 2 different sizes of
overshots.

Operation

1) Prior to Running Check - Steel shear pin.

- Correct slip size.
- Correct core extension (long or short).

2) Latching The slips move upwards and slide over the fish until the
core extension hits the top of the fish.
The spring then pushes the slips tighter.

3) Pulling An upward pull sets the slips tighter.

The upward jar force is transmitted through the skirt and
slips.
No tendency to shear the pin.

4) Shearing The downward jar action forces the core upwards

against the spring.
(Considerable jarring is sometimes required).
Once the pin is sheared, the 2 pawls hold the core in the
upward position which keeps the slips retracted.

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WS-316-V PERTOLINE HEAVY DUTY RELEASABLE OVERSHOT

The Petroline Heavy-Duty Releasable Overshot has been designed to withstand the
high jarring forces created during heavy-duty fishing operations.

The overshot can be released by downward jarring, which shears the pin and engages
the internal split collet with the top sub of the slip assembly.

Upward jarring then pulls the slips free of the fish, so that the overshot and toolstring
can be recovered.

The core is available in various lengths to provide at least 1/4" of downward movement
once the slips are latched.

Lengths available are 0.787" reach.

1.287" reach.
4.685" reach.

The overshot is available in 2 '/2" and 3" sizes with a range of slip mandrels available in
the following sizes:

2 ½” 3 ½”
To fish Part # To Fish Part #
(inches) (inches)
0.56 – 0.72 440-2500-30-11 1.40 – 1.56 440-2750-30-11
0.70 – 0.83 440-2500-31-11 1.56 – 1.72 440-2750-31-11
0.82 – 0.95 440-2500-32-11 1.72 – 1.88 440-2750-32-11
0.93 – 1.06 440-2500-33-11 1.87 – 2.03 440-2750-33-11
1.04 – 1.18 440-2500-34-11
1.16 – 1.29 440-2500-35-11
1.28 – 1.41 440-2500-36-11
1.39 – 1.53 440-2500-37-11
1.51 – 1.64 440-2500-38-11
1.63 – 1.75 440-2500-39-11
It is essential to correctly select the core and slip sizes.

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WS-316-W BULLDOG OR CENTRE SPEARS

Bulldog or Centre Spears are an internal version of the overshot utilising hardened,
expanding slips to grip inside the `fish' which is to be recovered.

They can be used in a wide range of application such as when an internal fishing neck
is damaged or worn, or to recover any items with a smooth internal bore.

The 2 designs shown here have no shear release option, and therefore should be run
attached to a rope socket which is latched into a downward shearing tool such as an
SB.

This permits extensive upward jarring, but allows recovery of the toolstring by
downward jarring if the fish cannot be recovered.

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This Bulldog Spear has a one slip element which moves up and down a tapered slide.
When the spear is lowered into the fish, the slips will move towards the top of the tool
(flush with OD of the tool).When picking up the tool string, the slip element will stay
stationary in relation to the upward movement of the tool. This causes the taper to force
the slip element outwards ( the OD of the tool becomes larger) and get a good internal
grip of the fish.

Note: This spear is also non releasable, so run it on a rope socket and pulling tool.

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WS-316-X WIRELINE RELEASABLE SPEAR

Description

The BDK Self Releasing Internal Spear is a fishing tool designed for downhole flow
control devices that have damaged fishing necks.

Maintenance

It is recommended that after each operation the tool is disassembled, cleaned and
checked for any signs of wear, damage or corrosion.

Operation

The tool is run to depth and the sprung Collet retracts to allow entry into the fish.
Upward jarring ca then be used to free the fish. To release from the fish, downward
jarring will shear the pin and activate the release mode.

Disassembly After Pin Has Been Sheared

1) Remove Grubscrew (2) from Top Sub (1). Unscrew Top Sub (1) from Mandrel
(3).
2) Remove Grubscrew (7) from Bottom Sub (12). Remove Retainer Ring (5) from
Upper housing (4) and any Shear Pin fragments (6). Unscrew Upper Housing (4)
from Bottom Sub (12).
3) Slide Upper Housing (4) off Mandrel (3) and remove any remaining Shear Pin (6)
material.
4) Remove Springs (8 & 11).
5) Position Mandrel (3) so Grubscrews (10) can be accessed through holes in
Bottom Sub (12).
6) Remove Grubscrews (10) from Spring Retainer (9), slide retainer off Mandrel (3).
7) Slide Mandrel (3) off Collet (13).
8) Slide Bottom Sub (12) towards and over Collet (13).
9) Slide Collet (13) off Mandrel (3).
10) The tool is now ready for cleaning and inspection.

Assembly

1) Slide Bottom Sub (12) over Collet (13).

2) Insert Mandrel (3) into Collet (13).
3) Install Grubscrews (10) part way into Spring Retainer (9), Slide Spring Retainer
(9) over Mandrel (3) and position over groove. Tighten Grubscrews (10) through
Holes in Bottom Sub (12).
NOTE: Some large Collets will not pass through Bottom Sub when already
installed on Mandrel.
4) Slide Springs (8 & 11) over Mandrel (3).
5) Screw Upper Housing (4) into Bottom Sub (12) and install Grubscrew (7).
6) Screw Top Sub (1) onto Mandrel (3) and install Grubscrew (2).
7) Pull Top Sub (1) away from Upper Housing (4) and insert Shear Pin (6).
8) Install Retainer Ring (5) onto Upper Housing (4).
9) The tool is now ready for use.

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ITEM DESCRIPTION BDK PART NO QTY FOR H2S PAT NUMBER,

1 TOP SUB – 1 1/16”-10 un - .75” NECK 10544 – A4 1
ADD ‘H’ SUFIX TO STANDARD PART NUMBER
TOP SUB – QRJ 10544 – B4
TOP SUB – HD QRJ 10544 – C4
TOP SUB – TRINITY 10544 – T4 REDRESS IT P/No: 10543-RD

* 2
3
GRUBSCREW
MANDREL – STANDARD REACH
G25DNF075
10547
1
1
CONSISTING OF * ITEMS

MANDREL – TYPE ‘X’ LOCK MANDREL REACH 10547 –02

MANDREL – 6” REACH 10547-03 Spear Type Connection Assembly No. Safe
MANDREL – 8” REACH 10550 Working
Load
4 UPPER HOUSING 10546 1
Standard Reach Thread ½”–10 LHS 10543-01-A4 52,370 lbs
* 5
6
RETAINER RING
SHEAR PIN
10545
10879
1
1
1.75” Fish Neck
QRJ 10543-01-B4
7 GRUBSCREW G250NF025 1
* 8
9
MANDREL SPRING
SPRING RETAINER
10620
10580
1
1
HD QRJ
Trinity
10543-01-C4
10543-01-T4
2.75”/2.81” Type Thread ½”–10 LHS 10543-02-A4 46,470 lbs
* 10
11
GRUBSCREW
COLLET SPRING
G250NF025
10621
2
1
‘X’ Lock
Mandrel reach
1.70 Fish Neck
QRJ 10543-02-B4
12 BOTTOM SUB 10548 1 13”(S) HD QRJ 10543-02-C4
COLLET – STANDARD REACH – 1.63” – 1.75” 10549-01
Trinity 10543-02-T4
COLLET – STANDARD REACH – 1.75” – 1.88” 10549-02
6” Reach Thread ½”–10 LHS 10543-03-A4 62,370 lbs
COLLET – STANDARD REACH – 1.88” – 2.00” 10549-03 1.75” Fish Neck
COLLET – STANDARD REACH – 2.00” – 2.13” 10549-04 QRJ 10543-03-B4
COLLET – STANDARD REACH – 2.13” – 2.25” 10549-05 HD QRJ 10543-03-C4
COLLET – STANDARD REACH – 2.25” – 2.38” 10549-06
AS REQUIRED

Trinity 10543-03-T4
COLLET – STANDARD REACH – 2.38” – 2.50” 10549-07 8” Reach Thread ½”–10 LHS 10543-04-A4 62,370 lbs
COLLET – TYPE “x” LOCK MANDREL – 2.31” – 2.52” 10549-08 1.70 Fish Neck
13
COLLET – 6” REACH – 1.63” – 1.75” 10540-09 QRJ 10543-04-B4
COLLET – 8” REACH – 1.63” – 1.75” 10551-01 HD QRJ 10543-04-C4
COLLET – 8” REACH – 1.75” – 1.88” 10551-02 Trinity 10543-04-T4
COLLET – 8” REACH – 1.88” – 2.00” 10551-03
COLLET – 8“ REACH – 2.00” – 2.13” 10551-04
COLLET – 8” REACH – 2.13” – 2.25” 10551-05
COLLET – 8” REACH – 2.13’ – 2.25” 10551-06
COLLET – 8” REACH – 2.13” – 2.25” 10551-07

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WS-316-Y BDK INTERNAL FISHING TOOL WITH TAPERED MANDREL

The B.D.K. Internal Fishing Tool, tapered mandrel type, is

designed to retrieve downhole devices by locating in bore
when the exact internal diameter cannot be determined due
to damage, “wash out” or wear. The tapered mandrel allows
expansion of collet to contact bore. The tool is run using the
upper fishing neck.
Downward jarring will set the Retrieving Collet and shear the
Running Tool. The Pulling Tool is then run in, latching the
inner fishing neck. Upward jarring sets the tool and retrieves
the Lock. To release from the Lock a reverse of the
procedure will allow full retrieval of the Fishing Tool. Can also
be used for retrieval of tools with damaged internal fishing
neck.
An alternative Pulling Neck is available should be external
Fishing Neck be preferred.

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WS-316-Z BDK INTERNAL FISHING TOOL WITH PARALLEL MANDREL

The B.D.K. Internal Fishing Tool, parallel mandrel type, is designed

to remove downhole flow control devices with damaged internal
fishing neck. The tool (excluding the mandrel) is run using the upper
fishing neck, downward jarring will set the retrieving collet and shear
the running tool. The mandrel is then run in using the fishing neck,
downward jarring when in position shears the running tool. The
pulling tool is then run in latching the upper fishing neck, upward
jarring sets the tool and retrieves the lock. To release from the lock
a reverse of the procedure will allow full retrieval of the Fishing Tool.

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WS-319-ZA ALLIGATOR GRAB

Description

The BDK Alligator Grab is a fishing tool designed to retrieve debris from within the
well bore. The Alligator Grab which has a built in adjustment feature, can be set to grab
the fish with varying pressure. The tool is operated with a shear down trigger system.

The Grab is designed to withstand heavy jarring situations.

Maintenance

As the Alligator Grab can be subject to heavy jarring it is recommended to completely

disassemble the Grab after each operation. It is recommended to thoroughly check all
parts for any signs of wear or corrosion.

Disassembly

1) Remove the Retaining Screw (5) from the Spring Adjuster (4).
2) Back off the Spring Adjuster (4) to release tension on the Spring (6).
3) Unscrew both Shear Pin Retainers (8) and remove the Shear Pin (9) using a
Punch.
4) Remove the Retaining Grub Screw (2) from the Top Sub (1).
5) Remove the Top Sub (1), unscrew the Spring Adjuster (4) & remove the Spring
(6).
6) Remove the Pivot Screw (11) and withdraw the Mandrel (3) from the Body (7).
7) Remove the Pivot Pin (10), which will separate the Jaws (12).
8) The Alligator Grab is now fully disassembled.

Assembly

1) Before assembly inspect all parts and replace any that are damaged or worn. '
2) Position both Jaws (12) together, insert Pivot Pin (10) place the assembly in the
Mandrel and insert the Pivot Screw (11).
3) Slide the Mandrel (3) into the Body (7) ensuring the Pivot Pin (10) remains in
place.
4) Insert the Shear Pin (8) and Shear Pin Retainers (9).
5) Slide the Spring (6) over the Mandrel (3).
6) Screw on the Spring Adjuster (4) until it makes up against the Spring. Ensure the
Spring is correctly located on both Spigots.
7) Screw on and tighten the Top Sub (1) and lock the Grub Screw (2).
8) Screw down the Spring Adjuster (4) to set the Jaws (12) to the required force and
align and lock the Grub Screw (5) in the slot.
9) The BDK Alligator Grab is now ready for use.

Note: Never use the Alligator grab to latch onto a large object when the overall
outside diameter (grab and fish latched) is larger than the internal diameter of
the nipples ,x-overs or other restrictions to pass when pulling to surface.

Note: Always install a rope socket and run the Alligator Grab on a RB or SB pulling
tool depending on type and condition of fish to be recovered.

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WS-316-ZB ACCELERATOR

These stretch simulators, or Accelerators, are made by Petroline

and BDK

They are installed in the toolstring, immediately below the rope

socket, when upstroke jars are to be used to create optimum upward
jarring.

The spring `stacks' in the Petroline jars can be matched to the spring
jar setting.

Accelerators are also a recommended addition to the toolstring at

shallow depths, i.e. less than 300 m. The spring replaces the `stretch'
of the wireline which exists when jarring deep.

They reduce the shock loading at the rope socket and cause the
stem to `accelerate' faster when the hydraulic jars go off. This
creates a more effective impact.

There are still some “old style” accelerators in use in BSP, which
instead of a disc springs stack have a coil spring installed. (see page
2)

The operating principle is the same however.

Specification
2 ½” Petroline Accelarator Sub
Item Description Qty. Part Number
Assembly 402-2125-00
01 Fishing Neck 1 402-2125-01-11
02 Spring Rod 1 402-2125-02-11
03 Main Housing 1 402-2125-03-11
04 Bottom Sub 1 402-2125-04-11
05 Nut 1 402-2125-05-11
06 End Piece 1 402-2125-06-11
07 Disc Spring * DS-010
* DS-012
08 Grub Screw 1 GS-002
09 Roll Pin 1 RP-004
10 Roll Pin 1 RP-004
11 Roll Pin 1 RP005
* Dependent on set up
Maximum O.D. 2 1/8”
Overall Length 53”
Fishing Neck 1 ¾”
Connecting Threads 1 1/16” - 10

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The B.D.K. Wireline Accelerator is used in conjunction with

hydraulic or spring jars when jarring at shallow depths. The
wireline accelerator assembly is run just below the Rope Socket
of the toolstring, upward tension on the wireline compresses the
spring within the accelerator sub, and the stored energy is
transferred to the hydraulic or spring jars located lower down the
toolstring.
A combination of wireline tension and spring tension within the
accelerator will cause the hydraulic or spring jar to fire, thus
releasing totally, which in turn increases the impact at the fish.

Item Description Part Number

1 Top Sub 01103-01-A3 01105-01-A4 01106-01-A4 01107-01-A6
2 Pin 01103-02 01105-02 01106-02 01107-02
3 Body 01103-03 01105-03 01106-03 01107-03
4 Piston 01103-04 01105-04 01106-04 01107-04
5 Spring 01103-05 01105-05 01106-05 01107-05
6 Pin 01103-06 01105-06 01106-06 01107-06
7 Bottom Sub 01103-04-A3 01105-07-A4 01106-07-A4 01107-07-A6
Assembly Number 01103-00-A3 01105-00-A4 01106-00-A4 01107-00-A6

Petroline Accelerator Sub.

Additional Techincal Specification

As outlined in the attached brochure for maximum efficiency of the accelerator it has to
be matched to the toolstring, namely the jar, in use.

Refer to figure 1.

This graph shows the basic deflection due to load of an accelerator with standard disc
spring set up. The deflection is therefore the usable accelerator stroke which should be
greater than the stroke of the jar in use.

The standard spring set up is as follows:

159 sets in singles of 1.25 thick Disc Springs.

18 sets in singles of 1.75 thick Disc Springs.
354 total Disc Springs.

Note: The 18 sets of 1.75 thick are normally positioned at the top of the Accelerator
Sub.

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Refer to figure 2.

Figure 2 diagramatically shows the Disc Spring configurations of singles, doubles and
triples.

High Load Accelerators.

In the past we have supplied Upstroke Jars and accelerators set for 3000 lbs
activation. The Disc Springs in the Upstroke Jar are set in triples. The accelerator Sub
to compliment this is set up as follows:

10 sets in triples of 1.75 thick Disc Springs.

21 sets in doubles of 1.75 thick Disc Springs.
111 sets in singles of 1.75 thick Disc Springs.
366 Total Disc Springs.

Note: The Sub is normally furnished with triples, doubles then singles positioned
respectively from top to bottom of Sub.

STROKE - INCH

25

24

23

22

21

20

19

18

17

16

15

14

500 750 1000 1250 1500 1750 2000

LOAD – LBS
GRAPH 1 GRAPH 2

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WS-316-ZC BDK HEAVY DUTY ACCELERATOR

Description

The BDK Heavy Duty Wireline Accelerator Jar is used in conjunction with hydraulic or
spring jars when jarring at shallow depths. The Wireline accelerator assembly is run
just below the Rope Socket of the toolstring, upward tension on the wireline
compresses the springs within the accelerator sub, and the stored energy is transferred
to the hydraulic or spring jars located lower down the toolstring. A combination of
wireline tension and spring tension within the accelerator will cause the hydraulic or
spring jar to fire, thus releasing totally the energy stored within the springs, which in
turn increases the impact at the fish.

Disassembly

1) Remove retainer Grub Screw (11) from Top Cap (3) and back off Top Cap from
Slide Body (4).
2) Remove the inner assembly Slide Stem, Belleville Springs, Top Cap and Top Sub
(5,8,9,3, and 1-2)
3) Remove retainer Grub Screw (11) from and Bottom Sub (6-7).
4) Remove retaining Grub Screw (10) and unscrew Top Sub (1-2). Slide off Top
Cap (3) and remove all Belleville Springs.
5) The Accelerator is now ready for inspection.

Important: It is recommended to use a light lubricant during assembly

Assembly

1) Clean and inspect all parts for wear or damage.

2) Assemble the Hard Belleville Spring Stack as shown, onto the Slide Stem (5).

Important: Check that the hard belleville springs are loaded correctly as shown
before assembling the soft bellevilles (See chart for the correct number).

3) Repeat the same for the Soft Belleville Stack.

4) Slide over the Top Cap (3) and screw on Top Sub (1-2) and insert retaining Grub
Screw (10).
5) Slide the made up assembly into the Slide Body (4) and make up.
6) Insert the retaining Top Cap Grub Screw (11).
7) Attach the Bottom Sub (6) and insert Grub screw (11).
8) The Heavy Duty Accelerator is now ready for use.

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WS-316-ZD CENTRALISER

Fluted Centraliser – Slip Over

The B.D.K. Fluted Centraliser is available to fit all Stems, Cutters and
Go-Devils. These are essential to centralise the tools in deviated
wells. The centraliser is locked inposition on the body of the tool by
use of grubscrews.
A grubscrew locating groove in the body of the tool is recommended
to eliminate any possible movement of the Centraliser.

Fluted Centraliser – Stepped

The B.D.K. Fluted Centraliser is available to fit Stems, Cutters and

Go_devils with grooves machined into the body. The Centraliser is
machined in two halves and then clamped to the above tools locating
the step in the groove on the body. This type of centraliser eliminates
the possible shearing action of screws associated with the Split
Centraliser.

Wireline Fluted Centraliser

The B.D.K. Wireline Fluted Centraliser is a

device run in the wireline toolstring to
centralise the toolstring where the well
deviation causes the running and pulling
tools to lay off centre.

Spring Centraliser 2” – 4”

Item Qty Description

1 1 Top Sub
2 2 Securing Pin
3 2 Washer
4 8 Screw
5 2 Spring Mounting Bush
6 8 Washer
7 4 Spring
8 1 Mandrel
9 1 Bottom Sub

The B.D.K. Spring Centraliser is designed to run in the wireline

toolstring to assist in centralising the string inside large bore tubing.
They are normally used in the tollstring when running pressure and
temperature gauges. Its helps centralise and reduce shocks
transmitted to the gauges during runing operations. Also will retain
centralisation through large and small internal diameter tubing within
the same well bore.
Spring Centralisers for use in larger size tubing or casing are available
on request.

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WS-316-ZE MAGNET

The Magnetic Fishing Tool is designed to remove small pieces of ferrous metals from
the top of tools in the well.

This tool does not have a hole through it for fluid bypass as
do other tools. The magnet is fitted with a sleeve on the
outside, and a spring which compresses the sleeve to keep it
below the end of the magnet. Upon reaching the depth of the
fish, the operator sets the toolstring down gently on top of
the fish.

The weight of the toolstring then forces the magnet down

inside the sleeve to pick-up small pieces of wire, or ferrous
metals that might be lying on top or around the fish.

This is to be retrieved from the well slowly, so as not to lose

the particles that have been retrieved.

Magnets will also retrieve metallic scale.

Note: A soft iron ‘keeper’ plate should be kept on the face

of the magnet while not in use to preserve the
magnetism

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WS-316-ZF SWANGING TOOL

A Swaging Tool is used to restore light collapse in the tubing

string.
It canals be used to restore “egg shaped fishing necks on
damaged X-locks and flow tubes of lock mandrels where
expander mandrel and fishing neck were ripped off and flow
tube deformed anfter unsuccessfull latching operations.

NOTE: Always run a Swaging Tool with a rope socket

installed on a RB pulling tool.

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WS-316-ZG TUBING END LOCATOR

Used to locate the end of the tubing at the time of the completion as a cross reference
check of the tubing tally. Also used to correlate the tag sand depth accurately from the
bottom of the tubing (depth known from completion records).

Usually has 2 positions for the `finger', so that it can be used in 2 3/8"
and 27/8", or 3 '/2" and 4 '/2" tubing.

Take care pulling the tubing end locator up into the lubricator.

After the tubing end locator passes out the bottom of the tubing
spring, the loaded `finger' trips to the horizontal position. Pick-up to
obtain the tubing end depth.

The jar up action shears the 1/16" brass pin below the `finger' and
allows the tool to be removed.

Caution: Run the gauge cutter first to ensure the tubing is clear.
If the tubing end locator has to be pulled up with the
`finger' in the running position, it may catch in the
tubing or collar. The continued upward movement in
this situation will shear the pivot pin and drop the
`finger' and spring. In some cases the `finger' has
damaged or punctured the tubing.

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WS-316-ZH WIRELINE BRUSH

The B.D.K. Wireline Brush is used to Brush out waxes, scale and other
Debris from the tubing string or Landing nipples prior to running Down
hole flow control devices. A Wire size of up to 3/16” is looped (or Cut to
suitable lengths) and inserted in holes and retained with locking screws.
(Wire not supplied)

NOTE: Always install a rope socket and run the Wireline Brush on
a RB pulling tool.

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WS-316-ZI WIELINE TUBING DRIFT AND DRIFT CUTTER

Design Principle

The wireline drifts are designed for running down in a tubing string immediately upon
completion or in some cases before the BOP drilling stack is removed to establish
whether or not there are any obstructions in the ID of the tubing.

Operating Principle

In the BSP Group these drifts must be run on a RB pulling tool. The OD of the drifts is
just a few thousands of an inch smaller than the ID of any selective landing nipple.

No-Go type landing nipples will not allow certain size drifts to pass through. After
getting the drift tool down to the No-Go nipple and back out of the well the operator
knows that the assemblies necessary to complete the well can be run and retrieved.

The 2.890" (73 mm) drift is run to the S-4 nipple for assurance that the SOF valve can
be run through the tubing above the S-4 nipple.

Note: Always run a gauge cutter / drift cutter with a rope socket installed and on an
RB pulling tool.

Drift Body

Pony Rod

Drift Body

Pony Rod

Drift Body

The Drift Cutter is the BSP version of a gauge cutter. It is longer and the
cutting edge on the bottom has been rounded off facilitating smooth passage through
nipple profiles and sleeves in SSD.s because it lost its cutting edge, it should not be
used to cut wax or remove scale.

The Tubing Drift as shown in the right picture, is used as a “dummy gun” prior to
perforating. It consists of three drift elements connected by “pony “sucker rods of 2 - 4
or 6ft long . Dummy guns in the larger sizes will get quite heavy, but still need to be run
on a RB pulling tool. In the event of getting stuck in a tight spot, it offers the choice to
release from the drift by upward jarring, rather than jarring down on a SB to shear the
pin and jamming the drift even tighter.

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WS-316-ZJ WIRE SCRATCHER

A Wire Scratcher provides a means to clean the ID of the tubing,

nipple profiles, and SSD's etc.
It is run on a standard toolstring, and run up and down to clean the
affected area.

It is most commonly made from an old piece of stem or sucker rod

drilled and tapped, as shown, to accept pieces of braided line cut in
lengths to suit the well diameter.

A variation of this tool, threaded with slickline in a long continuous

loop, can be used to locate the top of broken wire.

It has also been used succesfuly been used in fishing out

small pieces of broken wire which could not be fished
with a regular wiregrab.

NOTE: Always install a rope socket and run the Scratcher on a RB

pulling tool.

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CHAPTER 17
BRAIDED LINE OPERATIONS
TABLE OF CONTENTS

WS-317-A INTRODUCTION TO BRAIDED LINE OPERATIONS....................................2

WS-317-B GREASE INJECTION CONTROL HEAD .....................................................10
WS-317-C WIPER HEAD ................................................................................................13
WS-317-D BRAIDED LINE ROPE SOCKET ..................................................................15
WS-317-E BRAIDED LINE SWIVEL ...............................................................................16
WS-317-F ELMAR GREASE INJECTION MODULE L-69574 .......................................17

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WS-317-A INTRODUCTION TO BRAIDED LINE OPERATIONS

Multi strand wireline is used for `heavy' fishing jobs and swabbing operations. Because
of the additional forces created by the well pressure acting on the larger
cross-sectional area, a well is sometimes killed before the fishing job is attempted. The
most common size of wire used is 3/16", with use of 1/4" and 5/16" for heavy duty
applications.

3/16” Line

The conventional 3/16" cable comprises 16 (9 + 6 + 1) strands. The core and right lay
inner wires are thinner than the left lay outer wires. By using right and left lay, the
twisting tendency of the wire under load is prevented.

Dyform

A few years ago a British ropes subsidiary introduced Dyform cable. Around the
single centre core are 9 thinner right lay wires, the outer wires are also right lay but
thicker. The finished cable is pulled through a die, and by doing this the following
improvements are made:

(i) 20° increase in breaking load, because there is more steel in the same
diameter.
Maximum breaking - 6300 lbs (2800 DaN)
Working load - 4800 lbs (2133 DaN)
( ii ) Smooth external periphery and closer tolerance of OD, reducing leakage at the
stuffing box.
( iii ) Higher crush resistance because of the increased steel content of the cable.
( iv ) Low twist tendency because of the Dyform process.
(v) Smaller `interstitial' spaces use less grease from the grease injection
sealing system.

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Recommended
Max. 80% Working Weight per 100
Breaking Load Load metres
Size (ins) Material (kgs) (lbs) (kgs) (lbs) (kgs) (lbs)
Galvanised Carbon Steel 2,250 4,960 1,800 3,970 10.77 23.7
Dyform Carbon Steel 2,800 6,174 2,240 4,940 12.70 28.0
3
/16 316 Stainless 1,810 3,990 1,448 3,193 10.60 23.4
18/18/2 Stainless 1,850 4,080 1,480 3,263 10.60 23.4
Nitronic - 50 Alloy (Nickel) 1,950 4,300 1,560 3,440 10.60 23.4
Carbon Steel 3,000 6,615 2,400 5,292 14.30 31.5
Dyform Carbon Steel 3,700 8,158 2,960 6,527 17.70 39.0
7
/32 316 Stainless 2,400 5,292 1,920 4,234 14.30 31.5
18/18/2 Stainless 2,500 5,512 2,000 4,410 14.30 31.5
Nitronic - 50 Alloy (Nickel) 2,700 5,954 2,160 4,763 14.30 31.5
Carbon Steel 3,920 8,644 3,136 6,915 18.70 41.2
Dyform Carbon Steel 5,080 11,201 4,064 8,961 22.00 48.5
1
/4 316 Stainless 3,120 6,880 2,496 5,504 18.70 41.2
18/18/2 Stainless 3,200 7,056 2,560 5,645 18.70 41.2
Nitronic - 50 Alloy (Nickel) 3,560 7,850 2,848 6,280 18.70 41.2
Carbon Steel 6,120 13,495 4,896 10,796 29.20 64.4
Dyform Carbon Steel 7,960 17,550 6,368 14,041 34.50 76.0
5
/16 316 Stainless 4,800 10,584 3,840 8,467 29.20 64.4
18/18/2 Stainless 5,000 11,025 4,000 8,820 29.20 64.4
Nitronic - 50 Alloy (Nickel) 5,500 12,128 4,400 9,702 29.00 64.4

General Equipment Requirement for Braided Line Operation

The following is a list of equipment that is required for braided line

operations.
1) Wireline Heavy Duty Power Pack: With bases, extra fuel and water if the engine
is liquid cooled.
2) Heavy Duty Reel Skid: With a generous amount of line. Chains and binders to
anchor reel skid. Weight indicator (Martin Decker 4000 lbs) with proper hay
pulley.
3) Lubricator Tray: With sufficient sections of the lubricator to compensate for size of
tools and pressure expected. Two or more BOPs. Stuffing box-line wiper with a
hydraulic packing nut or a grease injector head, depending on whatever the
pressure demands. Xmas tree connection, riser, guy lines, rope, binders and
lubricator clamp.
4) Wireline Equipment Tool Box: Fishing tools.
5) Mast Unit: crane, platform crane.
6) Hand Tool Box.
7) Grease Injector Unit: Supply of grease.
8) Air Compressor.

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Grease Injection Unit Operation

The grease injection unit is air-operated. It is very important that a dependable and
generous supply of air is available the whole time that work is being performed in a
well. The grease container must be full before starting a trip in a well. .

Adjust the air regulator valves to the container and the high pressure pump to 340-550
kPa. Fill the grease supply hose to evacuate the air. Attach the high pressure grease
supply hose to the control head. Connect the flow hose and the packing nut hose to
the control head also.

Raise the lubricator up and install it on the BOP stack. Increase the regulator air
pressure to the high pressure pump and build up the grease pressure to 700-3500 kPa
above the closed-in tubing head pressure. This pressure will vary depending on the
wear ID of the flow tubes, the OD of the braided line and the operating line speed. The
line speed should not be more than 60 m/min. Ninety percent of the operation of the
grease injection unit will be controlled by the regulator.

On a dual BOP with the top rams inverted, the unit should be tested prior to rig up and
function checked once the manifold has been rigged up. A non-return valve should be
positioned in the port between the rams for grease to be injected if the rams have to be
closed and a seal achieved.

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Nominal Line Size Use of Range of Actual Average Line Maximum Tube ID Including Wear
Inches (mm) Size Do Not Use When Creater
Inches (mm) Inches (mm)
0.124 - 0.125 (3.15 - 3.18) 0.134 (3.40)
1/8 (32)
0.127 - 0.129 (3.23 - 3.28) 0.137 (3.48)
0.174 - 0.176 (4.42 - 4.47) 0.184 (4.67)
0.177 - 0.180 (4.50 - 4.57) 0.187 (4.75)
3/16 (48) 0.181 - 0.183 (4.60 - 4.65) 0.191 (4.85)
0.184 - 0.186 (4.67 - 4.72) 0.194 (4.93)
0.188 - 0.190 (4.78 - 4.83) 0.198 (5.03)
0.192 - 0.193 (4.88 - 4.90) 0.202 (5.13)
0.194 - 0.196 (4.93 - 4.99) 0.204 (5.18)
0.195 - 0.198 (4.95 - 5.03) 0.205 (5.21)
0.199 - 0.201 (5.05 - 5.11) 0.209 (5.31)
0.201 - 0.205 (5.11 - 5.21) 0.211 (5.36)
0.206 - 0.208 (5.23 - 5.28) 0.216 (5.49)
7/32 (56)
0.211 - 0.213 (5.36 - 5.41) 0.221 (5.61)
0.214 - 0.216 (5.44 - 5.49) 0.224 (5.69)
0.216 - 0.219 (5.49 - 5.56) 0.226 (5.74)
0.219 - 0.221 (5.56 - 5.61) 0.229 (5.82)
0.222 - 0.225 (5.64 - 5.72) 0.232 (5.89)
0.224 - 0.228 (5.69 - 5.79) 0.234 (5.94)
0.227 - 0.229 (5.77 - 5.82) 0.237 (6.02)
0.231 - 0.233 (5.87 - 5.92) 0.241 (6.12)
1/4 (64)
0.242 - 0.245 (6.15 - 6.22) 0.252 (6.40)
0.251 - 0.253 (6.38 - 6.43) 0.256 (6.50)
0.262 - 0.264 (6.65 - 6.71) 0.274 (6.96)
9/32 (71) 0.290 - 0.292 (7.37 - 7.42) 0.302 (7.67)
0.300 - 0.303 (7.62 - 7.70) 0.312 (7.92)
0.307 - 0.309 (7.80 - 7.85) 0.319 (8.10)
0.310 - 0.312 (7.87 - 7.92) 0.322 (8.18)
0.311 - 0.313 (7.90 - 7.95) 0.323 (8.2)
5/16 (79) 0.315 - 0.318 (8.00 - 8.08) 0.327 (8.31)
0.321 - 0.323 (8.15 - 8.20) 0.333 (8.46)
0.327 - 0.329 (8.31 - 8.36) 0.339 (8.61)
0.332 - 0.334 (8.43 - 8.48) 0.344 (8.74)
0.360 - 0.363 (9.14 - 9.22) 0.375 (9.45)
3/8 (95) 0.368 - 0.370 (9.35 - 9.40) 0.380 (9.65)
0.379 - 0.381 (9.63 - 9.68) 0.391 (9.93)
0.394 - 0.396 (10.00 - 10.06) 0.406 (10.30)
0.398 - 0.401 (10.11 - 10.19) 0.410 (10.41)
0.406 - 0.408 (10.31 - 10.36) 0.418 (10.62)
7/16 (111)
0.410 - 0.413 (10.41 - 10.49) 0.422 (10.72)
0.417 - 0.420 (10.59 - 10.67) 0.429 (10.90)
0.425 - 0.430 (10.80 - 10.92) 0.437 (11.10)
15/32 (119) 0.462 - 0.464 (11.73 - 11.79) 0.477 (12.12)
17/32 (135) 0.524 - 0.526 (13.31 - 13.36) 0.539 (13.69)
Note that the main sizes in use are 3/16", 7/32" 1/4" ND 5/16"
Table 9.3.1 – Grease/oil Injection Control Head, Flow Tube Selection and Wear Data

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Control Head Rig Up and Operation

Assembly Procedure

1) Pass the braided line through the following parts in sequence

2) Packing nut with the seals installed.
3) Piston with the seals, non-extrusion ring and seal protector ring in place.
4) Piston return spring.
5) Control head body with the lower brass interlocking seat, line rubber, upper brass
bushing, flow tube and flow tube sleeve seals in place.
6) First flow tube and flow tube sleeve.
7) Flow tube sleeve coupling with flow tube and flow tube sleeve seals in place.
8) Second flow tube and flow tube sleeve.
9) Flow tube sleeve coupling with flow tube and flow tube sleeve seals in place.
10) If any additional flow tubes are required, assemble them as number one and two
were assembled.
11) Quick union nut.
12) Bottom sub with the flow tube and flow tube sleeve seals in place.
13) Tighten all the connections between the bottom sub and the control head body.
14) Connect the flow hose to the control body. Connect the valve and nozzle to the
other end of the flow hose.
15) Connect the check valve and elbow in the lower flow tube sleeve coupling.
16) Connect the high pressure grease supply hose into the bottom of the check
valve.
17) Hook up the hydraulic hand pump hose to the upper threaded part in the
hydraulic packing nut body.
18) Insert the work string into the top of the lubricator.
19) Make up the rope socket to the work string and tighten.

Caution: Do not turn the rope socket in the making up process. Using a knuckle
joint with a 600 mm weight bar between the rope socket and knuckle joint
turn the work string in the lubricator. Ensure that the check valve is in
place and the correct way round.

20) Pick up tools into the lubricator and make up the control head to the lubricator.
21) Raise the lubricator with the crane for land operations. Use scaffolding for
offshore operations.

Operating Procedure

1) Locate the grease supply system skid near the Xmas tree.
2) Unreel the grease supply hose, flow hose and hand pump hose and make sure
they will all reach from the supply skid to the control head after it is in position on
the BOP.

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Tool String Selection Procedure

When selecting the tool string for braided line operation, it is very important that the
largest OD tools possible be used. A shear up tool should be tried first. If
unsuccessful then a shear down tool should be run.

CAUTION: 5.5-7 KG ADDITIONAL WEIGHT MUST BE ADDED.

CAUTION: THE AMOUNT OF LUBRICATOR NECESSARY TO HOUSE HEAVY

FISHING TOOL STRINGS AND FISH SHOULD ALWAYS BE BORNE IN
MIND.

Braided Line Care and Handling .

The overall life of braided line begins from the moment it is received from the supplier.
The shipping reel full of line must not be dropped when loading off. The reels of braided
line must be stored in a weather protected dry store room.

Taking the line off the shipping reel onto the work reel can be accomplished two ways.
The first is to take the braided line off the shipping reel onto a stranded line unit with
just enough tension to make a flat layering on the reel possible. Then using the first unit
as a tensioning device pull the line onto the regular double drum unit at the proper
tension.

The second is to take the braided line from the shipping reel and over two tension
drums with 10 or 12 grooves and braking mechanism. The line is wrapped around the
tension drums and onto the regular unit. Braking is applied to the outer surface of the
tensioning drums while a small amount of drag is applied to the shipping reel to prevent
over running of the line. A Martin Decker weight indicator can be rigged to indicate the
line pull being applied to the core layer. The core layer should be spooled at 10-15% of
the breaking strength of the line. The second layer at approximately 15-20% of the
breaking strength. The third layer tension should be increased to approximately
20-25% of breaking strength. This tension is maintained until approximately half of the
cable length is spooled onto the reel. The tension can then be reduced for every 300 m
of the cable spooled on.

When using the braided line on a job do not wrap the line around the counter wheel.
Hay pulley and stuffing box sheave should have the correct size groove. Hydraulic or
tension jars should be used in the work string. In the event of fishing use jar down to
release pulling tools with low shear value shear pins. Do not over-tighten the stuffing
box line wiper because of bird caging effects. When using a grease injector control
head the braided line should not be run in the hole or pulled out faster than 60 m/ min.
The reason for this rate is that the injector pumping unit might not be able to supply
enough grease to the control head to maintain a seal. Another reason is that the
braided line is easier to stop if the line climbs over itself or jumps a wrap or two. It is
also easier to .flat wrap braided line.

Measuring the OD and inspecting the line with the reel stopped every 300 m is also a
very good practice. At the time of shut down a good coating of oil or inhibitor helps
protect the line from deterioration. A piece of tarpaulin or heavy sacking wrapped
around the drum aids in weather protection.

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Braided Line Running In Procedure

A lot more care and observance must be used when running in braided line. Due to its
flexibility it is easier for the line to jump the sheave at the hay pulley. This usually
occurs when the tool string hits the fluid level, sits down in a side pocket mandrel or
hits an obstruction down hole. Jumping a sheave can damage some of the strands
enough so that they could break while running in and out of the hole. The operator
should always keep the counter head in front of the wraps coming off from the drum.
Do not exceed 50 % pull of the breaking strength of the line. Ensure that the weight
indicator sheave is supported to avoid the sheave falling on its side when tools sit
down.

Braided Line Jarring Operation

When a braided line is being used in an operation it is normally because the solid
0.092" and 0.108" wires are not capable of performing the required work. Usually when
the braided line is in use there is some heavy upward jarring involved.

The wireline supervisor should make certain that hydraulic or tension jars are utilised in
the work string. If the jarring is taking place at less than 600m depth, a jar accelerator
should be included between the rope socket and weight bars.

The operator should also keep in mind that the need to be able to get off from a fishing
neck will have to be carried out by jarring down. Due to the ratios used in the
transmission and drive reduction to the reel, plus the weight of the mass in the
stranded line drum the reversing action of the unit will be slower and longer. So pulling
tools that shear down to release should have shear pins that can be sheared with a
minimum of strain to the hydraulic system and the unit.

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WS-317-B GREASE INJECTION CONTROL HEAD

The Grease Injection Control Head is required to obtain a seal when using braided
line for heavy-duty operations such as swabbing or fishing.

Principle of Operation

Grease is injected at a pressure higher than the well pressure (approximately 20%
higher). The grease fills the interstitial grooves between the braided line strands. The
most critical component of the grease injection head are the `flow tubes'. These should
be approximately 0.010" ID larger than the measure OD of the line. The seal is
achieved by the pressure drop created across the small gap between the line and flow
tubes.

A wiper box on top of the grease injection head retains a large percentage of the
grease.

Ancillary Equipment

The following equipment is required to operate the grease injection system:

• Compressor*.
• Grease reservoir.
• Grease pump*.
• Connection hoses.
• Dual BOP system.
* Backup systems essential in high pressure situations.

Use

The following factors will effect the volume of grease required:

• Clearance between the flow tubes and line.
• Temperature.
• Well pressure.
• Line speed.
• Line size.
• Grease viscosity.

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GREASE SUPPLY

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WS-317-C WIPER HEAD

The Wiper Head, or line pack-off, was originally developed for swabbing operations
where relatively low pressures are encountered. Pack-offs are now available for use up
to 5,000 psi.

The most common design contains a split rubber element which is compressed
hydraulically to seal' against the line. Other designs are available that utilise an
hydraulic `bladder' which squeezes around the line.

Pack-offs are also used in conjunction with grease injection control heads to retain as
much of the grease as possible and act as the final low pressure seal.

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WS-317-D BRAIDED LINE ROPE SOCKET

There are 2 types of slip - the overload

release type and the plain.

The overload type is designed to cause the line

to break under severe loading at a specific
percentage of the full strength of the line. Five
breaking strength slips are available for 50%,
60%, 70%, 80%, and 90% of line strength.

The plain type is designed much the same as

the overload type, except that it does not have
the overload release feature. Experience
indicates that the line will usually break near the
top end of these slips at approximately 90% of
the breaking strength of the line.

Always use a swivel between this rope socket

and the stem to provide the rotating action.
Toolstrings tend to twist as you run in the hole
and if a swivel is not used, this rotation is
transferred to the wire causing additional strain
and the potential to unwrap or open up the
braided wire strands.

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WS-317-E BRAIDED LINE SWIVEL

The Swivel is designed with a bearing to permit the easy rotation of the toolstring, even
under loads as tools move in / out of the well.

It is essential to use a swivel between the rope

socket and stem to prevent twisting of the line in
the following toostrings:

(i) When using a `no-knot' type rope socket, as

this design does not allow the internal
rotation of the components.

( ii ) When using a braided line rope socket, a

swivel prevents the tool rotation being
transferred to the line. Twisting force on
braided line can cause the braid to unwrap
or open up, which can lead to a broken
strand or jamming in the flow tubes.

The sideways movement of a swivel varys from 1

'/2° to 5°, (depending on the manufacturer) so it is
not as suitable as a knuckle joint which has 15° of
movement.

In the event of a line brake, the swivel will keep

the rope socket fishing neck near straight and
make latching possible. If a knuckle joint has been
used in place of a swivel, it allows the rope socket
to `fall over' making latching difficult. Knuckle
joints are not designed to rotate under load.

Swivels and knuckle joints are not

interchangeable.

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WS-317-F ELMAR GREASE INJECTION MODULE L-69574

Section 1 Safety

SAFETY IS EVERYONE'S RESPONSIBILITY

CAUTION - read service manual before operating

- observe all safety precautions
- this system is capable of producing high pressure to avoid component
rupture and possible injury regulate inlet air pressure so outlet
pressure does not exceed the maximum working pressure of any
component in the set up
- check pressure rating and compatibility of all connections
- clear area of unnecessary personnel
- select proper equipment
- mare sure valves and regulators are in correct position
- Do not try to tighten or loosen connections under pressure do not
weld, file or use metal stamps on the pressure equipment - these can
start cracks
- Do not overtighten any valves (hand tight only)
- Do not attach anything to this equipment unless you are sure of its
pressure rating
- Watch for trapped pressure.
bleed off fully before breaking down unions etc.

General

The Elmar Grease Injection Module L-69574 can supply grease at pressures up to
20,000 psi for injection into the flow tubes and between BOPs. Grease return from the
flow tubes, via the module, to an external drainage point is also provided for.

Features And Specifications

• 2 air driven WIWA 235:1 ratio grease pumps mounted on a 90 gallon grease
tank.
• Grease supply to the flow tubes via 120 ft lengths of hose.
• Grease supply to BOP via 70 ft length of hose. '
• 120 ft long grease return hose.
• Grease injection hoses are J" ID minimum burst pressure 52,000 psi.
• 3/4" ID 100 RlAT air hose, 60 ft long
• Built in hose reels allowing easy rewind
• Modern stainless steel mimic control panel.
• Aluminium storage cupboard.

Description Of Components

The frame of the module is fabricated from 50 x 50 mild steel hollow section. Four
lifting eyes are fitted and the lifting slings provided have a SWL of 2 tons. A PVC cover
is supplied for protection.
The hoses are stored on four 7" wide and one 5" wide single port reels.
Two grease pumps and a partly split grease tank are provided for redundancy.

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Physical Characteristics

The Elmar Grease Injection Module - L-69574.

Overall Dimensions:

Length = 1.37 m
Height = 1.30 m
Width = 0.98 m

Approximate weight:- 660 kg.

Item Part no Qty Description Item Part no Qty Description

1 91948 1 Double Rewind Mechanism Assy. 9 90522 1 Grease To Bop. Reel Assemly
2 90037 1 Double Rewind Mechanism Assy. 10 90523 1 Upper Grease Inject. Reel Assy.
3 90038 1 Single Rewind Mechanism Assy. 11 90524 1 Lower Grease inject. Reel Assy.
4 90517 1 Control Panel Assembly 12 90525 1 Grease Return Reel assembly
5 90518 1 Grease Pumps & Tank Top Assy. * 90515 - General Arrangement
6 90519 1 Air Line Filter Assembly * 90516 - Control Panel - Front Layout
7 90520 1 Frame Assembly * 90526 - Reel Assembly Layout
8 90521 1 Air Reel Assembly * 90527 - Schematic Diagram
* - Additional Drawings Supplied

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Item Part no Qty Description Item Part no Qty Description

1 L-60557 1 Storage Cupboard 17 L-81370 4 Hex Set
2 L-61300 1 Label - Caution Do Not ETC. 18 L-81410 10 Washer - Plain
3 L-61309 1 Label - Grease to BOP 19 L-81420 10 Washer - Spring
4 L-61310 2 Label - Grease to FlowTubes 20 L-81430 10 Hex Set
5 L-61311 1 Label - Grease Return 21 L-81610 4 Washer - Plain
6 L-61316 1 Label - Air Supply 22 L-81660 4 Nut
7 L-61953 1 Panel Cover Plate - Upper 23 L-82026 1 Hinge - 880mm
8 L-61954 1 Panel Cover Plate - Lower 24 L-82061 2 Anti - Luce Fastener
9 L-61955 1 Base Cover Plate 25 L-82093 1 Handle
10 L-61956 1 Top Cover Plate 26 L-82190 2 Handle
11 L-62195 1 Frame 27 L-82250 4 Anti - Luce Fastener
12 L-63000 1 Crank Handle 28 L-82412 12 Rivets
13 L-81022 2 Nut 29 L-86030 1 Chains & Shackles
14 L-81050 32 P.H. Screw 30 L-86310 1 Decal
15 L-81101 16 Nut 31 L-86571 1 PVC Cover
16 L-81300 6 Washer - Plain 32 - - -

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General Check Before Operation

Walk around the module and check:

• Grease hose ends are tightened onto blank plugs.
• Grease tank levels by removing tank caps.
• Airline filter drained.
• Lubricator topped up with suitable lubricant.
• All air valves are OFF.

Pressure Test Procedure

NOTE: Do not rotate reels with pressure in the hoses. This will reduce '0' ring seal life.

Grease Inject System Check

• Unspool grease hoses before pressure testing

• Connect the air reel to the rig air supply
• Turn grease pump air regulators fully anticlockwise
• Close all grease valves
• Turn the main air supply valve on
• Open Pump No: 1 grease inject valve (on right of pump No: 1 pressure gauge).
• Turn Pump No: 1 air regulator clockwise. Pump will start to stroke as it pressures
up the grease injection line. Keep adjusting until 20,000 psi is reached on the
gauge. Check for leaks behind panel, at hose reel centre and at hose end.
• If the air valve is turned OFF the pressure will reduce slowly as it leaks back
through the pump tube.
• Open crossover valve - the pressure should now register on Pump No: 2 gauge
also.
• Open Pump No: 2 grease inject valve (on left of pump No: 2 pressure gauge).
Check for leaks.
• Turn ON Pump No: 2 air valve.
• Turn Pump No: 2 air regulator to reach 20,000 psi. Check for leaks.
• Turn main air supply valve OFF.
• Open grease dump valves to release pressure.
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Drain Line Check

• Disconnect the drain hose and one grease inject hose from the fixed blanking
plug.
• Connect the drain hose to the inject hose.
• Open drain valve.
• Pump grease through drain hose until it comes out of the drain point. Use a
length of hose to direct the waste fluids to a convenient disposal point.
• Close drain valve, pump up to 20,000 psi and check for leaks.
• Close air valve and open grease dump valve.
• If possible test the drain: line with water to avoid filling it with thick oil.

Wellsite Operation

RIG UP

• Place the skid with reels facing the rig.

• Connect hoses to pressure equipment as it is rigged up.
• One grease pump should be sufficient to run the job but remember that with the
120 ft hose the pressure losses along the grease line are high. You may have to
pump 2, 000 - 3, 000 psi above well pressure to regain a lost seal or to keep up
with excessive grease consumption if the flow tubes are worn.

DO NOT BLEED THE LUBRICATOR PRESSURE USING THE GREASE DUMP

VALVE. This dumps to the grease tank.

2. RIG DOWN

• Ensure that all pressure is released from the hoses before disconnecting and
reeling up by opening the grease dump valve.

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CHAPTER 18
TUBING RETRIEVABLE SAFETY LOCK-OUT TOOLS
AND ACCESSORIES
TABLE OF CONTENTS

WS-318-A INTRODUCTION TO TUBING RETRIEVABLE SUBSURFACE SAFETY

VALVES ..........................................................................................................2
WS-318-B HALLIBURTON LOCK OUT TOOLS AND ACCESSORIES ..........................3
WS-318-C BAKER “T” SERIES ......................................................................................15
WS-318-D CAMCO TR-SSV LOCK OPEN TOOLS AND ACCESSORIES ...................27
WS-318-E TROUBLE SHOOTING PROCEDURES FOR TR-SSV’S ............................39

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WS-318-A INTRODUCTION TO TUBING RETRIEVABLE SUBSURFACE
SAFETY VALVES

Introduction

In BSP more than a hundred wells have been completed with a TR-SSV as an integral
part of the production string. These TR-SSV,s offer great advantages over Wireline
retrievable safety valves:

1) Full bore through valve allowing high flow rates and permits running of properly
sized wireline tools.
2) Build in equalising feature (upon request)
3) Landing nipple profile cut in top sub to accommodate straddle, plug or insert
valve
4) Metal to metal seals (non elastomer ) for high pressure gas wells
5) Deep set features
6) Reduces wireline operations (i.e. Not having to pull and set SC-SSSV prior and
after an intervention)
7) Lock open feature in case of malfunctioning of the valve.
8) Permits installation of insert valve utilising the same control line for hydraulic
operating pressure.

The valves presently in use are manufactured by the following suppliers:

9) Halliburton Models: SP-1, SP-2 and Well Star.
10) Baker Models: TE-5, TSME-5, TSME-10, TSUME-5 and TME-5 deep set.
11) Camco Models: TRM-4E and TRM –4PE – CF.

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WS-318-B HALLIBURTON LOCK OUT TOOLS AND ACCESSORIES

Following are the running and pulling procedures for wireline tools used to either repair
malfunctioning valves or permanently lock them open.

Halliburton SP-1 and SP-2

Difference between SP-1 and SP-2 is the shape of the flapper which is more contoured
on the SP-2. The SP-2 also has a build in equalising feature, but the lock out features
and procedures for both type of valves are identical.

Lock-Out Tool

Design Overview

This OTIS© 'LO' Lock-Out Tool is designed to provide a means of locking open a
Tubing-Retrievable Safety Valve should the Safety Valve become inoperable. The Tool
locates in the Lock-Open Sleeve of the Safety Valve and shifts the Sleeve down to lock
the Valve open. Internal hold down slips prevent the sleeve from moving up and locks
the flow tube in the fully open position, keeping the flapper out of the flow path and
open the control line outlet, creating communication with the tubing.

Design Principle

This Tool is designed with Spring-Loaded Keys to allow them to flex when traveling
through the Tubing String. Pressure from below moves the Drop Valve off Seat and
allows fluid bypass. As the Shifting Tool enters the Lock-Open Sleeve, the 90 degree
bearing surface on the Keys contact the shoulder in the Lock-Open Sleeve and stops
the Tool String. Downward jarring shears the Shear Pin and allows the Mandrel to
move down behind the Keys. This prevents the Tool from being pushed out of the
Lock-Out Sleeve. Pressurise the control line to operating pressure for observation
purposes. With the Chevron packings sealing off in the upper seal bore, pump or gas
pressure may be applied to assist in the shifting / lock-out process. Further downward
jarring shears the plugs in the lock open sleeve wich then moves down and exposes
the communication ports for the control line outlet. At this point the contol line pressure
should have dropped and be equal to the tubing pressure. Continued downward jarring
(preferably assisted by pump pressure) will move the lock out sleeve together with the
flow tube to the total lock open position. An internal slip arrangement prevents upward
movement from either sleeve or flow tube. An appropriate tubing drift needs to be run
upon completing the lock out operation to ensure an unrestricted passage through the
valve.

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Lock-Out Tool

Find Name Qty Item No.

1 2.313 FSH
Test TL no 3.813 9 CR H2S 1.00 14NO38160
2 Extn 2¾ - 12 UN 2½ - 12 U 1.00 78D 2327
3 LK – OUT Shft F/4 ½ Non–Elasto 1.00 42 LO 10
801 ES-MM-9

Design Specifications

Type Spec Release Original

Service H2S
Size 4½
Packing OD 3.813
Fish Neck OD 2.313
OD w/keys expanded 4.09
OD w/keys retracted 3.620
Length 27.46
Bottom Thread 1-8 UNC
Used With 4½ O.D.
Nonelastomer
TRSV

Halliburton SP-1 and SP-2 Exercise Tool

The Exercise Tool is used in cases where the flapper valve

does only partially open and / or not fully close.
This can be caused by a build up of hard wax or scale on the
lower part of the exposed flowtube in the flapper housing or in
the flapper housing and the flapper itself.
The tool is run and set in a special profile cut in the flow tube
which will only match the profile of the keys on the tool. Once
the profile is located downward jarring shears the top pin (3)
and locks the keys into the profile.
As the inner mandrel moves down, shearpins (8) assisted by
leaf springs (7) will lock the assmbly in place. The TR-SSV is
then pumped open to its maximum allowable working
pressure.

Tool string weight is picked up with some over pull (300lbs) .do
not hit the jars as this could shear the locking pins (8). Keep
overpull exactly at a round figure i.e. 200, 300, or 400 lbs. As the travel from the flow
tube from fully closed to fully open is known or can be obtained from the manufacturer,
(for instance 6”), mark the wireline at a fixed point.
Now bleed off the control line pressure for the TR-SSV and notice the weight on the
weight indicator drop. Pick up the toolstring and re-apply overpull to the exact value as
before. Measure the movement of the wire which should correspond with the known
travel of the flow tube. When the measurements do not match, slack off and close jar.
Pressureup the controlline again to maximum allowable working pressure and jar down
on the tool. This might free the flow tube and remove any build up of foreign matter.
Following the jarring down, pick up tool string with same exact overpull as before, mark
wire and bleed off controlline pressure, measure movement of wire as before. In case
of improvement, repeat procedure as many times as necessary until full and free travel
of the flow tube is observed.
Retrieve Exercise Tool by jarring up and shearing the lock pins. Follow up the Exercise
operation with a tubing drift run to confirm flapper fully open . Then carry out inflow test
to confirm flapper fully closes and is holding pressure.
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EXERCISE TOOL

DESIGN SPECIFICATION

Type Spec Release ECN 230829

Service STD
Size 3.813,3.688 inches
Fish Neck OD 2.313 inches
OD w/keys expanded 4.195 inches
OD w/keys retracted 3.62 inches
Length 76.63 inches
Shr down force to set (lbs) 6212
Shr up to release per pin (lbs) BRS 1988, STL 2847
Used with 4½ series 10 flapper trsv

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Halliburton SP-2 TRSSV

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Halliburton “WellStar”

Design Overview

The Halliburton "WellStar" Tubing-Retrievable Safety Valve is a self-equalizing,

flapper-type safety valve designed to shut in a well at a point below the surface. The
safety valve is a surface controlled, subsurface safety valve (SCSSV) and is normally
closed. The valve is held open by hydraulic control pressure and remains open until the
control line pressure is exhausted. The hydraulic control pressure is transmitted from a
remote location through a control line to operate the valve.

Design Principle

The Halliburton tubing-retrievable safety valve (TRSV) contains a piston, opposed by a

compression spring and the well pressure, which operates a flapper mechanism. When
pressure is released from the piston chamber, the spring moves the piston up and the
torsion spring rotates the flapper to the "closed" position.

The valve is a self-equalizing TRSV. Opening the valve requires applying pressure to
the control line to equalize the pressure across the closure device. Once pressure has
been equalized across the flapper, hold open pressure is applied to the control line to
fully open the flapper. The valve also has a "protection" feature that will not allow it to
open unless pressure across the closure mechanism is equalized.

The TRSV is retrieved only with the tubing. The valve should not be used to regularly
shut in the well.

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WellStar TRSSV – Lock Out Procedure

Design Overview

The LOX, LOR or LOQ lock-out tool is a mechanical and hydraulic device. It provides a
means of permanently locking open a WellStarTM tubing retrievable safety valve
(TRSV) and establishing control line communication when operating conditions dictate
the necessity. The tool is installed and retrieved by using standard wireline methods.
The lock-out procedure requires only a single wireline trip. The tool locates in the top
sub of the TRSV shifts the piston to the open position and deposits an insert into the
top sub to lock the TRSV permanently open.

Design Principle

The LOX, LOR or LOQ lock-out tool is designed to run in the locating mode. It locates
and sets in the X®, R® or RQ© nipple profile in the top sub of the WellStar" tubing
retrievable safety valve. Once the lock-out tool is set, pressure is applied down the
tubing string to shear a set screw and activate the lock-out tool. A set of lugs is
extended outward and engages the piston of the TRSV Further pressuring actuates the
piston downward. When the TRSV is in the full open position, a built-in by-pass valve in
the lock-out tool is open and pressure above the TRSV starts to drop. Continuously
pumping down the tubing is not required due to a ratchet mechanism in the lock-out
tool maintains the TRSV in the open position. Downward jarring shears the set screws
and releases the core rod of the lock-out tool. Further jarring drives the insert out and
perforates the top sub. The insert remains in the top sub and maintains the TRSV in
the open position when the lock-out tool is retrieved.

Lock-Out Procedure

Caution Every effort should be made to make the WellStarTM TRSV usable before
locking it open. Once locked open, it cannot be operated again.

Lock-Out Tool Installation Procedure

Wireline tool string requirements:

TRSV size
2 in. 2½, 3½ & 4½ in.
Jar Size 1 ½ in. 1 7/8 in.
Stroke 30 in. 36 in.
Stem Size 1 ½ in. 1 7/8 in.
Length 15 ft 15 ft

1) Make a gauge run to determine the depth at the top of the TRSV This will give an
orienting point at which to work from.
2) It is recommended to run a scatcher approximately 2 ft past the orienting point.
This should clean out the profile that the lock-out tool locks into.
3) Using the packing stack on the lock-out tool, zero the depth gage at tubing
hanger.
4) Pressure up the tubing string to equalize pressure across the TRSV If the closure
mechanism is not equalized before the lock-out tool is landed, the TRSV cannot
be locked open. Continuous pumping may be required to maintain pressure
equalization across the closure mechanism.

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5) Lower the tool string slowly to approximately 10 ft above the TRSV
6) Pull up the tool string and note the pick-up weight of the tool string.
7) Lower the tool string through the TRSV until it locates the nipple profile of the
TRSV. This should be approximately 4-5 ft past the orienting point depending on
the size of the TRSV.

Note Do not lower the lock-out tool past the TRSV. Refer to the table below for the
overall length of the TRSV. If the lock-out tool does not locate the profile in the
top sub of the TRSV, abort the lock-out procedure.
Pull up to retrieve the lock-out tool.

TRSV size Overall Length

2 in. 47.1 in.
2½ in. 51.2 in
3½ in 56.3 in
4½ in 63.5 in

8) 8.Tap down lightly twice to make sure that the lock-out tool locates the nipple
profile.

Note If the lock-out tool moves down, abort the lock-out procedure. Jar up to retrieve
the lock-out tool.

9) Jar down twice to set the lock.

10) Pull a bind of 400 lb above the pick-up weight of Step 4 and hold for 5 minutes to
check if the lock-out tool is fully set in place.

Note It may be necessary to slightly crack open the flow line to prevent fluid lock in
tubing above the TRSV If the lock-out tool is unlocked, abort the lock-out procedure.
Jar up to retrieve the lock-out tool.

11) Slack off wireline tension.

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Pressure Actuation Procedure

Note Due to the small flow area of the by-pass valve built in the lock-out tool, it is
necessary to restrict the flow rate of fluid pumped into the tubing.

1) Pressure up the tubing to the lock-out pressure plus tubing pressure. Refer to the
Design Specification of the TRSV for the lock-out pressure.

Note Pressurization of the tubing will activate the actuation mechanism of the
lock-out tool. Further pressurization will move the piston of the TRSV Once
the piston of the TRSV reaches the full open position, a by-pass valve built in
the lock-out tool will open and cause a noticeable pressure drop in the tubing.

If tubing pressure above the TRSV can not be pressured up, abort the
lock-out procedure. Jar up to retrieve the lock-out tool.

2) Once a pressure drop is noticed, stop pumping into the tubing. The TRSV is now
in the open position.

3) Slowly bleed down pressure above the TRSV to the tubing pressure. The lock-out
tool holds the TRSV in the open position.

Perforation Procedure

Caution Due to the heavy weight of the stems, do not attempt to perform jarring by
hand. When opening the jar for downward jarring, pick up the tool string
slowly to prevent upward-jar ring action that may unlock the lock-out tool.

1) If possible, apply 200 psi to the control line and lock at this pressure. This
pressure will be used as an indication of communication, but it is not necessary
for lock out.

a) Jar down to shear the set screws to release the core rod of the lock-out tool.
Continue to jar down to deposit the insert of the lock-out tool into the top sub of
the TRSV Communication will be indicated by a change in the control line
pressure to tubing pressure.

b) Jar down five additional times after communication is indicated.

2. If a communication indicator is not possible, jar down as per the table below:

No. of Jarring Blows Top Sub Material

30 9Cr-1Mo, 410, 13Cr
50 Incoloy 925

3. Jar up to retrieve the lock-out tool. The TRSV is permanently locked open.

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ITEM DESCRIPTION ITEM DESCRIPTION

1. FISHING NECK 26. LUG
2. SET SCREW 27. SLEEVE
3. SLEEVE 28. SHEAR SCREW
4. ROD 29. SHIFTING HOUSING
5. SHEAR SCREW 30. CAP SCREW
6. TOB – SUB 31. VALVE STEM
7. ADAPTER MANDREL 32. PACKING RETAINER
8. ADAPTER SLEEVE 33. SEAL RING
9. GUIDE PIN 34. O – RING
10. LOCKING LUG 35. SEAT
11. CONNECTOR SUB 36. PISTON EXTENSION
12. EXPANDER SLEEVE 37. LATCH HOUSING
13. KEY RETAINER 38. RETAINER RING
14. SHEAR PIN 39. LATCH SEGMENT
15. SPRING 40. SPACER
16. CAP SCREW 41. V – PACKING
17. SPRING 42. O – RING
18. KEY 43. FEMALE PACKING ADAPTER
19. MAIN MANDREL 44. REMOVABLE SEAL SUB
20. INSERT CARRIAGE 45. PACKING MANDREL
21 SHEAR PIN 46. DOUBLE MALE PACKING ADAPTER
22. INSERT 47. V – PACKING
23. SHEAR PIN 48. V – PACKING
24. SET – SCREW 49. FEMALE PACKING ADAPTER
25. LUG – RETAINER 50. BOTTOM SUB

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WS-318-C BAKER “T” SERIES

The procedures for the Flapper Lock Open tool and Control Pressure Penetrator
Communication Tool are the same for all type “T” series valves as mentioned on page
2 of WS-318-A.

Description And Purpose

The Flapper Lock Open Tools described in this Tech Unit are used to
permanently lock open TubIng Retrievable Safety Valves. This allows
retrieval of a Dry String. Flapper Lock Open Is also used In the event of
Safety Valve malfunction. After the Safety Valve has been permanently
locked open, It may accept a Separation Sleeve or a Wlreline Retrievable
Insert Safety Valve provided communication of the control fluid to the interior
of the valve has also been accomplished.

Two wireline runs are required to permanently lock the Flapper of a Tubing
Retrievable Valve open. On the first run, the Flapper Lock Open Tool Is
landed and locked in the Nipple Profile of the Tubing Retrievable Safety
Valve. Withdrawal of the Wireline Running Tool which is attached to the Slide
Assembly portion of the Flapper Lock Open Tool actuates the Tool releasing
the Lock Ring, which retains the Flapper in the open position. A second run
retrieves the Flapper Lock Open Tool. The tool Is designed such that the
Lock Ring cannot be released into the Flapper section if the Flow Tube of the
Tubing Retrievable Safety Valve is not in the fully closed position.

Flapper Lock-Open Tool

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Running, Operating And Retrieving Procedures

Preparation On The Rig Floor

1) Refer to the lock manufacturer’s instructions for running, operating and retrieving
procedures for the lock and running tools.
2) Using a pair of calipers, check the basic o.d. and no-go dimensions of the tool.
Compare the values with the well prognosis for any incompatibility.
3) Install the Lock Ring (17) per steps 19-20 of the assembly instructions. If the lock
ring is already installed, make sure that it is retained by the Plungers (8, 19), and
that they in turn are retained by the Upper Plunger Stop (7) and End Cap (22)
screwed up against them.
4) If the lock running tool/stinger sub-assembly is not already installed in the “FLO”
tool, screw the lock running tool onto the stinger sub-assembly and install the
running tool into the lock, following the lock manufacturer’s recommended
procedures.
5) Prepare the lock for runnning following the lock manufacturer’s recommended
running procedures.
6) With a screwdriver or other similar instrument, reach through the slot in the
Mandrel (1) and push the Stinger Assembly (4, 20) downwards until it shoulders
on the Upper Spring Mandrel (9). Install the Headless Brass Machine Screw (5)
into the Upper Spring Mandrel so that it locates in the groove in the stinger.
7) Remove the steel hose clamps (if present) from the Lock Ring (17).
8) Back off the End Cap (22) from the Lower Plunger (19) until the scribe line is
visible through lower hole in lower plunger. Top of End cap (22) should be flush
with scribe line on lower spring mandrel.
9) Install Set Screws (6,21) in the Upper Plunger Stop (7) and End Cap (22).
Note: It is imperative the set screws be installed in the end cap since end cap is not
shouldered when made up.
Caution At this time, if the running tool is sheared and removed from the fishing
neck, the tool would be actuated shooting off the lock ring. It is suggested
that steps 8 and 9 be performed immediately before the tool is run to avoid
injury or loss of the lock ring.
10) Ensure that the tubing retrievable safety valve is open or that well pressure is
equalized across the flapper before proceeding.
11) Run down hole. Follow the lock manufacturer’s instructions to land the lock in the
lock profile in the tubing retrievable safety valve nipple profile.
12) If the tubing retrievable safety valve is open, bleed control line pressure to zero
psi to return the tubing retrievable safety valve flow tube to the closed position.
Note: The tubing retrievable safety valve flow tube must be in the closed position for
the flapper lock open tool to function correctly.
13) Follow the lock manufacturer's instructions to release and retrieve the running
tool from the lock.
14) Come out of the hole with the running tool and stinger assembly.
15) Run back in the hole with the appropriate pulling tool and land In the lock on the
flapper lockopen tool. Retrieve the flapper lock open tool. (See the lock
manufacturer's operating Instructions for correct pulling tool and lock retrieving
procedure).

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Misrun Operating Procedure

1) In the event of a misrun consult the lock manufacturer's running and pulling
procedures for a ' suggested course of action.
2) Drift the tubing or remove any debris that may be causing the problem.
3) Redress the flapper lock open tool and lock if necessary and rerun.

PART LIST, PRODUCT NO. 822-80-2328

Reference Drawing No. 590-171-01
Item No Description Qty Product No
1 Mandrel 1 05-72390-00
2 Slide 1 05-72389-00
3 Brass Shear Pin ¼ Dia. X 72 Lg 1 ---
4 Upper Stinger 1 05-72391-00
5 Brass Shear Screw #10-32 x 7-16 Lg. 1 WW-GFOB-0FB
6 Stainless Steel Screw ¼-20 x 3/16 Lg. 7 WW-G518-061
7 Upper Plunger Stop 1 05-72393-00
8 Upper Plunger 1 05-72394-00
9 Upper Spring Mandrel 1 05-72395-00
10 Key 4 05-67951-00
11 O-Ring 6 02-34862-2C
12 Plunger Spring 2 05-54468-00
13 Actuation Dog 3 05-61287-00
14 Stainless Steel Set Screw #6-32 x ¼ Lg. 7 WW-G506-085
15 Stainless Steel Cap Screw #10-32 x 3/16 Lg. 2 WW-G20B-060
16 Stainless Steel Set Screw # 10-32 x 1/8 Lg. 5 WW-G60B-041
17 Lock Ring 1 05-72398-00
18 Lower Spring Mandrel 1 05-72396-00
19 Lower Plunger 1 05-72397-00
20 Lower Stinger 1 05-72392-00
21 Stainless Steel Set Screw ¼ - 20 x 5/16 Lg. 2 WW-G518-0B5
22 End Cap 1 05-54325-00
23 Lock Crossover 1 05-67318-00
24 Probe Crossover 1 05-67319-00

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BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

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Description and Purpose

The Control Pressure Penetrator Communication Tool described in

this Tech Unit is used to establish control line communication to 3-1/2”
Model “Select” Tubing Retrievable Safety Valves containing the Control
Communication feature with Hallliburton ® "X"® Lock Profile.

Running, Operating and Retrieving Procedures

1) Shut-in the well at the surface and record shutin pressure.

2) Make-up a 1-1/2 OD Spang Jars with 30" Stroke. Total weight of Tool String less
Jar Down Fluid Communication Tool should be no less than 200 Ibs.

Note: Tool String weight is given as a reference for dry hole, low pressure
conditions. Tool actuation in different weight fluids and higher tubing pressure
may require additional Tool String weight.

3) Run the Control Pressure Communication Tool in and land in the Safety Valve.
4) Stroke the jars on the Wireline Work String until the Communication Tool is fully
actuated, this will be indicated by hard strokes on the jars with no movement. As
a reference, to fully actuate the Tool requires approximately 20 jar strokes in low
pressure dry well conditions.

NOTE: It is important not to use excessive jar force after the Communication Tool is
fully actuated.

5) Retrieve the Tool String from the well. The Penetrator will retract as the Tool is
pulled.
6) Check to see if control fluid communication is established by pressurizing the
Control Line, it should not hold pressure, or by observing if surface readings on
the Control Line System pressure to be equal to SITP.
7) In the event of a misrun or in the event that communication is not achieved,
redress the Tool and repeat steps 1 thru 6.

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Chapter 18, Tubing Retrievable Safety Valve Lock-Out Tools and Accessories Page 18 of 44
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PARTS LIST FOR PRODUCT NO. 822-81-2833

Refer to Drawing No. 576-540-00

Item No Product Number Qty Description Material

1 05-74328-00 1 Fishing Neck 4140-4145
2 05-71942-00 1 Belleville Washer -
3 05-76518-00 1 Guide 4140-4145
4 05-76519-00 1 Cap 4140-4145
+5 WW-GE18-0HR 3 Shear Screw Annealed ¼-20 x ½ BMS-C129
+6 WW-G518-061 2 Hex Socket Set Screw ¼-20 x 3/16 -
+7 WW-G518-0H4 4 Hex Socket Set Screw ¼ - 20- ½ -
8 05-76298-00 1 Mandrel 4140-4145
9 05-76517-00 1 Plunger 4140-4145
+10 WW-G20B-0D1 2 Socket Head Capscrew 10-32 x 3/8 -
11 05-72257-00 1 Retainer 4140-4145
+12 05-71380-00 1 Penetrator S-5 AN or CD
Tool Steel
13 05-72256-00 1 Dog 4140-4145

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BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

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Description and Purpose

The Baker FLO Tools are used to permanently lock open

tubing Retrievable Safety Valves. Once the valve is locked
open, a dry tubng string can be retrieved, a wireline
retrievable safety valve can be inserted (provide
communication has been established) or a separation
sleeve can be installed inside the valve.

General Operation

The Flapper Lock Open (FLO) tool is designed to deposit

an expanding lock ring into the flapper section of the valve
and permanently retain it in the open position. This tool is
run on wireline and lockedfety valve.

Withdrawal of the wireline tool actuates the Flapper Lock

Open tool and deposits the lock ring.

The Baker FLO tool design also prevents the release of the
lock ring unless it is located within the flapper cavity. This
feature withholds the disengagement of the ring if the flow
tube is not in the fully closed position or when the ring is
not properly located inside the flapper section.

Note: The Flapper Lock Open tool is the pictures is

equipped with a Baker Lock. All Baker valves in
BSP have an X, R or RQ nipple profile cut in the
top sub, so a cross-over sub to an Otis lock
mandrel must be used.

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NOTE: This drawing shows the Penetrator Communication Tool adapted to be set in a
Baker landing nipple profile, however as most Baker valves in BSP have a X,
R or RQ profile machined in the top sub, refer to the adapted version of this
tool on page 5 and 7 of WS-318-C.

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As no Documentation for an EXERCISE tool adapted to an Otis lock mandrel is
presently available, this DOCUMENT is included for INFORMATION only. This file will
be updated with proper documents once received from Baker.

Drawing No. 575-868-00C

Description And Purpose

The Baker Flow Tube Exercising Tool is a three trip, wireline run tool used
to mechanically move the flow tube of a surface controlled, subsurface
safety valve in the event the hydraulic control piston or the power spring
cannot overcome friction. The tool may be used to impact the flow tube
down (opening the valve) or impact the flow tube up (closure assist). Such
exercising might possibly bring a safety valve back into service when scale,
asphaltine, paraffin or other solids have seized the flow tube.

Application And Correspondence

Inquiries concerning design, manufacture and testing should be addressed

to:

Marketing Services
Baker Oil Tools
3000 N. Hemlock Circle
Broken Arrow, Oklahoma 74012
Phone: (918) 455-3000
Fax: (918) 259-2087

Compatibility Chart

A list of available Flow Tube Exercising Tools for 5-1/2" "TSM-5" Tubing
Retrievable Safety Valves containing various lock profiles is shown below:

Valve Model “TSM-5” “TSM-5” “TSM-5”

(824-89) (825-71) (824-89)
Profile “QN” “QN” “BA”
Seal Bore Size 4.578 4.578 4.56
Setting Depth 2,000 1,800 2,000
Exercising Tool 995-03-
Product No. 4504

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Operation

1) Check that brass shear screws (3) & steel Shear Screw (6) are properly installed.
2) Check that Slips are fully retracted below O.D. of the Slip Housing and O-ring
(14) is in place.
3) Attach 3" SB pulling tool to the Inner Mandrel (2).
4) Run Flow Tube Exercising Tool into the well until Shear Ring (5) no goes in "BA"
profile.
5) Jar down until the Brass Shear Screws (3) Shear and the Lower Mandrel (10)
moves down approximately 6 inches and sets the Slips into the Flow Tube I.D. It
is recommended that five licks of a three foot stem and jar are completed to fully
push the lower mandrel down, ensuring that the slips are fully set.
6) Continue to jar down to shear the "SB" Pulling Tool. Pull out of the hole.
7) Run into the hole with a 4" type "GS" Pulling Tool and latch into the upper profile
of the Outer Mandrel (1). Jar up or down depending on the direction of flow tube
movement desired. After flow tube exercising is complete, shear the "GS" Pulling
Tool by jarring down and pull out of the hole.
8) Run into the hole with the 3" "SB" Pulling Tool and latch onto the Inner Fishing
Neck. Jar upwards to unset the
9) dogs and pull out of the hole.

Disassembly Instructions

1) Remove Set Screws from Slip Housing and End Cap (7,12).
2) Remove End Cap (13) and Slip Housing (9). Remove Slips (11) and O-ring (14)
from the Slip Housing.
3) Remove Set Screw (7) and slide Shear Ring (5) off Outer Mandrel (1).
4) Slide Outer Mandrel off Inner Mandrel.
5) Remove Set Screws (4) from Inner Mandrels.
6) Dismantle Outer Mandrel (2), Inner Mandrel Extension (8), and Lower Mandrel
(10).

Assembly Instructions

Prior to assembly be sure the parts are free from burrs and that dogs move freely in the
windows. Check all threads for burrs and roughness.
1) Assemble Inner Mandrel, Extension and Lower Mandrel (2,8,10). Install Set
Screws (4).
2) Slide Shear Ring (5) onto Outer Mandrel (1) and Install Shear Screws and Set
Screw (6,7).
3) Screw Slip Housing (9) onto Outer Mandrel (1).
4) Install 4 Slips (11) into Slip Housing ( 9).
5) Slide Inner Mandrel, Extension, and Lower Mandrel into Outer Mandrel and Slip
Housing.
6) Attach End Cap (13) to Lower Mandrel (10).
7) Install Shear Screws (3), Set Screws (7,12), and O-ring (14).

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Engineering Data
Product No. 995-03-4503 995-03-4504
Running Tool 811-45-3050
Pulling Tool 811-45-3050
Exercising Tool 811-42-3685
Ref. Eng. Dwg. No 575-868-00 575-868-01

Item no Decription No. Req’d Production Number

Production Number 995-034503 995-03-4504
1 Brass HdLs. Set Screw ¼ - 20NC x 5/8 Lg. 8 WW-GE18-0MB
2 Hex Had Socket Set Screw ¼ - 20NC x ¼ Lg. 6 WW-G518-080
3 Ann Stl. HdIs. Set Screw ¼ - 20NC x ½ Lg 16 WW-GE18-0HR
4 Hex Head Socket Set Screw ¼-20NC x 3/8 Lg. 4 WW-G518-0D0
5 Hex Head Socket Set Screw ¼ - 20NC x ½ Lg. 3 WW-G518-0H0
6 O-Ring 1 WW-B238-H40
Spare Parts Kit Product Number 05-75868-50

No. Description Qty Product No. Dimensions

- Product Number 995-03-4503 995-03-4504 *4.650 For Product No. 995-03-4503
*4.635 For Product No. 995-03-4504
1 Outer Mandrel 1 05-75865-00 05-75979-00
+54.87 For product no. 995-03-4503
2 Inner Mandrel Top Sub 1 06-03092-00 +59.87 For product no. 995-03-4504
3 Brass Hdls. Set Screw(1/4-20NC x 5/8 Lg.) 8 WW-GE18-0MB #60.50 For product no. 995-03-4503
4 Hex Head Socket Set Screw ¼-20NC x ¼ Lg 6 WW-G18-080 #65.50 For product no. 995-03-4504

5 No-Go Shear Ring 1 05-06835-00 05-75981-00

6 Ann. Stl.Hdls. Set Screw ¼ - 20NC x ½ Lg. 16 WW-GE18-0HR
7 Hex Head Socket Set Scr. ¼-20NC x 3/8 Lg 4 WW-G518-0D0
8 Inner Mandrel Extension 1 05-75866-00 0575980-00 Lower Inner Interference (total)
9 Slip Housing 1 06-06838-00 Mandrel OD Slip to flow tude ID
10A Lower Inner Mandrel 1 08-93254-00 2.530/2.535 0.050 / 0.080
10B Lower Inner Mandrel 1 08-93254-01 2.500/2.505 0.020 / 0.050
10C Lower Inner Mandrel 1 08-93254-02 2.480/2.485 0.000 / 0.030
10D Lower Inner Mandrel 1 08-93254-03 2.540/2.545 0.060 / 0.090
10E Lower Inner Mandrel 1 08-93254-04 2.550/2.555 0.070 / 0.100
11 Slip (set of 4) 1 06-06837-00
12 Hex Head Socket Set Screw ¼-20NC x ½ Lg. 3 WW-G518-0H0
13 End Cap 1 06-06839-00
14 O-Ring 1 WW-B238-H40

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BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

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WS-318-D CAMCO TR-SSV LOCK OPEN TOOLS AND ACCESSORIES

Camco TRM-4E type TR-SSV

Application

Standard to moderately corrosive applications to 300°F. A special treatment is

available to prevent buildup on selected internal surfaces for especially severe scaling
conditions caused by produced fluids.

Operation

The normally closed TRM-4E safety valve is opened with hydraulic pressure applied
through a hydraulic control line extending from the safety valve through the wellhead to
the surface control panel. Hydraulic pressure applied from the surface forces the rod
piston and flow tube down, compressing the power spring and moving the flapper off
seat into the fully open position. When hydraulic control line pressure is released, the
power spring pushes the flow tube and rod piston up, which permits the hinged flapper
to move into the flow stream and close against the flapper seat shutting in flow from the
well.

Lockout Procedure

A unique lockout mechanism enables a simple one-trip wireline procedure to

permanently lock out the vblve and initiate secondary hydraulic communication. A
lockout sleeve, located above the flow tube, is shifted downward simultaneously
locking the valve open and disengaging a press fit metal seal plunger to initiate
hydraulic communication to the valve ID. A secondary wireline valve can then be
installed in the TRM-4E valve. A second lockout option allows the valve to be locked
open without activating secondary hydraulic communication. The versatile TRM-4E
safety valve is available with a wide range of upper nipple profiles.

Equalizing Procedure

To open the valve with pressure below the flapper, hydraulic pressure is applied to the
actuating piston. The valve's flow tube moves downward pushing the ported equalizing
dart outward. The wellbore fluid travels via a port in the equalizing dart into the bore of
the valve above the flapper. The pressure above the flapper increases until it equals
the pressure below the flapper.

3-1 /2" TRM-4E SCSSV

DIMENSIONAL AND ENGINEERING DATA *Maximum Allowable Hydraulic Pressure

Maximum OD: 5.000in Safety Valve Internal Maximum Control

Minimum ID: 2.812 in Pressure (psi) Line Pressure (psi)
Hyd. Chamber area: 0.110 sq.in
Flow Tube Travel 4.845 in 0 5,000
Drift Bar: Pt. No. 87808-011 1,000 6,000
Drift Bar Spec.: 2.808” x 42” 2,000 7,000
Overall Length: 52.971 in 3,000 8,000
Nipple Profile: Otis 2.812” X type 4,000 9,000
5,000 10,000

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Operating Data

Working Pressure: 5,000 psig * The table above identifies the absolute Maximum
Test Pressure 7,500 psig Allowable Hydraulic Pressure for a given tubing
Opening Pressure *1250 psig pressure. However, Camco recommends that the
Closing Pressure *645 psig hydraulic control pressure be maintained as close to
Temperature Rating: 20°F to 300°F the minimum requirement as possible to safely hold
Tensile Strength **257,000 lbs the valve in the fully open position in order to
Internal Yield Pressure **8,020 psig prolong the life of the hydraulic seals (see Operating
Internal Yield Pressure **8,020 psig Requirements section of this manual.)
External Yield Pressure **6,757 psig

Materials:

Flow wetted components: 9CR 1 MO

Body Components: 4140
Specialty Components (piston assy., flapper/flapper seat assy., springs): High strength
Ni-Cr, Ni-Co and Ni-Cr-Mo alloys

Note: Materials listed identify the general corrosion resistance for the category of
components. Materials with better general corrosion resistance may be used
for other parts in the same component category.

Note: "Flow wetted" is defined as those components with an ID that is in direct

contact with the flowing production fluid. Other components in stagnant areas
of the valve may be "wetted" (i.e. in contact with produced fluids), but are not
subjected to fluid flow movement.

API Class of Service: Class 2

Permanent lockout/hydraulic communication tool: Pt. No. 13677-000-00000

Selective lockout/hydraulic communication tool: Pt. No. 13678-000-00000
Lower choke lockout tool (Z-5 type): Pt. No. 13722-000-00000
Lower choke lockout tool no-go sub: Pt. No. 10402-001-00000

Note: For a complete lockout tool, both the lower choke lockout tool and lower choke
lockout tool no-go sub are needed.
No-go to bottom of choke recess with valve in open position: 21.324 in

Note: By machining a new spacer bar in the field, an existing Camco Z-5 type
lockout tool may be converted for use in the TRM series SCSSV. Use the
above specification for modification.

Secondary Valve: Pt. No. 21740-000-00000
Description: WRDP-1
Secondary valve spacer assembly: Contact Camco Engineering
Secondary valve lock assembly: 2.81” OTIS X TYPE

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Permanent Lockout And Secondary Communication Actuation
Procedures

The TRM series SCSSV provides for two methods of permanent lockout in the event
problems occur which prevent proper operation of the safety valve.

Method 1: If a wireline retrievable SCSSV is to be installed in the TRM and a minimal

number of wireline trips is desired. Method 1 provides for permanently
locking the TRM out and providing secondary hydraulic communication in
one wireline trip. Using this method, the secondary hydraulic
communication feature and permanent lockout feature are simultaneously
activated.
Method 2: If the TRM is to be permanently locked out, but activation of the secondary
hydraulic communication feature is not required. Method 2 provides for
permanent lockout without activating secondary hydraulic communication.
The following examples are typical situations in which permanent lockout is
required without activating hydraulic communication.

1) Completion being pulled (may or may not be SCSSV related problem). Lockout
required to provide through-tubing access for tools or circulation.
2) Operator elects to run SSCSV secondary valve as opposed to SCSSV.
3) Hydraulic integrity lost between surface control system and hydraulic
communication.

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Permanent Lockout Procedure

Method 1: One-trip permanent lockout/ secondary hydraulic communication

1) Make up the lockout tool to the wireline tool string. A typical wireline tool string
consists of:
a) Rope Socket.

b) Weight Bars (stem)

Since the lockout tool is pressure assisted, a normal amount of weight is

sufficient. As an example, 100 Ibs for smaller sizes (2-3/8" 3-1/2") and 200 lbs for
larger sizes (4" - 7").

Note: More weight than that noted will improve lockout efficiency.

c) 1.3. Mechanical Jars

2) Non-selective lockout tool: Lower the lockout tool into the well until it lands in the
TRM and the no-go shoulder on the no-go sub contacts the no-go shoulder in the
TRM hydraulic chamber housing. Tap down lightly to verify the no-go is
shouldered and that the tool is not located in a tight spot.

Selective lockout tool: Lower the lockout tool into the well until the tool passes
through the desired profile.

Caution: To prevent the lockout tool from becoming hung up, make sure that
the top of the lockout tool is not run past the closed flapper.

Once the tool passes through the desired profile, reverse direction and back the
tool through the profile. This will activate the pogo dogs. Set back down when the
lockout tool locates the no-go in the nipple bore. Tap down lightly to verify the
no-go is shouldered and that the tool is not located in a tight spot.

3) Apply hydraulic pressure to the control line equaling 500 psi over SITP. Block in
control line pressure during lockout procedure.
4) Jar down (2-5 licks should be sufficient) to shear the brass pins in the no-go sub.
This will set the locking dogs in the recess above the lockout sleeve and allow the
hydraulic ram to seal against the o-ring in the ID of the packing sub.
5) Apply tubing pressure above the lockout tool to a pressure 1000 psi above SITP
at valve depth.

6) Jar down aggressively until the shear bolts of the TRM shear, allowing the
lockout sleeve to move downward loading the plunger. Continue jarring
downward until the plunger is removed from the chamber housing.

Note: It will be evident that the plunger is properly removed when the hydraulic
control pressure drops to SITP.

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After the shear bolts are sheared and hydraulic communication is established, the
pressure differential across the lockout tool will place the flow tube in the full open
position, allowing the top of the plunger to clear the bottom of the hydraulic
chamber housing.

7) Bleed down pressure above the lockout tool so pressure above the lockout tool at
valve depth equals SITP at valve depth.

8) Pick up the tool string and retrieve lockout tool to surface.

Hydraulic Communication Verification

1) Slowly pump hydraulic fluid into the control line. Pressure will rapidly fall off to
SITP if the communication feature is working properly.

Permanent Lockout Verification

To verify the TRM SCSSV is properly locked out, perform one of the following two
procedures:

1) Wireline Verification
a) Attach a blind box with an OD compatible to the polished bore ID to a
standard wireline tool string.
b) Slowly lower the blind box completely through the TRM and back to the
surface. The blind box should freely pass through the valve in both
directions.

2) Flow verification
a) Slowly open the wing valve to initiate well flow and gradually open to full
normal production. The production rate should be comparable to that when
the valve is in service, before lockout.

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Permanent Lockout Procedure

Method 2: Permanent Lockout procedure without hydraulic communication

The lower TRM lockout mechanism enables the TRM to be permanently locked open
without utilizing the secondary communication feature. This is accomplished by setting
a lock in the lower choke and shifting the choke under the flapper using wireline
methods. This lockout tool assembly consists of the lower choke lockout tool and lower
choke lockout tool no-go sub.

Refer to the Data Sheet for part numbers.

The length of the extension bar is designed so the locking dogs of the lock will be
below the lower choke lock recess when the no-go sub contacts the no-go shoulder in
the hydraulic chamber housing. The complete lockout tool is attached to the bottom of
a conventional wireline tool string (weight bars and mechanical jars) and lowered
through the tubing until the safety valve is reached.

Note: Before the permanent lockout procedure can begin, the differential pressure
across the safety valve must be reduced to zero, i.e., the pressure in the
tubing above the valve must be equal to the shut-in pressure below the
flapper. This is accomplished by applying pressure to the tubing above the
valve and monitoring the pressure increase. Equalization of pressure across
the valve will be evident when the pressurization rate decreases significantly
(stabilizes).

1) Lower the complete tool string through the tubing until the no-go shoulder in the
hydraulic chamber housing stops the tools.
2) Tap downward lightly to verify contact between the no-go on the tool string and
the no-go shoulder in the hydraulic chamber housing.

Note: If a shear pin through the lower body/prong is used, raise the tool string
approximately one to two feet and drop it on the no-go shoulder several times
until the pin shears and allows the collet to release and engage the dogs.

3) Lift up on the tool string. As the locking dogs reach the lower choke lock recess,
they will extend and engage the recess. Continue pulling upward until
approximately 500 pounds additional load registers on the weight indicator.
4) Slowly lower the tools and jar upward to shear the running tool from the lock.
5) Return the tool string to the surface and remove the no-go sub, extension bar and
lock running tool.
6) Attach a blind box with an OD compatible to the minimum ID of the TRM.
7) Lower the tools through the tubing string until the blind box stops on the top of the
lock.
8) Jar downward on the lock until travel is noted, indicating the upper set of shear
screws has sheared.

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9) After the lower choke is separated from the flow tube, it will move down until the
lower lock-out sleeve contacts the top of the seat insert. Continued jarring will
shear the second set of shear screws, allowing the lower lock-out ring to locate in
the lock-out recess.
10) Continue downward jarring until a solid blow is indicated. This indicates the lower
choke has been driven completely down, opening the flapper and that the set
screws are sheared. The lower choke is held down permanently by the lower
lockout ring.
11) Return the tool string to the surface. Remove the blind box from the tool string.
Attach the lock pulling tool (with prong) to the tool string.
12) Lower the tool string into the tubing until the lock fishing neck is contacted.
13) Jar downward to latch onto the lock fishing neck. The pulling prong will unlock the
locking dogs at the same time that the pulling tool latches onto the lock fishing
neck. Pull upward to return the lock to the surface.

Permanent Lock-Out Verification

See procedure following permanent Lock-out Method 1 to verify TRM is permanently

locked out.

NOTE: Lock out features for TRM-4E and TRM-4PE-CF are identical.

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7” TRM-4P-CF SCSSV
Pt. No.22910-000-00103

Revision No. 00 Revision Date 8/97

Item Part Number Qty Description
1 22910-120-00004 1 Hydraulic Chamber Housing
2 22907-131-00003 1 Lock-out Sleeve
3 22867-103-00001 1 Piston Head
4 22262-003-04000 2 Piston Seal Set (Omniseal)
5 22262-004-00002 2 Seal Stop
6 21224-025-04000 1 Wiper Ring
7 22867-024-00001 1 Down Stop
8 22907-023-00002 1 Lower Piston
9 22910-016-00003 1 Flow Tube
10 22910-011-00001 1 Spring Stop Retainer
11 22907-009-00003 1 Spring Stop
12 22907-016-00001 1 Power Spring (1000 ft)
13 22907-027-00002 1 Lower Choke
14 21166-026-04000 8 Hexagon socket set screw
15 22907-015-00002 1 Lower Lock-Out sleeve
16 22907-018-00001 1 Lower Lock-out ring
17 22910-019-00001 2 Retainer screw
18 22910-010-00003 1 Lock-Out ring retainer
19 22907-005-00001 1 Wiper ring
20 22910-021-00001 1 Guide key retainer
21 22907-011-00001 2 Guide Pin
22 22907-010-00002 1 Flapper Housing
23 22907-017-00001 1 Omni seal set
24 22907-012-00001 1 Omni seal set
25 22491-031-00007 2 Hexagon socket set screw
26 22907-B00-00001 1 Flapper / hard set sub-assembly
27 22910-015-00001 1 Spring housing
28 22910-014-00004 1 Lower nipple
29 22491-049-08000 4 Button head cap screw
30 22491-038-08000 1 Flapper spring
31 22491-034-08000 1 Left Spring Rod
32 22491-037-08000 1 Flapper Pin
33 22491-053-08000 1 Right spring rod
34 22907-A00-00002 1 Nose spacer sub-assembly
35 22491-063-06000 1 Button
36 22910-012-00001 1 Guide key
37 22856-015-00001 3 Shear bolt
38 22856-111-00001 1 Shear plug
39 22907-036-00001 1 Leaf Spring
40 13362-020-01000 2 Flat head socket cap screw
41 22910-020-00001 1 Snap ring
42 33630-011-00001 1 ¼ x 1/8 NPT male adapter-316SS
43 22907-122-00001 1 Lock-Out Rod (7- inch)
44 23039-020-00001 1 Lockout plug

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Recommended Hydraulic Pressure

Under normal conditions, the hydraulic seals are exposed to differential pressure for
long periods of time. Schlumberger recommends minimizing these differential
pressures in order to maximize the life of the seal. Higher pressure differentials may be
acceptable for special applications. (Contact Field Service for information.) Therefore,
minimum and maximum recommended surface hydraulic pressure should be
determined by the following equations.

Minimum Recommended Hydraulic Operating Pressure (Surface)

Pso (min) = Pt + Po + Psf - Ph

Maximum Recommended Hydraulic Operating Pressure (Surface)

Pso (max) = Pt + Po - Ph + 5,000 psi

Pso (min) = Minimum Recommended Hydraulic Operating Pressure (surface)

Pso (max) = Maximum Recommended Hydraulic Operating Pressure (surface)
Pt = Tubing Pressure at Valve Depth
Po = * Opening Pressure (Zero Bore)
Ph = Hydraulic Pressure of the Hydraulic Fluid
Ps f = Safety Factor to Insure the Valve Is Fully Open (400 psi)

'Since the opening pressure may vary slightly from valve to valve, obtain this number
from the safety valve receiving report or functional test report.

Maximum Allowable Hydraulic Pressure (Surface Test Only)

15,000 psi

Test Pressures up to 15,000 psi should only be applied when necessary to test control
line components .Do not expose hydraulic seals to high differential pressure for long
periods of time.

Valve Equalizing and Opening Procedure

CAUTION: Do not exceed the maximum hydraulic control line pressure of the
wellhead.

Use the following steps in order to equalize and open this safety valve.
1. Shut in the well at the wellhead.
2. Pressure the tubing above the valve until the pump pressure levels out
indicating equalization across the flapper.

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1) WITH external pressure source available:

a) Before the opening procedure can begin, the differential pressure across the
safety valve must be reduced to zero, i.e., the pressure in the tubing above the
flapper must be equal to the shut-in pressure below the flapper. This is
accomplished by applying pressure to the tubing above the valve and monitoring
the pressure increase. Equalization of pressure across the valve will be evident
when the pressurization decreases significantly.
b) Apply surface hydraulic pressure to the safety valve hydraulic control line after
tubing differential pressure has been equalized. Continue applying hydraulic
control pressure until the gauge registers a pressure equal to the sum of the
shut-in tubing pressure at valve depth, the opening pressure of the safety valve
(from the test report), plus a safety factor margin of 1,000 psi minus the
hydrostatic head in the control line.

2) WITHOUT external pressure source available:

a) Slowly apply surface hydraulic pressure until the valve starts to equalize. Monitor
the wellhead tubing pressure gauge to see if the tubing pressure continues to rise
to shut in pressure.
b) Due to increasing tubing pressure acting to close the valve while equalizing, an
occasional increase in hydraulic pressure may be required to continue equalizIng.
c) When the gauge registers a pressure equal to the tubing pressure, continue to
apply hydraulic control line pressure until the safety valve is fully open. This will
be marked by a sudden increase in pressure registered on the surface hydraulic
control line pressure gauge. the valve should be opened with a zero psi opening
pressure differential across the valve.
d) Adjust the hydraulic control line pressure until the control line pressure gauge
registers a pressure equal to the sum of the shut in tubing pressure at valve
depth, the opening pressure of the safety valve, plus a safety factor of 1,000 psi
minus the hydrostatic head in the control line.

3) Once equalized, use the following formula to calculate the minimum surface
pressure needed to maintain the valve in the fully open position. See the
Recommended Calculations section.

Pso = Pt + Po + Psf - Ph

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WS-318-E TROUBLE SHOOTING PROCEDURES FOR TR-SSV’S

After arriving on the location, determine the type of problem involved and refer to the
procedure for the specific problem. Do not rush through the procedure. Remember that
the only way to solve the problem is to work through it until you have eliminated all
other possibilities and remember that the most important element in this process is to:

THINK IT THROUGH.

Slow Flapper Leak

This situation can arise for a number of reasons. Scale, paraffin, asphaltine or other
solid matter could have collected on the flapper or seat which could prevent full closure
of the flapper mechanism. Failure to maintain adequate control line pressure during
wireline operations through the safety valve could result in closure of the flapper on the
wire. Retrieval of the wireline tool string then results in banging on the closed flapper,
thus damaging the flapper and seat with the hard (typically 50-60 Rc) wire. Another
remote possibility is partial blockage of the control line which could prevent the flow
tube from travelling up into its full closed position, thus holding the flapper off its seat.

1) Disconnect panel from control line port and attach hand pump.
2) Bleed pressure off tubing.
3) When possible, bleed flow line down to or below tubing pressure to remove
possibility of surface valve leak.
4) Monitor wellhead pressure for one hour or use flow meter to determine leak rate.
If using the pressure building method, refer to API 14B RP for recommended
practice of determining leak rates.
5) Option 1: If pressure build up is observed, cycle valve five times to try to
remove any debris that may have lodged in the flapper area.
If the valve is a non self-equalising valve then during the equalising portion of the
procedure it is recommended to pump additional fluid past the flapper to try to
clean off the seat. Diesel is a good fluid to use for this purpose. Use caution using
water to equalise across the flapper in a gas well, this may cause hydrates.

If the valve is a self equalising valve then it is recommended to place the full
opening pressure on the control line. The flapper will open 50 to 100 psi before
complete equalisation. This surge will help to clean off the seat.

Option 2: If pressure build up is still experienced, try and energise the flapper
seal by bleeding the pressure above the valve as rapidly as possible.
This rapid reduction adds energy to the flapper and can help it seal,
especially in low pressure wells. Repeat steps 2 through 4.

Option 3: If leak still persists, discuss the options with company representative. If
the leak rate is below 5 SCFM or 200 cc/min, he may want to leave
the valve as it is. The permissible leak rate, according to the MMS, for
a subsurface safety valve is 5 SCFM or 200 cc/min. (If not governed
by MMS, API RP 14B allows 15 SCFM and 400 cc/min.) If this rate is
acceptable to the company representative, the panel may be
reattached to the control line port.

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Option 4: If valve still leaks, soak the valve in solvent. Run a plug or check
valve to a nipple below the safety valve. Fill the tubing with a solvent
(such as sweet crude, diesel with solvent, etc.) appropriate for the
suspected solids) to a level just above the safety valve and let the
solvent stand in the valve for 12 to 24 hours. Cycle the valve five to
ten times at the beginning and the end of the soak period. Remove
the plug and flow the well. Repeat steps 2 through 4.

Option 5: Run a flapper washout tool. This will clean the flapper and seat area
and may remove any debris causing the leak. Refer to the Flapper
Washout Tool Procedure for this operation in this file. Repeat steps 2
through 4.

Option 6: If leak rate is still above 5 SCFM or is above the customer's standard,
and other options have been exhausted then the last option is to slam
the valve at or below the well's flow rate. To slam the valve, open the
safety valve using the standard procedure. When the well is flowing
(wing valve open), release all pressure to the safety valve. The Slam
closure should be one of the last procedures tried. If there is debris
on the flapper seat the slam closure will either crush it and may help
the situation or the debris may be embedded deeper into the seat
making the situation worse. Baker valves built after 1980 have been
designed to handle slam closures and present no problem other than
those mentioned above. Do not try this with competitors valves.
Repeat steps 2 through 4 to determine leak rate. This procedure can
be repeated if unacceptable leakage persists.

6) If valve continues to leak, begin discussions concerning inserting a wireline insert

valve and locking open the valve. All parties should be in agreement and all
options should be completed before the valve is locked open.Refer to WS-318-B,
C and D for specific procedures.

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Valve Will Not Close

Note: The use of fluid sealant containing Teflon or other particles can cause the
failure of a safety valve in the open or closed position. They can cause the
blockage of control lines. Check, to determine if the operator has used a
sealant.

If the valve does not seem to be closing, use the following procedure.

1) Disconnect the panel from the tree and attach hand pump. Notice the markings
on the tree. Establish that all internal needle valves are in the open position and
that the panel has been connected to the proper port. Pump through control line
with panel to make sure fluid is reaching the control line port.
2) Try to open the safety valve with the hand pump using the standard opening
procedure or company's preferred procedure. Monitor control line pressure to see
if you can see the flow tube move. When releasing pressure, measure the returns
into a beaker. The new rod piston valves have small control line fluid volumes. It
is difficult to determine whether the flow tube is moving from the amount of
returns, but record the returns and watch for changes in the volume.
3) If control pressure builds up very rapidly (2-4 strokes), the problem could be in
the tree. Hydraulic fluid does not compress to any great degree and if the
problem is very shallow the pressure will increase rapidly. Check the return
volume. Check with company representative to see if there are any other check
valves in the tree or if wrong port is being used.
4) If it is determined that the tree is clear, the problem could be a plugged control
line or a stuck flow tube. If the control line is plugged, it can sometimes be freed
by surging. Pressure up on control line to the rated control chamber test (refer to
Tech Unit for the valve) Remember, to check the pressure rating on the wellhead
and do not exceed this rating. Release pressure rapidly. After doing this several
times, repeat step 2 and notice any difference in pressure build up or returns.
Repeat this process until you have determined that this is not the cause of the
problem.
5) Using standard wireline procedure, run the flow tube exercising tool. Refer to the
standard Flow Tube Exercising Tool Procedure for samples of operation (Baker
and Halliburton only). Repeat this operation several times, noting if there is any
movement.
6) If it is determined that valve is still not closing or if the flow tube is moving but the
flapper is not sealing, run flapper washout tool. Refer to standard Flapper
Washout Tool Procedure for this operation in this file.
7) If above procedures do not relieve the problem, begin discussions concerning
inserting a wireline insert valve and locking open the valve. Care should be taken
if the flow tube is still in the down position. For Baker valves,the Flapper Lock
Open tool should not be ran if the flow tube is covering the flapper. All parties
should be in agreement and all options should be completed before the valve is
locked open. Refer to the tool specific tech units for detailed procedures for the
Flapper Lock Open Tool and Puncture Communication Tool. Generic Flapper
Lock Open Tool and Puncture Communication Tool in OPG-WS-318-C. For
Halliburton valves: OPG WS-318-B and for Camco valves OPG WS-318-D.

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Valve Will Not Open

Note: The use of fluid sealant containing Teflon or other particles can cause the
failure of a safety valve in the open or closed position. They can cause the
blockage of control lines. Check to determine if the operator has used a
sealant.

1) Disconnect the panel from the tree and attach hand pump. Notice the markings
on the tree. Establish that all internal needle valves are in the open position and
that the panel has been connected to the proper port. Pump through control line
from panel to make sure fluid is reaching the control line port.
2) Try to open the safety valve with the hand pump using the standard opening
procedure or the company's preferred procedure. Take notice of the company's
procedure and determine if there is a problem with the procedure. Also,
determine if the valve is equalising or non-equalising. Monitor control line
pressure to see if you can see the flow tube move. When releasing pressure,
measure the returns. The pressure above the valve must be properly equalised.
Do not rely on pressure or pressure gauges only. There should be fluid pumped
past the flapper. Monitor the amount of fluid being pumped into the well. A
minimum of 3 barrels of fluid should be pumped past the flapper to ensure that
the pressures are equal above and below. Continually attempt to open the valve
during the pump through procedures.
3) If control pressure builds up very rapidly (2-4 strokes), the problem could be that
the control line system is blocked and the fluid in the valve can not be released.
Hydraulic fluid does not compress to any great degree and if the blockage is very
shallow the pressure will increase rapidly. Check the return volume. Check with
company representative to see if there are any other check valves in the tree or if
wrong wellhead port is being used.
4) If it is determined that the tree is clear, the problem could be a plugged control
line or a stuck flow tube. If the control line is plugged, it can sometimes be freed
by surging. Pressure up on control line to the rated control chamber test pressure
(refer to Tech Unit for the valve) Remember, to check the pressure rating on the
wellhead and do not exceed this rating. Release pressure rapidly. After doing this
20 times, notice if there is any difference in pressure build up or returns. Repeat
this process until you have determined that this is not the cause of the problem.
5) Using standard wireline procedure, run the flow tube exercising tool. Refer to the
standard Flow Tube Exercising Tool Procedure as in OPG WS-318-B and WS-
318-C. Repeat this operation several times, noting if there is any movement.
6) If above procedures do not relieve the problem, begin discussions concerning
inserting a wireline insert valve and locking open the valve. Care should be taken
if the flow tube is still in the down position. The Baker Flapper Lock Open tool
should not be ran if the flow tube is covering the flapper. All parties should be in
agreement and all options should be completed before the valve is locked open

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Tubing Pressure Observed on Control Line

It is not recommended to use fluid sealant containing Teflon or other particles. These
fluids cause more problems than they solve. The use of these fluids can cause the
failure of a safety valve in the open or closed position. They can cause the blockage of
control lines. This is an unacceptable solution.

Control line cannot be bled below shut in tubing pressure.

1) Care should be taken when working in this situation. Check to ensure that there
is a working valve coming out of the well head. Install a second valve as a safety
precaution. If there is a problem with safety, then have the operator hook up a
wireline unit and run a separation sleeve with a bull plug bottom across the valve
to stop the leak. If the situation is safe, set up a manifold that will allow the fluid to
be bleed off to the atmosphere. DO NOT BLEED BACK THROUGH A HAND
PUMP.
2) There are two possible scenarios - one is the well head is leaking and the second
is the valve could be leaking. It is likely that the wellhead has a higher probability
of leakage. If the well has pressure on the tubing, the company should install a
back pressure valve in the tubing hanger or a plug in the nipple adapter of the
valve. The idea is to isolate the well head seals from the safety valve seals. Once
the back pressure valve is in place - bleed the pressure off above the back
pressure valve. Monitoring the pressure on the control line - if the pressure goes
down with the bleed down then the leak is in the well head. Once the pressure in
the wellhead has gone to zero then bleed the control line to zero.
3) If pressure does not bleed off, the problem could be located in the safety valve.
Run a separation sleeve across the safety valve. Then attempt to bleed the
control line to zero. Due to the possibility of the packing leaking on the separation
sleeve the back pressure valve test is recommended prior to running the sleeve.
4) If above procedures indicate a problem with the safety valve, begin discussions
concerning inserting a wireline insert valve and locking open the valve. All parties
should be in agreement and all options should be completed before the valve is
locked open.

Annulus Pressure Observed on Control Line

It is not recommended to use fluid sealant containing Teflon or other particles. These
fluids cause more problems than they solve. The use of these fluids can cause the
failure of a safety valve in the open or closed position. They can cause the blockage of
control lines. This is an unacceptable solution.

1) Recommend that company representative have tree seals examined.

2) If tree seals check out, DO NOT RUN THE PUNCTURE COMMUNICATION
TOOL (BAKER) SHIFT THE LOCK OUT SLEEVE (HALLIBURTON), OR THE
PERMANENT LOCKOUT COMMUNICATION TOOL (CAMCO) ALLOWING
FLUID COMMUNICATION IN VALVE. This will allow the tubing pressure to
communicate to the Annulus through the leak.

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Washout Tool Procedure

1) Ensure that the valve is in the open position or is equalized

properly.
2) Pin flapper washout tool to lock according to lock manufacturer's
procedure. If there is a separate nipple above the safety valve, the
lock must be run in the selective position. If not, run the lock in the
no-go position.
3) Using standard wireline procedures, run the flapper washout tool,
land, and retrieve running tool.
4) Using the fluid recommended by the company representative (e.g.
glycol, methanol, 2% KCL water, hot diesel, paraffin solvent, etc.),
pump a few barrels down the tubing at the highest rate allowed by
the company representative or 6 BPM whichever is less. High
rates create a better jetting action and can clean the flapper and
seat area more thoroughly.
5) Retrieve flapper washout tool and lock.

Note: Coil tubing equipped with a jetting tool can also be used in the
above application.

Manufacturing and assembly procedure:

Use appropriate lock for safety valves nipple profile, a pup joint, and a
cap.

Attach the pup joint to the lock and then put the cap on the other end of
the pup joint to blank it off.

Drill approx. 1/8" to 1/2" diameter holes in the pup joint to create the jet
to wash out the flapper area.

Place 4 holes radially every inch for 5 inches on the pup joint starting at
a measured distance from the lock no-go. The measured distance is
equivalent to the distance from the pogo of the safety valve nipple
profile to the flapper pin.

For BSP applications an appropriate Otis lockmandrel will have to be

used to substitute the Baker BA Lock as shown in the drawing.

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Chapter 18, Tubing Retrievable Safety Valve Lock-Out Tools and Accessories Page 44 of 44
BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

CHAPTER 19
PRESSURE GRAPHS FOR SC-SSSV,s AND MINIMUM /
MAXIMUM HOLD OPEN PRESSURES FOR TR-SSV,s
TABLE OF CONTENT

WS-319-A PRESSURE GRAPH FOR OPENING SC-SSV'S WITH EQUALIZING

FEATURE DK , XOB - 7, FXE , QOP AND QOS ...........................................2
WS-319-B PRESSURE GRAPH FOR OPENING SC-SSV'S WITHOUT EQUALIZING
FEATURE XOF AND FXVH ...........................................................................3
WS-319-C TR-SSV MINIMUM AND MAXIMUM HOLD OPEN PRESSURES ................4

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WS-319-A PRESSURE GRAPH FOR OPENING SC-SSV'S WITH
EQUALIZING FEATURE DK , XOB - 7, FXE , QOP AND QOS

EXAMPLE: CITHP = 20,000kPA, differential pressure across valve = 15,000kPA

Opening pressure valve under atmospheric conditions = 5,000kPA
Recommended Hold Open Pressure of valve = 7,000kPA above CITHP.

kPA
50000

40000

30000

20000

10000

BLACK: CITHP RED: CONTROLLINE PRESSURE

1) Pressure up control line to opening pressure

2) Stop pumping when equalising starts
3) Equalising complete, increase controlline pressure
4) Safe hold open pressure is 7,000kpa above CITHP.

NOTE: When an FXE valve is used as an insert valve for a TR-SSV, be sure to
reduce the Control Panel setting as the control line pressure for the TR-SSV is
much higher than for a wireline retrievable valve. By not reducing this
pressure, irreparable damage will be done to the flapper valve's mechanism.

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WS-319-B PRESSURE GRAPH FOR OPENING SC-SSV'S WITHOUT
EQUALIZING FEATURE XOF AND FXVH

EXAMPLE: CITHP = 20,000kPA, differential across valve = 15,0000kPA

Opening pressure valve under atmospheric conditions = 3,000kPA
Recommended Hold Open Pressure of valve = 7,000kPA above CITHP.

kPA

50000

40000

30000

20000

10000

BLACK: CITHP RED: CONTROL LINE PRESSURE

1) Pressure up control line until ball cracks open

2) Stop pump when equalising starts
3) Equalising complete, increase control line to 7,000kPA above CITHP

The Baker FXVH (non-equalising) requires 17.250kPA above CITHP as Safe Hold
Open Pressure. Also Baker recommends to reduce the differential across the valve to
less than 1,300kPA before attempting to open or even to zero kPA if valve fails to
open.

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WS-319-C TR-SSV MINIMUM AND MAXIMUM HOLD OPEN PRESSURES

Halliburton:

SP-1, SP-2: Minimum hold open pressure =

CITHP + Opening pressure + 3500kPA
Maximum hold open pressure =
CITHP + Opening pressure + working pressure valve (70,000kPA)

WellStar: Identical to SP-1 and SP-2 (working pressure 35,000kPA)

Camco:

TRM-4P-CF: Minimum hold open pressure =

CITHP + Opening pressure + 3000kPA
Maximum hold open pressure =
CITHP + Opening pressure + working pressure valve (35,000kPA)

TRM-4E: Identical to TRM-4P-CF

Baker:

TE-5 Minimum hold open pressure =

TSME-5 CITHP + Opening pressure + 5500kPA
TSUME-5 Maximum hold open pressure =
TME-5 CITHP + Opening pressure + working pressure valve (35,000kPA)

TSME-10: Minimum hold open pressure =

CITHP + Opening pressure + 13000kPA
Maximum hold open pressure =
CITHP + Opening pressure + working pressure valve (70,000kPA)

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BSP Well Engineering Manual Volume 4, Wireline, Standard & Procedures

CHAPTER 20
CALCULATIONS, CONVERSIONS AND USEFUL
ENGINEERING DATA
TABLE OF CONTENT

WS-320-A INTRODUCTION TO CALCULATIONS AND CONVERSIONS .....................2

WS-320-B THE UNITS ......................................................................................................3
WS-320-C BASIC FORMULA ...........................................................................................4
WS-320-D LENGTH / AREA / VOLUME...........................................................................5
WS-320-E RULES OF THUMB .........................................................................................6
WS-320-F FORCE.............................................................................................................7
WS-320-G HYDROSTATIC PRESSURE .........................................................................8
WS-320-H COMMON FACTORS .....................................................................................9
WS-320-I CONVERSION FACTORS..............................................................................10
WS-320-J FRACTION CONVERSIONS .........................................................................14
WS-320-K TUBING TABLE .............................................................................................15
WS-320-L LINE STRETCH DATA ..................................................................................16
WS-320-M ABBREVIATION............................................................................................17
WS-320-N METHOD TO DETERMINE TUBING OR CASING PRESSURE
DIFFERENTIAL ............................................................................................19
WS-320-O TABLE CHART OF GAS CORRECTION FACTORS ..................................21
WS-320-P TABLE CHART OF FLUID GRADIENT CHART ...........................................22
WS-320-Q TABLE CHART OF WEIGHT OF FLUID IN KG/M³ ......................................23
WS-320-R TABLE CHART OF FLUID WEIGHT CONVERSION CHART .....................24
WS-320-S TABLE OF DECIMAL EQUIVALENTS TO COMMON FRACTIONS ...........25
WS-320-T METHOD FOR CALCULATING HYDROSTATIC PRESSURE ....................26
WS-320-U USEFUL TOOL DATA ...................................................................................27

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WS-320-A INTRODUCTION TO CALCULATIONS AND CONVERSIONS

While the need for accurate `on the job' calculations can be kept to a minimum, it is
necessary for the wireline operator to be aware of the following basic concepts:

As most wireline work is conducted with the well under pressure, an understanding of
the basic laws of fluids is essential. The consequences of neglecting to consider the
forces created by a downhole pressure differential can be severe in terms of lost
production, lost equipment, and reduced safety.

The following section is not intended as a complete reference for oilfield calculations,
and topics will be restricted to those relevant to wireline operations.

Despite an international trend to metrication and SI units, the oil industry uses many
imperial and US measurements. To simplify this section, metric and US units have
been favoured with common variations in SI and imperial units noted where
appropriate.

In addition to these units, it is an advantage to be aware of the following basic laws of

physics concerning fluids.

Within the limits of practical wireline applications, we assume the following to be true:

1) Liquids are not compressible.

2) Gases are compressible.
3) Liquids and gases are both fluids.
4) Pressure in a fluid is transmitted equally in all directions.

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WS-320-B THE UNITS

The basic units in the metric and US systems pertaining to wireline operations are
listed below:

Metric US Unit
Length Millimetres (mm) Thousandths (1/1,000)
Centimetres (cm) Inch (in/”)
Metres (m) Foot (ft/”)
Area Square millimetres (mm²)
Square centimetres (cm²) Square inches (in²)
Square metres (m²) Square feet (ft²)
Volume Millilitres(ml) Cubic inches (in³)
Litres (L) Cubic feet (ft³)
Cubic centimetres (cc) (cm³) * Gallons (gal)
Cubic metres (m³) Barrels (bbl)
Pressure Kilopascals (Kpa) Pounds per square inch (psi)
Bar Atmosphere (atm)
Force Newtons (N) Pounds force (lbf)
Deca Newtons (DaN)
Kilogram force (kgf)
Weight Gram (g) Ounce (oz)
Kilogram (kg) Pound (lb)
Density Grams per cubic centimetre (g/cm³) Pounds per cubic foot (lbs/ft³)
Kilograms per cubic metre (kgs/m³) Pounds per gallon (lbs/gal)
Gradient Kilopascals per metre (Kpa/m) Pounds per square inch per foot (psi/ft)
Kgcm²/m
Temperature  Degrees Centigrade (°C) Degrees Fahrenheit (°F)

Variations

* Imperial gallon = 20 fluid ounces (i.e. 125% of US / gallon)

US gallon = 16 fluid ounces (i.e. 80% of an imperial gallon)

 SI Temperature unit = Degrees Kelvin (°K)

°K = °C + 273

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WS-320-C BASIC FORMULA

Area L

W
Square A = L x W
L

W Rectangle A = L x W

R
d Circle A =  R²

Diameter (D) = 2 x Radius ® pi ( ) = 3.14 (and is constant)

Volume
L

D Tank = L x W x D

R
Cylinder (tubing / casing) =  R² x D
D

Pressure Force per unit area = F / A

Hydrostatic Pressure = Pressure created by a column of fluid

= Density x Vertical depth of column

Force = Pressure x Area

Impact Force = Mass x Accelration

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WS-320-D LENGTH / AREA / VOLUME

Legends A = Area
a = altitude (height or depth)
r = Radius
D = Diameter
Formulas

Any Triangle A = ½ab

Right Triangle a =  c² - b²
b =  c² - a²
c =  a² + b²

Circle A =  r²
A = 0.7854 D²
C = D

Rectangle / Parallelogram A = ab

Trapezoid A = ½ a (b1 + b2)

Cube V = b³

Prism / Cylinder V = a x (Area of base)

1
Pyramid / Cone V = /3 a x (Area of base)

Sphere V = 4
/3  r³ =  D³ A = 4  r²
6
Constants  = 3.1416 ² = 9.8696
/2 = 1.5708 1/² = 0.1013
/3 = 1.0472  = 1.7725
2/3 = 2.0944 3
 = 1.4646
1/ = 0.3183

Electrical
Ohm’s Law Volts = Amps x Ohms

Watt’s Law Watts = Amps x Volts

Kilowatt hour = 1,000 Watt / hours
Amps = Watts
Volts

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WS-320-E RULES OF THUMB

Rules Of Thumb provide an approximate value for rapid field use and / or checking the
magnitude of calculated values.

1) Rule of thumb for finding the fill up volume of any size pipe is the inside diameter
squared equals barrels per 1,000 ft.
ID2 = bbls / 1,000 ft.
2) Approximate hydrostatic head = 0.052 x Wt / gal. x Depth in ft.
3) Hydrostatic head = Gradient x True vertical depth.
4) To convert specific gravity to API = 141.5 / SG - 131.5 = 0API.
5) To convert specific gravity to gradient: SG of fluid x 0.433 = Gradient of fluid.
6) Bottom hole pressure of gas column = Surface pressure x Gas correction factor.
7) Centigrade x 1.8 + 32° = °F.
8) Centigrade = Fahrenheit - 32° x 0.5555.
9) 1 Pascal = 1 Newton / square metre (using SI units).
10) Approximate hydrostatic head in KPa = kg / litre x Depth in metres x 9.81.

11) Partial pressure = psi x % H2S / CO2

100
12) Specific gravity = 141.5
API + 131.5

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WS-320-F FORCE

There are 2 types of Force which are relevant to wireline operations:

1) Force created by a pressure acting on an area.

Whenever a pressure differential downhole acts on a cross-sectional area, the

force created is directly proportional to the pressure and the area.

Force = Pressure x Area

Example The force of 3½” x plug (2.750” packing bore) with a 5,000 psi
pressure differential is:

Area =  R²
= 3.14 x 2.750 ²
2
= 5.94 in²

Force = Pressure x Area

= 5,000 x 5.94
= 29,700 ibf

2) Impact Force created during downhole jarring action.

This impact force is critical to achieve the desired movement and shearing action
in downhole tools and equipment. The amount of force created is directly
proportional to the mass of the stem, and the speed at the point where jars are
fully opened or closed.

Impact Force = Mass x Acceleration

Downward Jar Action Upward Jar Action

Acceleration due to gravity only. More acceleration available from wireline unit speed
on the surface.

Limited by – Fluid viscosity. Stem can be accelerated through heavy fluid and in
– Hole deviation deviated holes by wireline from the surface.
Result

Less impact available More impact available

Smaller shear pin diameters in
shear down tools. Larger shear pin diameters in shear up tools.

Stem Weight Calculation (approximate)

Stem weight (lbs) = Stem OD (inches) x Length (ft).

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WS-320-G HYDROSTATIC PRESSURE

A calculation of the approximate downhole differential pressures is recommended prior

to the following wireline operations:

1) Pulling a plug.
2) Retrieving gaslift valves.
3) Opening an SSD.

As these pressure differentials are often influenced or created by hydrostatic pressure,

the following information is useful:

Hydrostatic Pressure Is the pressure created by a column of fluid. The amount of

pressure is directly proportional to the fluid density and
vertical depth.

Note: True Vertical Depth (TVD) is important in

calculations in deviated wells.

To calculate hydrostatic pressure, it is necessary to have an

understanding of the following terms in addition to the basic
pressure formula:

Hydrostatic Pressure = Density x Depth

Specific Gravity Is a ratio of the density of a fluid compared with the density
of water. The specific gravity of water is one in all systems.
(No units, as this is a ratio).

Density Weight of a fluid per unit volume.

(Units = lb/gal, lb/ft3, Kg/m3, Kg/L.)

Gradient Rate of pressure increase per unit of depth.

(Units = psi/ft, KPa/m.)

As pure water is used as a standard of comparison, the following facts about water are
necessary:

US Metric
Density 62.4 lbs/ft³ 1 g/cm³
8.33 lbs / gal 1,000 kgs/m³
Gradient 0.433 psi/ft 0.1 kgcm²/m

Fresh Water Facts Water is used as a comparative standard.

Weight ....................................... 8.33 pounds per US gallon

Density ............................................. 62.4 pounds per cu. ft
......................................................................or 1,000 kg/m3
......................................................................... or 1 kg / litre
Gradient ...................................................... 0.433 psi per ft
Specific gravity .................................................................. 1
API gravity....................................................................... 10°

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WS-320-H COMMON FACTORS

Metric US
Length cm x 0.3937 = inches in x 2.54 = cm
m x 3.281 = feet ft x 0.3048 = m
Area cm² x 0.155 = in² in² x 6.452 = cm²
m² x 10.76 = ft² ft² = 0.0929 = m²
Volume cm³ (cc) x 0.06102 = in³ In³ x 16.3871 = cm³
m³ x 35.3147 = ft³ ft³ x 0.02832 = m³
m³ x 6.29 = bbl bbl x 0.159 = m³
m³ x 264.2 = gal gal x 0.003755 = m³
gal (US) x 0.83267 = gal (imp)
ft³ x 7.481 = gal
bbl x 42 = gal
bbl x 5.6146 = ft³
ft³ x 0.1781 = bbl
ft³ x 1728 = in²
Pressure kg/cm² x 14.22334 = psi psi x 0.07031
bar x 14.50 = psi atm x 14.70 = psi
bar x 0.987 = atm atm x 1.013 = bar
kpa x 6.895 = psi psi x 0.145 = Kpa
bar x 1.02 = kg/cm² psi x 0.6804 = atm
Force newtons x 0.225 – lbf lbf x 4.448 = N
kgf x 9.81 = N
kgf x 2.205 = lbf ibf x 0.454 = kgf
Weight / Mass g x 0.03527 = oz oz x 28.35 = g
kg x 2.205 = lb lb x 0.43536 = kg
1 short ton (2,000 lb) = 907 kgs
1 long ton (2,240 lb) = 1,016 kgs
1 tonne (metric) = 1,000 kgs
Density g/cm³ x 62.4 = 62.4 = lb / ft³ lb/ft x 0.01602 = g/cm³
kg/m³ x 0.001 = g/cm³ lb/ft x 16.02 = kg/m³
lb/gal x 0.1199 = g/cm³
gal/ft x 7.49 = lb/ft³
Gradient kg cm²/m x 0.231 = psi/ft ft of water x 0.0295 = atm
ft of water x 0.433 = psi
psi/ft x 7.49 =lb/ft³
Temperature (°C + 17.78) x 1.8 = °F (°F – 32) x 0.5555 = °C
C + 273 = °K

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WS-320-I CONVERSION FACTORS

Multiply By To Obtain
Acres 43,560 Square feet
Acres 4,047 Square metres
Acres 160 Square rods
Acres 5,645.4 Square varas (Texas)
Acres 0.4047 Hectares
Acre feet 7,758 Barrels
Acre feet 1,233.5 Cubic metres
Atmospheres 33.94 Feet of water
Atmospheres 29.92 Inches of mercury
Atmospheres 760 Millimetres of mercury
Atmospheres (at sea level) 14.7 Pounds per square inch
Barrels 5.6146 Cubic feet
Barrels (oil) 0.15899 Cubic metres
Barrels (US liquid) 0.11924 Cubic metres
Barrels (oil) 42.0 Gallons
Barrels (US liquid) 31.5 Gallons
Barrels 158.9 Litres
Barrels of cement (dry weight) 376.0 Pounds of cement
Barrels per hour 0.0936 Cubic feet per minute
Barrels per hour 0.700 Gallons per minute
Barrels per hour 2.695 Cubic inches per second
Barrels per day 0.02917 Gallons per minute
Bars 0.9869 Atmosphere
British thermal unit 0.2928 Watt hours
BTU 1,055.06 Joules
BTU's per minute 0.02356 Horsepower
BTU's per second 1,054.4 Watts
Centigrade heat units 1.8 BTU
Centimetres 1 x 108 Angstrom units
Centimetres 0.01 Metres
Centimetres 0.03281 Feet
Centimetres 0.3937 Inches
Centimetres 10,000.0 Microns
Centimetres of mercury 0.1934 Pounds per square inch
Chains 66 Feet
Chains 4 Rods
Cubic centimetres 0.06102 Cubic inches
Cubic centimetres 2.6417 x 10' Gallons
Cubic centimetres 0.0010567 Quarts (US fluid)
Cubic centimetres 0.03381 Ounces (US fluid)
Cubic feet 28,317.0 Cubic centimetres
Cubic feet 0.1781 Barrels
Cubic feet 7.481 Gallons (US)
Cubic feet 28.316 Litres
Cubic feet of steel 489.6 Pounds of steel
Cubic feet 1728. Cubic inches
Cubic feet 0.028317 Cubic metres
Cubic feet 0.03704 Cubic yards
Cubic feet / atmosphere 2,116.3 Foot / pounds
Cubic feet per minute 10.686 Barrels per hour
Cubic feet per minute 28.8 Cubic inches per second

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Multiply By To Obtain
Cubic feet per minute 7.481 Gallons per minute
Cubic feet per minute 0.1247 Gallons per second
Cubic feet per minute 472.0 Cubic centimetres per
second
Cubic feet per second 7.48 Gallons per second
Cubic feet per second 0.64632 Million gallons per day
Cubic inches 16.387 Millilitres
Cubic inches 16.387 Cubic centimetres
Cubic inches 0.00058 Cubic feet
Cubic inches 0.00433 Gallons
Cubic inches 0.0164 Litres
Cubic metres 6.2897 Barrels
Cubic metres 35.314 Cubic feet
Cubic metres 1.308 Cubic yards
Cubic yards 4.8089 Barrels
Cubic yards 27 Cubic feet
Cubic yards 46,656 Cubic inches
Cubic yards 0.76456 Cubic metres
Fathoms 6.0 Feet
Fathoms 1.829 Metres
Feet 30.48 Centimetres
Feet 0.3048 Metres
Feet 0.3600 Varas (Texas)
Feet of water @ 60° F 0.4331 Pounds per square inch
Feet per minute 0.5080 Centimetres per second
Feet per second 0.68182 Miles per hour
Foot/pounds 0.0012856 BTU
Foot/pounds 3.766 x 10-' Kilowatt / hours
Foot / pounds per second 0.0013558 Kilowatts
Foot/pounds 5.051 x 10-' Horsepower / hours
Foot / pounds per second 0.0018182 Horsepower
Foot / pounds (force) 1.3558 Joules
Gallons (US liquid) 0.03175 Barrels (US liquid)
Gallons (US) 0.02381 Barrels
Gallons 0.003785 Cubic metres
Gallons (US) 3,785 Cubic centimetres
Gallons (US) 0.13368 Cubic feet
Gallons (US) 231 Cubic inches
Gallons (US) 3.785 Litres
Gallons (US) 0.8327 Gallons (imperial)
Gallons per minute 1.429 Barrels per hour
Gallons per minute 0.1337 Cubic feet per minute
Gallons per minute 0.002228 Cubic feet per second
Gallons per minute 34.286 Barrels per day
Grains (Avoirdupois) 0.0648 Grams
Grains per gallon 17.118 Parts per million
Grains per gallon 142.86 Pounds per million gallons
Grains per gallon 0.01714 Grams per litre
Grams 15.432 Grains
Grams 0.001 Kilograms
Grams 1,000 Milligrams
Grams 0.03527 Ounces
Grams 0.002205 Pounds
Grams per litre 58.418 Grains per gallon

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Multiply By To Obtain
Hectare 2.471 Acres
Hectare 0.010 Square kilometres
Horsepower (British) 2,545.0 BTU per hour
Horsepower (British) 42.42 BTU per minute
Horsepower 0.7457 Kilowatts
Horsepower (British) 745.7 Watts
Horsepower (British) 1.0139 Horsepower (metric)
Horsepower 33,000 Foot pounds per minute
Horsepower (metric) 542.47 Foot / pounds per second
Inches 0.0254 Metres
Inches 2.54 Centimetres
Inches 0.08333 Feet
Inches of mercury 1.134 Feet of water
Inches of mercury 0.4912 Pounds per square inch
Inches of water @ 60° F 0.0361 Pounds per square inch
Kilograms per square centimetres 14.223 Pounds per square inch
Kilograms 2.2046 Pounds
Kilograms 1,000 Grams
Kilometres 0.6214 Miles
Kilometres 3,281 Feet
Kilopascals 0.1451 PSI
Kilowatt / hours 3,414.0 BTU
Kilowatts 1.3410 Horsepower
Knots (international) 0.5144 Metres per second
Knots (nautical miles per hour) 1.1516 Miles per hour
Litres 1,000 Cubic centimetres
Litres 61.02 Cubic inches
Litres 0.26418 Gallons
Litres 1.0567 Quarts
Metres 100 Centimetres
Metres 3.281 Feet
Metres 39.37 Inches
Metres 1.094 Yards
Miles 5,280.0 Feet
Miles 1,609.3 Metres
Miles 1.609 Kilometres
Miles 1,900.8 Varas (Texas)
Miles (international nautical) 6,076.1033 Feet
Miles (international nautical) 1.1508 Miles (US statute)
Miles per hour 1.4667 Feet per second
Millimetres 0.001 Metres
Minutes (angle) 2.909 x 10' Radians
Ounces 0.2835 Kilograms
Ounces (avoirdupois) 437.5 Grains
Ounces (avoirdupois) 28.3495 Grams
Ounces (US fluid) 29.57 Millilitres
Parts per million 0.05835 Grains per gallon
Parts per million 8.34 Pounds per million gallons
Pints (US liquid) 1.89 Litres
Pounds 7,000 Grains
Pounds 453.6 Grams
Pounds 0.45359 Kilograms
Pounds force 4.4482 Newtons
Pounds per gallon 0.1198 Grams per cubic centimetre

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Multiply By To Obtain
Pounds per gallon 0.052 Pounds / square inch / feet
of depth
Pounds per square inch 2.309 Feet of water at 60° F
Pounds per square inch 2.0353 Inches of mercury
Pounds per square inch 51.697 Millimetres of mercury
Pounds per square inch 0.0703 Kilograms per square
centimetre
Pounds per square inch 6.8947 Kilopascals
Pounds per million gallons 0.11982 Parts per million
Pounds C° units (PCU) 1.8 BTU
PSI 6.895 Kilopascals
PSI 0.0703 Kilograms / Square
centimetre
Quarts 0.946 Litres
Quarts 946.36 Millilitres
Quintal (Mexican) 101.467 Pounds
Radians 57.30 Degrees
Revolutions per minute 0.10472 Radians per second
Rods 16.5 Feet
Square centimetres 0.1550 Square inches
Square feet 929 Square centimetres
Square feet 0.0929 Square metres
Square inches 6.452 Square centimetres
Square kilometres 0.3861 Square miles
Square metres 10.76 Square feet
Square metres 1.196 Square yards
Square miles 640 Acres
Square miles 2.590 Square kilometres
Square miles 0.8361 Square metres
Tons (long) 1,016.0 Kilograms
Tons (long) 2,240.0 Pounds
Tons (metric) 6.297 Barrels of water @ 60° F
Tons (metric) 1,000.0 Kilograms
Tons (metric) 2,204.6 Pounds
Tons (metric) 1.102 Tons (short or net)
Tons (short or net) 0.9072 Tons (metric)
Tons (short or net) 907.18 Kilograms
Tons (short or net) 2,000.0 Pounds
Vara (Texas) 2.7778 Feet
Yards 0.9144 Metres

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WS-320-J FRACTION CONVERSIONS

Fraction Decimal MM Fraction Decimal MM

1 33
/64 0.015625 0.3969 /64 0.515625 13.0969
1 17
/32 0.03125 0.7938 /32 0.53125 13.4938
3 35
/64 0.046875 1.1906 /64 0.546875 13.8906
1 9
/16 0.0625 1.5875 /16 0.5625 14.2875
5 37
/64 0.078125 1.9844 /64 0.578125 14.6844
3 19
/32 0.09375 2.3812 /32 0.59375 15.0812
7 39
/64 0.109375 2.7781 /64 0.609375 15.4781
3 5
/8 0.125 3.1750 /8 0.625 15.8750
9 41
/64 0.140625 3.5719 /64 0.640625 16.2719
5 21
/32 0.15625 3.9688 /32 0.65625 16.6688
11 43
/64 0.171875 4.3656 /61 0.671875 17.0656
3 11
/16 0.1875 4.7625 /16 0.6875 17.4625
13 45
/64 0.203125 5.1594 /64 0.703125 17.8594
7 23
/32 0.21875 5.5562 /32 0.71875 18.2562
15 47
/64 0.234375 5.9531 /64 0.734375 18.6531
¼ 0.250 6.3500 ¾ 0.750 19.0500
17 49
/64 0.265625 6.7469 /64 0.765625 19.4469
9 25
/32 0.28125 7.1438 /32 0.78125 19.8438
19 51
/64 0.296875 7.5406 /64 0.796875 20.2406
5 13
/16 0.3125 7.9375 /16 0.8125 20.6375
21 53
/64 0.328125 8.3344 /64 0.828125 21.0344
11 27
/32 0.34375 8.7312 /32 0.84375 21.4312
23 55
/64 0.359375 9.1281 /64 0.859375 21.8281
3 7
/8 0.375 9.5250 /8 0.875 22.2250
25 57
/64 0.390625 9.92119 /64 0.890625 22.6219
13 29
/32 0.40625 10.3188 /32 0.90625 23.0188
27 59
/64 0.421875 10.7156 /64 0.921875 23.4156
7 15
/16 0.4375 11.1125 /16 0.9375 23.8125
29 61
/64 0.453125 11.5094 /64 0.953125 24.2094
15 31
/32 0.46875 11.9062 /32 0.96875 24.6062
31 63
/64 0.484375 12.3031 /64 0.984375 25.0031
½ 0.500 12.700 1 1.000 25.400

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WS-320-K TUBING TABLE

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WS-320-L LINE STRETCH DATA

The total stretch in the wireline is the length of the line in the well multiplied by the
average of the stretch in the first and last foot length.

The stretch factors have been calculated using the typical modulus values.

Temperature has been assumed to be constant.

For practical purposes, the material does not effect the results sufficiently to justify
various values.

The amount of stretch in solid wireline can be calculated from the following formula:

Total Stretch = F Wt + F (Wt + W1) x L

2

Where Total stretch is in inches:

F = Stretch factor, inches / feet / lbs
Wt = Weight of toolstring (lbs)
W1 = Weight of wireline in well (lbs)
L = Length of line in well (ft)

Example 0.092” line (API – 9A specifications) length 10,000 ft

Nominal weight is 22.69 lbs / 1,000’

W1 = 226.9 lbs
F = 6.8 1.0-5
Wt = 200 lbs

Total stretch = (6.8 x 10-5 x 200) + 6.8 x 10-5 (200 + 226.9) x 10,000
2

= 0.0136 + 0.0290 x 10,000

2

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WS-320-M ABBREVIATION

AHBKB Along Hole Below Kelly Bushing

AHD Along Hole Depth
BB Blind Box
BRA Bottom Hole Assembly
BHP Bottom Hole Pressure
BJ Blast Joint
BOP Blow-Out Preventers - Drilling or wireline type
BPV Back Pressure Valve
BRT Below Rotary Table
CCP Circulating Casing Pressure
CHH Casing Head Housing
CHS Casing Head Spool
CSG Casing (Csg)
CTU Coiled Tubing Unit
CV Check Valve
CWP Cold Working Pressure
DCSSV Direct Controlled Subsurface Safety Valve (also known as DCSSSV)
DN Deca Newtons
DSAF Double Studded Adapter Flange
EGP External Gravel Pack
ELEV Elevation - Rig floor to area point distance
EMR Electronic Memory Recorder
EU External Upset
FC Flow Coupling
FP Formation Pressure
FTP (FTHP) Flowing Tubing (Head) Pressure
GC Gauge Cutter
HCS Hydril CS
HSP Hydrostatic Pressure
HUD Hang (Hold) Up Depth - For clean tubing ID
ID Internal (Inside) Diameter
IGP Internal Gravel Pack
IN Improved Plow Steel
ITCP Integral (Integrated) Tubing Conveyed Perforator
KB Kelly Bushing
KN Kilo Newtons
KPa Kilopascals - Pressure rating
LIB Lead Impression Block
MAASP Maximum Allowable Annular Surface Pressure
MD Measured (Mean) Depth
MIRU Move In, Rig-Up
MPa Mega Pascals (KPa x 1,000)
NRV Non-Return Valve
NU Non-Upset
OD Outside Diameter
PCD Pitch Circle Diameter
POH (POOH) Pull Out Of Hole
psi Pounds per Square Inch
QLS Quick Lock System - Petroline
RDMO Rig Down, Move Off
RF Rig Floor
RIH Run In Hole
RT Rotary Table

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SCSSV Surface Controlled Subsurface Safety Valve (also known as
SCSSSV)
SICP (SICHP) Shut-In Casing (Head) Pressure
SITP (SITHP) Shut-In Tubing (Head) Pressure
SIWP (SIWHP) Shut-In Well (Head) Pressure
SPM Side Pocket Mandrel
SRO Surface Readout
SRT Sucker Rod Thread
SSD Sliding Side Door
SSSV Subsurface Safety Valve
SSV Surface Safety Valve
STD Standard
TBF Top (of) Bottom Flange
TBG Tubing (Tbg)
TC-P Tubing Conveyed Perforator
TD Total Depth
TH Tubing Hanger
THF Tubing Hanger Flange
THS Tubing Hanger Spool
TJ Travel Joint
TLV Threshold Limit Valve
TP Test Pressure
TRSV Tubing Retrievable Safety Valve
TVD True Vertical Depth
TWCV Two Way Check Valve
UNA Use No Abbreviations
UTS Ultimate Tensile Strength - Stress
VAM Vallourec Alexendre Madre - Premium thread
WOC Waiting On Cement - To set after cementing operations
wow Waiting On Weather - To clear and / or become less rough
WP Working Pressure

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WS-320-N METHOD TO DETERMINE TUBING OR CASING PRESSURE
DIFFERENTIAL

Casing/Tubing Differential

1) To Determine Hydrostatic Pressure in Tubing:

At SSD Depth:
(a) (7.91 kPa/m x 2551.18 m) + 6895 kPa
= 27075 kPa

2) To Determine Hydrostatic Pressure in Annulus

At packer depth 2560.32 m
(a) 11.3 kPa/m x 2560.32 m) = 28932 kPa

3) The Differential Pressure from Casing to Tubing

At SSD:
8932 kPa - 27075 kPa = 1857 kPa

Figure 1

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Tubing

1) To Determine Hydrostatic Pressure at 1600 m

(a) From the gas correction factor chart (P.B. 14.29.003 Item 2.0), find the gas
correction factor for 0.65 sg gas at 1600 m. In this case it happens to be
1.115.
The hydrostatic pressure at 1600 m = 1.115 x 3448 kPa = 3844 kPa.

2) Hydrostatic Pressure at SSD (2734 m)

(a) Fluid column between 1600 m and SSD is: 2734m-1600m=1134m
(b) Hydrostatic Pressure at SSD is
1134 m x 7.91 kPa/m = 8970kPa
Total pressure in tubing is:
8970 kPa + 3844 kPa = 12,814
kPa

Annulus

a. Gas pressure at 1600m:

1.115 x 3448 kPa = 3844 kPa

b. Hydrostatic Pressure at SSD is:

1134 m x 11.3 kPa/m brine = 12,814
kPa
Total casing pressure at SSD is:
12,814 kPa + 3844 kPa = 16,658 kPa
Tubing pressure at SSD is 12,814 kPa
Casing pressure at SSD is 16,658 kPa
Therefore, the differential pressure is:
16, 658 kPa – 12,814 kPa = 3844 kPa

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Chapter 20, Calculations, Conversions and Useful Engineering Data Page 20 of 29
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WS-320-O TABLE CHART OF GAS CORRECTION FACTORS

Well Depth Correction Factor

(Metre) 0.6 sg GAS 0.7sg GAS 0.8 sg GAS 0.9 sg GAS
1000 1.070 1.083 1.095 1.108
1150 1.082 1.096 1.110 1.125
1300 1.093 1.109 1.125 1.143
1450 1.104 1.122 1.141 1.160
1600 1.115 1.136 1.157 1.178
1750 1.127 1.150 1.173 1.196
1900 1.139 1.164 1.188 1.214
2050 1.150 1.177 1.205 1.233
2200 1.162 1.193 1.222 1.253
2350 1.174 1.208 1.239 1.272
2500 1.186 1.224 1.255 1.291
2650 1.198 1.241 1.272 1.312
2800 1.210 1.250 1.289 1.332
2950 1.223 1.265 1.308 1.352
3100 1.236 1.280 1.326 1.374
3250 1.248 1.295 1.344 1.395
3400 1.261 1.311 1.363 1.417
3550 1.274 1.327 1.382 1.439
3700 1.286 1.342 1.401 1.461
3850 1.301 1.358 1.420 1.483
4000 1.314 1.375 1.439 1.506
4150 1.327 1.392 1.460 1.529
4300 1.341 1.409 1.479 1.553
4450 1.355 1.425 1.499 1.578
4600 1.366 1.438 1.515 1.596

Multiply Surface Shut-In Pressure by the correction factor to obtain Pressure At Depth

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WS-320-P TABLE CHART OF FLUID GRADIENT CHART

API Gravity Fluid Gradient

(kPa/m)
60 7.232
55 7.435
50 7.639
48 7.707
46 7.797
44 7.887
43 7.933
42 Diesel 8.000
41 8.023
40 8.068
39 8.113
38 8.181
37 8.226
36 8.272
35 8.317
34 8.362
33 8.430
32 8.475
31 8.520
30 8.565
28 8.678
26 8.791
24 8.904
22 9.017
20 9.153
18 9.266
15 9.447
12 9.650
10 9.786

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WS-320-Q TABLE CHART OF WEIGHT OF FLUID IN KG/M³

Fluid Gradient Weight Fluid Gradient Weight

(kPa/m) (kg/m³) (kPa/m) (kg/m³)
9.996 999.6 16.773 1677.3
10.061 1006.05 17.013 1701.3
10.301 1030.08 17.253 1725.3
10.541 1054.11 17.494 1749.4
17.734 1773.4
10.781 1078.14 17.974 1797.4
11.022 1102.17 18.214 1821.4
11.262 1126.2 18.455 1845.5
11.502 1150.23 18.695 1869.5
11.743 1174.26 18.935 1893.5
11.983 1198.29 19.176 1917.6
12.223 1222.32 19.416 1941.6
12.464 1246.35 19.657 1965.7
12.704 1270.38 19.897 1989.7
12.944 1294.41 20.137 2013.7
13.184 1318.44 20.377 2037.7
13.425 1342.47 20.618 2061.8
13.665 1366.50 21.858 2085.8
13.905 1390.53 21.082 2108.2
14.146 1414.56 21.323 2132.3
14.386 1438.59 21.562 2156.2
14.626 1462.62 21.803 2180.3
14.867 1486.65 22.043 2204.3
15.107 1410.68 22.283 2228.3
15.331 1533.11 22.524 2252.4
15.571 1557.14 22.764 2276.4
15.812 1581.17 23.004 2300.4
16.052 1605.20 23.245 2324.5
16.292 1629.23 23.485 2348.5
16.533 1653.26 23.725 2372.5
23.966 2396.6

Note: Multiply Fluid Gradient by depth in feet to obtain Hydrostatic Pressure

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WS-320-R TABLE CHART OF FLUID WEIGHT CONVERSION CHART

WEIGHT FLUID WEIGHT FLUID

(Density) HEAD (Density) HEAD
Degress Specific Cubic Press. Degress Specific Cubic Press.
API Gravity Metre Per m API Gravity Metre Per m
Kg KPa Kg KPa
60 0.739 738.5 738.5 30 0.876 876.2 8.762
59 0.743 743.3 743.3 29 0.882 882.7 8.827
58 0.747 746.5 746.5 28 0.887 887.5 8.875
57 0.751 749.7 749.7 27 0.893 892.3 8.923
56 0.755 754.5 754.5 26 0.898 897.1 8.971

55 0.759 759.3 759.3 25 0.904 903.5 9.035

54 0.763 762.5 762.5 24 0.910 909.9 9.099
53 0.767 767.3 767.3 23 0.916 916.3 9.163
52 0.771 770.5 770.5 22 0.922 921.1 9.211
51 0.775 773.7 773.7 21 0.928 927.5 9.295

50 0.780 780.1 780.1 20 0.934 933.9 9.339

49 0.784 783.3 783.3 19 0.940 940.3 9.403
48 0.788 788.1 7.881 18 0.946 945.1 9.451
47 0.793 792.9 7.929 17 0.953 953.1 9.531
46 0.797 797.7 7.977 16 0.959 957.9 9.579

45 0.802 801.0 8.010 15 0.966 966.0 9.660

44 0.806 805.8 8.058 14 0.973 972.4 9.724
43 0.811 810.6 8.106 13 0.979 977.2 9.774
42 0.816 815.4 8.154 12 0.986 985.2 9.852
41 0.820 820.2 8.202 11 0.993 991.6 9.916

40 0.825 825.0 8.250 10° API 1.00 999.6 9.996

39 0.830 829.8 8.298 or Pure 1.01 1006.0 10.060
38 0.835 834.6 8.346 Water 1.03 1030.0 10.300
37 0.840 839.4 8.394 1.06 1054.1 10.541
36 0.845 844.2 8.442 1.08 1078.1 10.781

35 0.850 849.0 8.490 Salt 1.10 1102.1 11.021

34 0.855 853.8 8.538 Water 1.13 1126.2 11.262
33 0.860 858.6 8.586 1.15 1150.2 11.502
32 0.865 863.4 8.634 1.154 1153.4 11.534
31 0.871 869.8 8.698 1.18 1174.2 11.742

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WS-320-S TABLE OF DECIMAL EQUIVALENTS TO COMMON FRACTIONS

Table 5
1 13 25 37 49
= 0.015625 = 0.203125 = 0.390625 = 0.578125 = 0.765625
64 64 64 64 64
1 7 13 19 25
= 0.031250 = 0.218750 = 0.406250 = 0.593750 = 0.781250
32 32 32 32 32
3 15 27 39 51
= 0.046875 = 0.234375 = 0.421875 = 0.609375 = 0.796875
64 64 64 64 64
1 1 7 5 26
= 0.062500 = 0.250000 = 0.437500 = 0.625000 = 0.812500
16 4 16 8 32
5 17 29 41 53
= 0.078125 = 0.265625 = 0.453125 = 0.640625 = 0.828125
64 64 64 64 64
3 9 15 21 27
= 0.093750 = 0.281250 = 0.468750 = 0.656250 = 0.843750
32 32 32 32 32
7 19 31 43 55
= 0.109375 = 0.296875 = 0.484375 = 0.671875 = 0.859375
64 64 64 64 64
1 5 1 11 7
= 0.125000 = 0.312500 = 0.500000 = 0.687500 = 0.875000
8 16 2 16 8
9 21 33 45 57
= 0.140625 = 0.328125 = 0.515625 = 0.703125 = 0.890625
64 64 64 64 64
5 11 17 23 29
= 0.156250 = 0.343750 = 0.531250 = 0.718750 = 0.906250
32 32 32 32 32
11 23 35 47 59
= 0.171875 = 0.359375 = 0.546875 = 0.734375 = 0.921875
64 64 64 64 64
3 3 9 3 15
= 0.187500 = 0.375000 = 0.562500 = 0.750000 = 0.937500
16 8 16 4 16
61 31 63
= 0.953125 = 0.968750 = 0.984375 1.0
64 32 64

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WS-320-T METHOD FOR CALCULATING HYDROSTATIC PRESSURE

General

The hydrostatic pressure is the pressure created at a given depth by a column of fluid.
In the BSP Production Operations the fluid weight is measured by kPa/m (kilopascal
per meter).

1) To establish the hydrostatic pressure two factors are required.

(a) Fluid weight kPa/m.
(b) Depth of column of fluid.

2) After the known factors are established, multiply the fluid weight kPa/m by the
fluid column depth.
Note: The following illustrations and examples for determining hydrostatic
pressure.
Fluid weight Common to BSP Operations

9.7858 kPa/m = Clear Water

9.8536 kPa/m = Brine Water At 20°C
9.8988 kPa/m = Brine Water
Example A: 7-inch casing at 1,500 m

7 inch casing
1,500 metre

Figure 1
For Clear Water = 9.7858 kPa/m
9.7858 x 1500 = 14678.7 kPa hydrostatic pressure
For Brine Water = 9.8536 kPa/m
9.8536 x 1500 = 14780.4 kPa hydrostatic pressure
For Brine Water = 9.8988 kPa/m
9.8988 x 1500 = 14848.2 kPa hydrostatic pressure
Note: The hydrostatic pressure would be the same at any given depth
regardless of the casing size.

Example B: 9.3/8 casing at 1803 metre

For Clear Water = 9.7858 kPa/m

9.7858 x 1803 = 17643.8 kPa hydrostatic pressure

For Brine Water = 9.8536 kPa/m

9.8536 x 1803 = 17766.0 kPa hydrostatic pressure

For Brine Water = 9.8988 kPa/m

Figure 2 9.8988 x 1803= 17847.5 kPa hydrostatic pressure

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WS-320-U USEFUL TOOL DATA

General Tool Specification

GENERAL TOOL SPECIFICATION

Description Size Max. Length Top Fishing Remarks
(Ins) O.D. (Ins) Thread Neck
(Ins) (Ins) (Ins)
Impression Block
52 C 30 1 1.000 - 5/ –11
8 0.750
52 C 12 2½ 2.250 - 15/ – 10
16 1.750
52 C 16 3 2.620 - 11/16 –10 2.313
16 – 10
Spiral Brush 2½ 2.425 9 15/ 1.375
16 – 10
3½ 3.250 10 15/ 1.375
16 – 10
Quick Lock 1½ 1.500 10.625 15/ 1.375
2½ 1.825 9.00 11/16 – 10 1.750
‘B’ Down Shift Tool
142 B 04 2.375 2.108 18.31 15/ – 10
16 1.375 Will Pass Through 1.875 I.D.
142 B 03 2.875 2.592 18.94 15/ – 10
16 1.750 Will Pass Through 2.313 I.D.
142 B 01 3.500 3.023 18.94 11/16 – 10 2.313 Will Pass Through 2.750 I.D.
‘XO’ Selective Tool
42 XO 1 2.375 2.156 12.06 15/ – 10
16 1.375 Will Pass Through 1.875 I.D.
42 XO 7 2.875 2.656 12.75 15/ – 10
16 1.750 Will Pass Through 2.313 I.D.
16 – 10
42 RO 25600 3.500 3.000 13.26 15/ 1.750 Will Pass Through 2.562 I.D.
42 XO 18 3.500 3.031 13.44 11/16 – 10 2.313 Will Pass Through 2.750 I.D.
‘BO’ Up Shift Tool
42 BO 116 2.375 2.108 13.30 15/ – 10
16 1.375 Will Pass Through 1.875 I.D.
42 BO 118 2.875 2.592 13.94 15/ – 10
16 1.750 Will Pass Through 2.313 I.D.
16 – 10
42 BO 178 3.500 2.966 13.94 15/ 1.750 Will Pass Through 2.562 I.D.
42 BO 146 3.500 3.015 14.19 11/16 – 10 2.313 Will Pass Through 2.750 I.D.
Flo. Rel. O/Shot
M 808 433 2.375 1.875 20 15/ – 10
16 1.375
M 808 450 2.875 2.250 20 15/ – 10
16 1.375
3.500 2.815 20 11/16 – 10 1.750
4.000 3.312 20 11/16 – 10 1.750

Running Tool Specification

RUNNING TOOL SPECIFICATION

Description Size Max. O.D. Length Top Thread Fishing Neck Remarks
(Ins) (Ins) (Ins) (Ins) (Ins)
GA-2 Running Tool 1.187 1.187 4.375 15
/16 – 10 1.187 -
Assy. No: 15052
RK-1 Running Tool
Assy. No: 15079 1.437 6.000 15
/16 x 10 1.187 Install RK Latches
‘DO’ Running Tool
Assy. No: 41 DO 10 2 1.375 13.44 15
/16 – 10 1.375 Neck 1.06 Runs F/N
Assy. No: 41 DO 11 2½ 1.750 13.75 15
/16 – 10 1.750 1.38
Assy. No: 41 DO 9 3 2.000 16.88 11/16 – 10 1.750
X Running Tool Assy. 2 Dogs Out 1.943 29.56 15/
16 – 10 1.375 Bottom Thread ½”-13
No: 41 x 05 Dogs In 1.772
Assy. No: 41 x 06 2½ Max OD Dogs Out 2.380 31.25 15/
16 – 10 1.750 Bottom Thread 5/8-13
Max OD Dogs In 2.209
Assy. No: 41 x 066 3 Max OD Dogs Out 2.840 32.06 1/
16 – 10 2.313 Bottom Thread ¾-10
Max OD Dogs In 2.72
‘RXN’ Running Tool 2½ Max OD Dogs Out 2.692 31.2 15/
16 – 10 1.750 Bottom Thread 5/8-11
Assy No: 41 RO Max OD Dogs In 2.50 Runs Fishing Neck 1.81
25601
Assy. No: 41 RXN 4½ Max OD Dogs Out 4000 26.82 11/16 – 10 2.313 Bottom Thread 21/8
41230 Runs Fishing Neck 3.12

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Description Size Max OD Length Top Thread Fishing Remarks
(Ins) (Ins) (Ins) (Ins) Neck
(Ins)
Gauge Cutter 2 1.537 6¼ /16 – 10
15
1.183
2 1.600 7 /16 – 10
15
1.183
2 1.625 8½ 15
/16 – 10 1.183
2 1.718 8½ 15
/16 – 10 1.183
2½ 1.912 8½ 15
/16 – 10 1.375
2½ 2.346 8½ 15
/16 – 10 1.750
3 2.800 8½ 11/16 – 10 2.314
3 2.848 8½ 11/16 – 10 2.314
Wire Scratcher 2 Order by Job 20 15
/16 – 10 1.375
2½ Order by Job 20 15
/16 – 10 1.375
3 Order by Job 20 15
/16 – 10 1.375
‘T’ Running 2 1.750 8.00 15
/16 – 10 1.375
2½ 2.250 8.00 15
/16 – 10 1.375
3 2.740 9.00 11/16 – 10 1.375
Sand Bailer 2 1.625 87.50 15
/16 – 10 1.375
2½ 1.625 87.50 15
/16 – 10 1.375
Hydrostatic Bailer 50 2 1.625 71.60 15
/16 – 10 1.375
BO 8
Wire Grab 2
2½
3
Blind Box 1 1.000 8.88 5
/8 –11 NC 0.750
1½ 1.500 8.88 15
/16 – 10 1.375
2½ 2.000 9.25 15
/16 – 10 1.750
3 2.620 9.00 11/16 – 10 2.313
3 2.750 9.00 11/16 – 10 2.313
4 3.250 9.00 11/16 – 10 2.313
‘O’ Bannon O/Shot 2 1.865 13.0 15
/16 – 10 1.375
2½ 2.250 13.0 15
/16 – 10 1.375
3 2.731 15.0 11/16 – 10 2.313
Amerada Pressure &
Temperature Gauge
RPG-3 1.250 1.250 77.250
RT-7 1.250 1.250 67.0
Bowen Wire Finder - 1.850 36.0 15
/16 – 10 1.375
-
Go-Devil 2 1.500 18.0 1.375 Bottom Flat Mule
2½ 1.500 24.0 -
1.375 Show. No-Go or
Bull Nose
Shut Off Tool
Assy. No: 13220 - 2.187 20.531 1¾-1215/16 – 10 -
Assy. No: 13009 2.718 15.6 2¼ SLB 15/16 – 10
SOF Running Tool 3 2.750 51.12 11/16 – 10 2.313
41 SO 56
XO B-7 Running Tool 3 2.840 32.06 11/16 – 10 2.313
41 XO 66
JK-2 Running Tool 1.307 1.375 4.56 15
/16 – 10 1.187 Installs BK-2
15072 Laches

Assembly Nominal Size Maximum Fishing Neck (Ins) R-reach Top Prong Shear Pin
No (Ins) O.D. (Ins) On Tool Willengage (Ins) Thread Thread (Ins)
(ins) (Ins)
JDC 15151 1¼ 1.281 1.187 0.875 1.937 15
/16 – 10 - 3
/16
JDC 15156 2 1.859 1.375 1.375 1.438 15
/16 – 10 ½ - 13 5
/6 x 13/8
JDC 15158 2½ 2.250 1.375 1.750 1.313 15
/16 – 10 ½ - 13 5
/16 – 113/16
JUS 15196 2 1.859 1.375 1.375 2.125 15
/16 – 10 ½ - 13 5
/6 x 13/8
JUS 15198 2½ 2.250 1.375 1.750 2.188 15
/16 – 10 ½ - 13 5
/16 – 113/16
Petroline 2½ 2.250 1.375 1.750 - 13/8 – 10 - -
410 – 1750.00

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Chapter 20, Calculations, Conversions and Useful Engineering Data Page 29 of 29