SPE 23250

An Integrated Approach to the Safety of Surface Well Testing on

Mobile Offshore Rigs
J-P.A. Oilier, Schlumberger Technical Services; B.R. Imrie, * Schlumberger Inland Services;
and R.E. Talbott, Schlumberger Technical Services
'SPE Member

Copyright 1991, Society of Petroleum Engineers, Inc.

This paper was prepered for presentation at the First International Conference on Health, Safety and Environment held in The Hague, The Netherlands, 10-14 November 1991.

This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper,
as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect
any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society
of Petroleum Engineers. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment
of where and by whom the paper is presented. Write librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836 U.S.A. Telex, 730989 SPEDAL.

ABSTRACT
The risk inherent to any production operation is the
Offshore well testing during the exploration and appraisal uncontrolled release of hydrocarbons into the atmosphere
phases requires the production of hydrocarbons, often at high which may lead to explosion, fife, toxic effects and pollution.
pressure, through a temporary system set up on a mobile
offshore rig. These operations require the operator, the drilling This study uses the production systems and safety standards of
company and the testing company to reconcile the three key fixed offshore production platforms as a reference to analyze
issues of keeping risk as low as reasonably achievable, the testing systems and procedures used on mobile rigs. The
collecting as much information as possible and limiting cost analysis focuses on coping with logistical constraints while
maintaining standard drilling safety practices as well as the
The process equipment designed and manufactured for safety standards associated with the production operation. The
permanent installations is compared to those used on mobile second part of the study reviews the interaction required
offshore rigs. The associated risks are analyzed. Standards of between companies to plan and perform the test. Conclusions
professional training and experience are discussed. are then drawn concerning the risk level of well testing on
mobile offshore rigs, the importance of professional input and
The interaction required for test acceptance, job planning and the need to reinforce the formalization of companies
job execution is described. This interaction involves the interaction and safety integration.
operator, the testing company, the drilling company,
regulatory bodies and certifying authorities. Potential
improvements are proposed. BACKGROUND:

Well Testing Schematic and History

INTRODUCTION
Prior to the development of the crude oil burner, it was
Surface well testing consists of flowing fluid from the difficult to test oil wells offshore because the oil had to either
reservoir through the wellbore and a production string, to the be stored on the platform or pumped into a tanker. Storage on
surface. At the surface, fluid samples are collected for analysis the platform was and is not feasible and using a tanker is
and the rest of the effluents are disposed of. Several impossible in rough seas. The only wells which could be
measurements such as flow rates and pressures are made and tested offshore were gas and or gas condensate wells where the
interpreted to help characterize the reservoir and design the liquid hydrocarbons could be burned. The first offshore crude
production facilities. oil burner was brought on line to test the first large oil
discovery in the North Sea, the Ekofisk field, in 1969.

Production testing on semi-submersibles and drillships was

also difficult until the development of a suitable device to
disconnect and reconnect the production string inside the
References and illustrations at end of paper.

447
 2 AN INTEGRATED APPROACH TO TIlE SAFETY OF SURFACE'WELLTESTING ON MOBIlE OFFSHORE RIGS SPE 23250

blowout preventer located on the seabed, as shown in Figure The safety system should provide two levels of protection
2. This development not only improved the safety aspects of which should be independent of and in addition to the control
the test, it also allowed for the safe operation of wireline devices used in normal operation.
conveyed devices to monitor downhole well test data in real Note: "overpressure" is an example of an undesirable event
time and for the use of coiled tubing for stimulation
operations. Safety analysis techniques will determine, using a Safety
Analysis Table (SAn, the minimum safety requirement for a
There are two kinds of production test systems used on component as an independent unit of the system. When
mobile offshore rigs. One of these is the conventional testing process components are fully protected and combined into a
system used to test exploration and appraisal wells. The production system, no additional threats are created. Therefore,
systems are in operation approximately 500 times per year on if all process component safety devices are logically integrated
mobile offshsore rigs outside North America and represent the into a safety system, the entire facility will be protected. This
bulk of mobile offshore testing systems. A typical offshore is controlled through Safety Checklists (SAC) and a Safety
setup of a conventional testing system is shown in Figure 1. Analysis Function Evaluation (SAFE) whose completion
The other type system is called an Extended Well Test System provides a means of verifying the design logic of the basic
(EWn or Early Production Facility (EPF). These systems safety system.
may have some components of conventional testing
equipment and some semi-permanent components. There have Emergency Support Systems (ESS) minimize the effect of
been approximately 30 extended well tests/early production escaped hydrocarbons on production facilities. They include
facilities installed since the technique was developed in the the Emergency Shut Down System (ESD) to provide a
mid-seventies. The production capacity of these systems method to manually initiate production system shutdown by
ranges from 10,000 BOPD to 30,000 BOPD. Some of them personnel observing abnormal conditions or undesirable
have been in operation for weeks while others have been, and events. The Subsurface Safety Valves (SSSV) which may be
still are, in operation after several years. These extended tests self-actuated or activated by the ESD system or a fire detection
or early production facilities allow the operator to gather system. The containment system to collect escaped liquid
information about the reservoir (i.e. boundaries, hydrocarbons and initiate shutdown. Combustible gas
heterogeneities, drainage systems) while producing the detection and fire detection devices to trigger alarms and/or
reservoir. These systems are used while the reservoir is being shutdown.
analyzed, prior to making a final commitment on field
development or while permanent production facilities are
being designed and constructed. Such systems have to be MOBILE RIG INSTALLATIONS COMPARED TO FIXED
engineered and mobilized much quicker than permanent PLATFORM SYSTEMS. AS A REFERENCE
facilities (15 to 20 weeks against 15 to 20 months). They are
considered as being as safe as permanent systems. Since these The production system, from reservoir up to hydrocarbon
systems represent a middle-of-the-road approach, they will not processing, storage and disposal, is made of similar basic
be discussed further. components whether it is designed for commercial production
or for testing the discovery well.
Safety In Production Systems:
Protection Conce.Pts - Safety Analysis Having briefly reviewed the objectives, history and evolution
Emergency SUQPOrt Systems of offshore testing, having as well stated the protection
concepts and safety analysis applying to any production
Most threats to safety and environment protection from a system, we now analyze its main components:
production system involve the release of hydrocarbons. Thus,
the analysis and design of a production system should focus - Wellheads and upstream safety barriers.
on preventing such releases, stopping the flow of - Piping systems.
hydrocarbons if it occurs, and minimizing the effect of - Process equipment.
hydrocarbons that are released. - Storage - disposal.
- Emergency support systems.
The basic protection concept used in the safety system
analysis consists in identifying each undesirable event that Production facilities on fixed platforms represent the state-of-
could affect a component of the system. Undesirable events the-art in terms of safety standards and environmental
are analyzed according to: constraints. Their production systems are built for decades, to
operate round the clock in any weather condition.
- Their cause. Recommended practice for their design and installation is
outlined in API 14 E. Recommended practice for analysis,
- Their effect and detectable abnormal conditions. design, installation of basic surface safety systems is outlined
in API 14 C. It will be our reference.
- The kind of primary and secondary protection which should
prevent or react to their occurrence. The production system used for testing a discovery or an
appraisal well is made of components which are rigged up
only for the purpose of this test, as shown in Figure 1. The

448
 SPE 23250 J.P.OLLIER B. IMRIE' R. TALBaIT 3

setup will be subsequently dismantled when the well is Downhole testing techniques like drillstem testing are adding
plugged and abandoned. one more safety barrier close to the hydrocarbon reservoir.
Consequently, there are more safety barriers in temporary
Wellheads And UPstream Safety Barriers production strings upstream of the wellhead than on fixed
production platforms. Some of these protections are integrated
Christmas trees on permanent installations and flowheads on to the drilling safety systems, inside the BOP stack which
temporary setups provid.e the same wellhead function. They provides the additional annulus protection above the downhole
allow a shutdown of the production string at surface. Both are packer.
designed and manufactured as per the specifications of API 6
A as a minimum requirement Both have at least one remotely Piping Systems
controlled valve connected to an emergency support system.
Their differences are the result of different logistical On production platforms, piping systems are designed to
constraints. handle the maximum flowrate expected during the lifetime of
the facility. It is also advisable to add a surge factor of 20 to
Christmas trees are flanged on top of the tubing hanger and 50 per cent unless surge expectations have been more
only have to support their own weight. Flowheads, on the precisely determined. Both flow velocity and pressure drop
other hand, are screwed on top of the last tubing or drillpipe. should be considered for liquid lines, single phase gas lines,
During drillstem testing, they have to support the weight of and gas/liquid two phase lines, respectively. Design and
the whole drilling string and allow rotation of that string installation is as per API 14 E recommended practice as a
under pressure. Because of its position above the rig floor and minimun requirement
its screwed bottom connection, a flowhead has weight and
compactness constraints. In this respect, the choke controlling Setting up temporary piping systems on mobile offshore rigs
the flowrate, which is normally part of a Christmas tree, is creates several challenges. The rig may have no permanent
not mounted on the flow head. Consequently, wellhead production flowlines at all. Some areas of the deck may be
pressure has to be brought from the flowhead to the choke out of reach for rig cranes and derrick catlines. Deck space,
manifold on the rig floor through a flowline. particularly on small jack-up rigs, is scarce which means that
process equipment such as choke manifolds, heat exchangers,
Offshore, producing wells are equipped with a subsurface separators and gauge tanks may very well be scattered around.
safety valve located below the sea bed. It closes the well in a Such an environment implies the following constraints for
fail-safe mode should the production string be damaged or the piping system:
destroyed above the mud line. It is also surface controlled and
integrated to the emergency support system. Fire detectors, The layout can very seldom be accurately determined and or
high-low pressure sensors and emergency shutdown systems pre-assembled onshore. Each piece of pipe is to be hand-
will trigger the closing mechanism. carried and assembled by no more than two or three people.
That is a pipe weight constraint. Pipes are assembled using
Temporary production strings provide at least one safety quick connections because of time and manpower constraints.
barrier upstream from the flowhead: The standardization on H2S-Proof equipment for most
exploration tests has resulted in the elimination of chicksan-
A lubricator valve, located a few feet below the rig floor, type articulated piping. They have been replaced by scores of
allows electrical or mechanical wireline tools to be run in the 90° elbows and straight pipes assembled by quick
production string. It can be closed from the rig floor and acts connections. A simple 3-in. nominal 90° elbow with its quick
as a safety barrier should any leak or rupture occur at or below connection weighs between 30 and 50 Ibm according to its
the flowhead. It can subsequently be pumped open by the rig working pressure. A simple 3-in. nominal 6 ft straight pipe
mud pumps to circulate and control the well. connection weighs between 80 and 150 Ibm. A standard 2,000
ft piping setup will amount to more than 300 different pipes
In addition, on floating rigs, a subsea test tree is positioned and 300 connections. It requires about 16 man/days to rig up
inside the drilling BOP stack. This device has three and subsequently 12 man/days to pressure test In the North
simultaneous safety functions: Sea, each piece of piping has to be traceable and recertified on
a regular basis. High temperature production tests require the
a) To allow a quick disconnection of the production string elimination of elastomeric seals in the quick connection. They
should the rig need to move off location in an emergency are replaced by metal to metal seals associated with different
(less than 20 seconds). types of screwed connections or clamping devices.

b) To cut any cable or coil tubing which happen to be inside Today, the flowline connecting the flowhead outlet to the
the production string at the time of disconnection. choke manifold is a flexible pipe composed of unbonded
layers of plastic and steel. Maximum allowable working
c) To plug the production string left downhole and, through a pressure can be up to 15,000 psi and its maximum operating
retainer valve, to plug the upper part of the string just temperature up to 160°C. For an internal diameter of 2.8-in.,
above disconnecting point. This prevents dumping an external diameter of approximately 6-in., it weighs nearly
hydrocarbons into the sea. Liquid would pollute the 40 lbm/ft Since it is located on the rig floor, it is easily
environment, gas would be a threat to the rig safety. moved and handled.

449
 4 AN INTEGRATED APPROACH TO mE SAFETY OF SURFACE WELLTESTING ON MOBllE OFFSHORE RIGS SPE 23250

An alternate solution is to have at least part of the piping 10,000 BOPD assuming a one minute retention time. While
system permanently installed on board the drilling rig. It can in operation. normally for flowing periods not exceeding a
be designed, particularly the low pressure side of the system, few hours, test separators are continuously manned. In this
in larger sizes, with less elbows and with proper supports in type of environment, the field experience of specialists can
order to restrict vibrations. Piping has to be inspected after hardly be replaced by automated equipment and pre-established
each production test in order to detect any erosional damage computer programs.
resulting from well clean up or sand production. Such an
integrated setup is normal practice on Norwegian rigs where Storage - Disposal
most of the process equipment like steam exchangers,
separators, burner booms remain permanently rigged up. In On platforms. besides engine fuel. there is no storage of
other areas, some semi-submersible rigs have part of the hydrocarbons. Both gas and liquids are segregated and pumped
piping and burner supporting booms permanently installed. It through monophasic pipelines to onshore storage facilities.
is seldom the case with jack-ups owing to rig space and rig Tankers may provide some intermediate crude oil storage.
move constraints. particularly for extended well tests or early production
facilities.
A temporary piping system is a containment system as safe
as permanent piping provided it is inspected after each job and On mobile offshore rigs, whatever the type of test. gas is
pressure tested before each job. However, even though it is flared. During exploration tests, storage of large quantities of
common practice that flow velocity may exceed. for short crude oil on the rig deck would be hazardous in terms of risk
periods, the limits set for permanent installations (provided of explosion and fire and limited in terms of deck space and
sand is not produced), the flowing capacity of the whole deck load. Disposal through floating storage facilities would
production system may be restricted, and rigging up and be uneconomical as regards mobilization costs. eventhough
pressure testing the system are time-consuming. technically feasible. Such an environment implies that today
liquid hydrocarbons are disposed of through crude oil burners.
Process Equipment
Emergency Shutdown Systems
For a given process capacity. the design and manufacturing of Pressure Relief Systems
separators is very similar, whether they are part of a fixed
platform setup or mobile separators. The reference is ASME The operating mode of the system is as per API RP 14 C
Section VIII, division 1 and 2 and NACE MR 0175 as a minimun requirements:
minimum requirement. Their difference is in the degree of
automation and packaging. - Automatic monitoring and automatic protective action if
an abnormal condition indicating an undesirable event can
On platforms. process equipment is tailored to the field be detected by a sensor.
characteristics. that is operating pressure, flow rates. gas oil
ratio, water oil ratio. in order to optimize the hydrocarbons - Automatic protective action if manually actuated by
recovery. Mobile test separators are designed to cope with 90 personnel who observe or are alerted to an unsafe condition
per cent of unknown flowing conditions. which may as well by an alarm.
include exposure to mud, sediments and debris. They need to
be ruggedized in order to endure transportation on supply boat - Continuous protection by support systems that minimize
decks and offloading on rigs in almost any weather condition. the effects of escaping hydrocarbons.
Then. they may remain stored on the deck, unattended for days
or weeks and nevertheless they have to be ready to operate in a Considering the relatively short flowing periods in
matter of hours. Such an environment implies the following exploration testing. from a few hours to 48 hours as a
constraints: maximum, and the potentially unstable flowing conditions,
safety system operating modes are essentially based on
- Equipment must be light enough to be moved by the rig personnel. There are only a limited number of sensors,
cranes. basically pressure safety low pilot and pressure safety high
pilot, located between flowhead and test separator, that will
- Equipment must be rugged enough to withstand offshore automatically shutdown the flow at and below the flowhead in
transport and offshore storage. This prohibits the use of case of flowline rupture or plugging. Any other shutdown is
most electronic equipment in remote locations. manually actuated either from the emergency shutdown panel
or from selected remote manual ESD stations. As a secondary
- Equipment must be versatile in terms of gas and liquid protection against overpressure. pressure safety valves located
capacity in order to cope with unknown flowing on each pressure vessel can release the flow overboard through
conditions. relief lines.

The standard test separator is the process equipment

centerpiece. It weighs between 10 and 15 tons empty, with its
protecting frame. It can handle a well effluent composed of
three phases: gas. oil and water. It is designed for a maximum
gas capacity of 60 MMSCFD or a maximum oil capacity of

450
 SPE 23250 IP. OILIER. :8'. IMRIE . R. TALBaIT 5

COMPANIES INTERACTION - When the surface testing is equipped with a computerized

acquisition system, the test supervisor monitors the well
Well testing requires very thorough and formalized job parameters on a screen and visual/audible alarms warn him
preparation and a high degree of coordination between the in the event of abnormal pressures and temperatures.
parties involved (Table 1).
- In exploration, the test separator is permanently manned
Well Test Planning: Oil Company - Testing Company during the whole flowing period. Non-recurrent operations
like oil meter gauging, surface sampling, oil pumping are
The oil company generally indicates the well test objectives manned too.
such as number of reservoirs (zones) to be tested and the
measurements they would like to obtain (i.e. productivity - The initial training of personnel and subsequent advanced
index, wellbore damage, permeability, reservoir fluid sample). courses are based on surface testing simulators reproducing
They also provide information on operating parameters such various operating conditions and undesirable events in the
as bottom hole pressure and temperature at reservoir depth, learning center. Nevertheless, exploration well testing
estimated maximum pressure and temperature at the wellhead requires extended and varied field experience since it
when the well is shut in, estimated pressure and temperature basically implies managing the unexpected in real time.
when the well is flowing at the expected maximum rate,
estimated gas oil ratio, hydrogen sulfide, carbon dioxide
content, etc. This information is based on previous experience CONCLUSION AND POSSIBLE FUTURE TRENDS
with tests in nearby wells, tests in identical reservoirs or from
simulation. The development of technologies and procedures for testing
wells on mobile offshore rigs has advanced such that these
Objectives and operating parameters are consolidated into a operations may be considered as safe as those associated with
test program, compatible with the testing equipment permanent production platforms.
specification, ratings and safety systems.
The testing wellhead and downhole safety systems are fully
Well Test DesiW: TestiDl~ CompanY - Oil Company And/Or integrated to drilling company systems. This integration could
Certifying Autority On Behalf Of Regulatory Body be improved with regards to the piping systems in order to
reach larger production capacities and decrease rig up time.
The testing company will take these objectives and operating
parameters and develop an engineering design for the test. The human experience in exploration tests still proves to be
Figure 3 is an example of a well test equipment layout. This superior to any fully automated device, owing to the hardly
design will show if there are any testing equipment predictable flowing patterns of exploration wells. Personnel
limitations which may be caused by pressure, temperature, are trained on simulators but nevertheless need extended and
flow rates, sand production, etc. The design will also take into varied field experience.
account limitations imposed by local regulations or certifying
authorities. The amount of detail and the degree of Certifying authorities today, in areas like the North Sea, are
formalization of the test design documents are largely the link between the oil company, the drilling company and
dependent on specific client requirements. The involvement of the testing company. They have contributed to the
certifying authorities has helped formalize the language and standardization of the safety integration between companies by
the methods used in the test design. These standards are using the methods prevailing on permanent systems. In areas
detailed in the API 14 C. where certifying authorities are not directly involved, the same
level of safety awareness is expected. In these areas,
Qperating And Safety Procedures - Personnel Role In Safety: formalization of the safety integration would represent a
Oil Company - Testing CompanY - Drilling Company definite improvement by decreasing the risk level through
better communication.
The oil company verifies that operating procedures and
The future of testing will be to limit or avoid hydrocarbon
position description of both testing and drilling crews are
production at the surface on mobile offshore rigs. This can be
compatible and well understood by the other party. In this
achieved through high stability, high resolution pressure
respect, the personnel role in safety and operation is a key
gauges which may provide reliable pressure transient
issue.
measurements and productivity index evaluation at low surface
flowrates. Testing could then be performed through smalllD
The emergency shutdown panel is the center of the well
tubings or even coil tubing. New advances in formation tester
testing safety system. It is located next to the driller's
technology have improved the measurement of reservoir
doghouse. It is permanently manned, not only during flowing
flowing capacity and may eventually provide enough
periods but as soon as the subsurface test tree is screwed onto
information and valid fluid samples to avoid any production to
the production string until it is pulled out. This function is
surface during the exploration phase.
absolutely integrated to the rig safety system, as described in
the downhole safety barriers paragraph.

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6 AN INTEGRATED APPROACH TO TIlE SAFETY OF SURFACE WELLTESTING ON MOBILE OFFSHORE RIGS SPE 23250

ACKNOWLEDGMENT

Cooperation from Christian Romano, Head of the Surface

Well Testing Field Support Group of Schlumberger, Division
Flopetrol, and from Andre Rocklin, with Testing and
Production Services at Schlumberger DUbai, are gratefully
acknowledged.

REFERENCES

1. American Petroleum Institute, API 6A, "Specification

For Wellhead And Christmas Tree Equipment", sixteenth
edition, October 1, 1989.

2. American Petroleum Institute, API 14C, "Recommended

Practice For Analysis, Design, Installation And Testing
OfBasic Surface Safety Systemsfor Offshore Production
Platforms", fourth edition, September I, 1986.

3. American Petroleum Institute, API 14E, "Recommended

Practice for Design And Installation Of Offshore
Production Platform Piping Systems", fourth edition,
April 15, 1984.

4. Schlumberger Educational Services, Testing Services

Catalog, copyright 1990.

5. Flopetrol, Field Operating Handbook: Well Testing.

6. de Fleurieu R., Williams J. A., Reverdito G.:

"Management of Safety And Environment Risks In An
Oilfield Service Company", paper SPE 23493 presented
at the First International Conference on Health, Safety
and Environment in Oil and Gas Exploration and
Production, The Hague, The Netherlands, 11-14
November 1991.

452
 SPE 23250

TABLE 1

Companies Interaction

Qil Thslini .Imllini r&aif.

Ql Ql Ql A!llh.
1 Well Test Planning

• Well test objectives X X

• Well parameters X X
• TestProgram X X

2 Well Test Pesign

• SUIface layout diagmm X X

• Proeess and insttumentation diagmm and data sheets, X X
pressure drop calculations
• Summary of pressure and temperature limitations X X
• Verification through: X X
Safety Analysis Tables (SAT)
Safety Analysis Checklist (SAC)
Safety Analysis FWlCtion Evaluation (SAFE)

3 Operating and Safety Procedures

• Operating procedures and position description for

perronnel X X X
• Emergency/contingency procedures X X X
• Verify logic of system safety integmtion with
drilling company including emergency shutdown X X X X
• Verify fll'e fighting procedure, adequacy of rig
structure to suppon testing equipment X X X

4 Commjssjonjog

• Hydrostatic pressure testing to be logged in Rig's

LogBook X X X X

Well Testing Schematic

·;;.
o GAS • WELL STREAM

Fullbore Test String Surface Equipment

1. Firing head 12. Hose bundle

I
2. Perforated tailpipe • 13. E-Z TREE control unit and
3. PosiTest packer glycol injection pump . ,
\/7 1.. .•
4. Hydraulic jar 14. Flow head
15. Flow head safety valve
5. Pressure recorders
6. Test valve 16. Wireline wellhead equipment
-,
17. Offshore wireline unit with "1
7. Reverse valves
• COMPUTEST system
" -,1
Subsea Safety Equipment 18. Data acquisition units
• 8. E-Z TREE-Safety valve 19. Emergency shutdown
latch assembly with glycol system
injection system 20. Data header
9. Retainer valve 21. Choke manifold 7
10. Deep sea hydraulic control 22. Steam exchanger 6
pod 23. Three-phase separator
5
11. Lubricator valve 24. Oil manifold
25. Surge tank 4
26. Transfer pump 3
27. Air compressor
2
28. Gas manifold
29. Supporting boom 1
30. Burner
Figure 1
Well Testing Schematic

• Mark of Schlumberger

453
 SPE 23250

Hydraulic Control
Hose Reel Console Accumulator
Skid Unit

1---- 1 Stand of 11 Retainer Valve

DrillpipelTubing Closed
1---- Lubricator Valve
(Closed)

IIW.L,m,--- Riser
1[1;01---- Hose Protector Disconnected
1---- Hydraulic
Control Pod

~I++ Retainer Valve

(Open)

I+i----- E-Z Tree

Latch Assembly Rams Closed

I~H-+---- E-ZTree Valves

- E-Z Tree
1++--- Valve Assembly Closed
U-:-~-- Slick Joint

lr---r,-+--- Fluted Hanger

Figure 2
Subsea Test Tree Assembly

- Mark of Schlumberger

454
 SPE 2}250

PRELIMINARY
PROPOSAL
.--
FWD

N O£CK-HAZAROOUS ARE

lI1:LIlDlS
WORKSHOP I ACCUNIJl.\TORS
I
;._- _._ VENT _._._._._._.
_-_ LINE 10 BOOMS __ ._._._._.~._-_._._.- .. - _--.- -_ __ .

TL:!=----'!:::::=:.::r----- :-----,

RISER DECK

\
:.. .•. -!

\ ) \
Figure 3

Well Test Equipment Layout

SIZE WEIGHT WORKING

ITEM DESCRIPTION
L W H (KG) PRESSURE

1 CHOKt MANlF'OLD 7'IY' ''0'' 4'0" 3000 15K

2 STE-AM EXCHANGE' 20'0" &'S" S"O.. '&000 1OK/3200

3 SEPARArOR '6'6' TJ" S',," '&000 ,4-iO

4 SURGE TANK Iw 6'0" 2Q·0· 'elIOO 50

5 TRANsrER FJU~P J'O" J'O" 3'OM 100 '00

6 OIL MANIF'OlO 4',0' 2·.... "J" '00 1440

STE-AM GENERATO!' 19'0" 6' g' 16000 '50

7
8 COUPRESSQRS '5'0' 7'0" &'0" &000 .SO

9 SAFETY VALVE 3"" J"O' 7'J" 1500 15K

10 DATA HEADER ."" "0" 7'2" 1000 15K

--
•...•..
HYDROCARBON
LINE:S
VENT LINES

+
~
H'f't)RAULIC liNtS
PILOT LINts

NOTt ;- WEIGHT AS GNEN A8O'v't tS "WET WEIGHT", i.e. WEICHT OF' EQUIPMENT WHE
ruu.
OF' fRESH WA.ltR.

455