Stimulation I

Student Workbook

Developed by
Halliburton Energy Institute

© 2003 Halliburton Company, All rights reserved

Printed in the United States of America
Notices

Confidentiality
All information contained in this publication is confidential and proprietary
property of Halliburton Energy Services, a division of Halliburton Company. Do
not transfer this document outside of Halliburton without approval from the
Intellectual Property Group of the Law Department.

Document History
First Release: December 2001
Revised: August 2002
Revised: November 2004
Revised: March 2005

Acknowledgements:
HEI would like to thank the following for their contributions to this manual (in
alphabetical order):
Billy Almon, Jeff Fleming, Kathy Mead, Von Parkey, Max Phillipi, Sherry Snyder,
Mark Suttle, and Chris Talley

Stimulation I
Table of Contents

Section Subject
1 Introduction
2 Calculations
3 Blenders and Auxiliary Equipment
4 High Pressure Pumping Equipment
5 Manifold Equipment
6 Fracturing Fluid and Materials
7 Nitrogen/Carbon Dioxide
8 Chemical Stimulation
9 Proppants
Section 1

Introduction to Stimulation

Table of Contents
Introduction................................................................................................................................................1-3
How This Course is Organized ..............................................................................................................1-3
Study Suggestions ..................................................................................................................................1-4
The Purpose of Stimulation in an Oil Well................................................................................................1-5
Delivering Quality and Value.................................................................................................................1-5
Halliburton and the Drilling of an Oil Well ...............................................................................................1-6
Drilling Operations.................................................................................................................................1-6
Running Drill Pipe .................................................................................................................................1-6
Running Surface Casing.........................................................................................................................1-7
Cementing ..............................................................................................................................................1-8
Tripping In............................................................................................................................................1-10
Running and Cementing Intermediate Casing......................................................................................1-10
Drilling To Final Depth........................................................................................................................1-10
Completing the Well ............................................................................................................................1-10
Setting Production Casing ....................................................................................................................1-11
Perforating............................................................................................................................................1-11
Installing the Completion System ........................................................................................................1-12
Sand Control.........................................................................................................................................1-12
Installing the Christmas Tree ...............................................................................................................1-12
Acidizing ..............................................................................................................................................1-13
Fracturing .............................................................................................................................................1-13
Historical Background of Stimulation .....................................................................................................1-14
History of Acidizing.............................................................................................................................1-14
History of Hydraulic Fracturing ...........................................................................................................1-14
Halliburton Energy Services Vision and Mission....................................................................................1-16
HES 2003 Vision Statement.................................................................................................................1-16
Production Enhancement Vision and Guiding Principles ....................................................................1-16
HES Mission Statement .......................................................................................................................1-17
General Safety and Work Guidelines.......................................................................................................1-18
Stimulation Job Descriptions (Frac/Acid)................................................................................................1-20
Oilfield Terms, Slang, and Acronyms .....................................................................................................1-22
Common Oilfield Terms ......................................................................................................................1-22
Common Oilfield Acronyms ................................................................................................................1-35
Common Halliburton Acronyms ..........................................................................................................1-38
Unit A Quiz ..........................................................................................................................................1-40
Answer Key .............................................................................................................................................1-41

1•1 Stimulation I
© 2005, Halliburton
 Introduction to Stimulation

Use for Section notes…

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 Introduction to Stimulation

Introduction
Welcome to Halliburton’s Production your enrollment and can assist you in
Enhancement (PE) Product Service Line (PSL). completing the course.
Halliburton is the world leader in oil and gas
well stimulation, both in market position and
customer perception. Consistently ranked How This Course is Organized
number one in value by independent surveys of
oil and gas customers, the Production Familiarize yourself with the way this workbook
Enhancement PSL provides excellent value for is organized. You will find a table of contents at
oil and gas operators throughout the world. the beginning of each section, followed by an
Halliburton helped to pioneer well fracturing introduction, a list of topic areas, and the
back in 1949. learning objectives for that section.
Halliburton's PE PSL encompasses the Each section in this workbook contains several
technologies and capabilities to optimize units. Each unit contains all the information you
hydrocarbon reservoir performance through a need. Other manuals or catalogs are not
variety of approaches generally based on necessary, with the possible exception of a Red
pressure pumping services. The PSL’s reservoir Book and dictionary. Each unit is made up of
focus drives technology development in fluids, text, figures to help explain the text (pictures,
materials, and equipment. Included in the PE drawings charts, etc.), and a unit quiz. When you
PSL are Stimulation (fracturing and acidizing), complete all the units in a section, you complete
Sand Control, Coiled Tubing, Well Control / a self-check test. Both the quizzes and tests will
Hydraulic Workover (HWO), Nitrogen Services, help you check your personal progress. The time
and Pipeline and Process Services. This course you spend on each unit is not important; it is
primarily covers only Stimulation. important that you learn and retain the content.
This course is your introduction to the well At the end of every section are the answers to all
stimulation process: what it is, why is it done, unit quizzes and the self-check tests. After you
and how we do it. From this course, you will complete a quiz or a test, refer to the appropriate
learn many new terms, types of equipment, types answer key. Let your supervisor know when you
of materials, and processes. By completing this complete a section. Then you will take a written
course, you will be able to more effectively test that is graded. This section test is based
communicate with others in the PSL and at the solely upon the information in your workbook.
job site, be better able to participate in However, you cannot use your workbook as a
stimulation jobs, and be prepared to take on reference while taking the test.
more responsibility. You will start to become an Successful completion of all the section tests and
invaluable person who can deliver the Customer a comprehensive final examination makes you
Service that has been a Halliburton tradition for eligible to attend the next level course.
more than 80 years.
For more information on a subject covered in
Take time to carefully read this introduction. It your workbook, let your resource personnel
will acquaint you with this course and suggest know of your interest — they can direct you to
ways to get the most out of it. more information.
This workbook allows you to learn at your own
speed, without an instructor, and at any time or
place that may be convenient for you. Your
immediate supervisor is normally responsible for

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 Introduction to Stimulation

Study Suggestions • Check your answers against the answer key.

Reread the parts of the text that relate to the
This course was planned to make learning as items you are unsure about or you have
easy as possible. However, to retain the answered incorrectly. Don't forget, if you
knowledge, you must put forth effort. are having trouble, or if you feel your
Remember, the responsibility for learning this response is equally correct, consult your
course is yours. resource personnel.

Keep your workbook available at all times; you When you work through all the units in a
never know when you might have the section, you will be ready to take the self-check
opportunity to work on a unit. Try and set aside test for that section. Go back through all the
enough time to complete an entire unit during a units to review what you have learned. Your
study period. completed unit quizzes should also be helpful
here.
Some study suggestions include
If you are having trouble choosing or calculating
• Review both the section and unit an answer, go to the next question. At the end of
introductions. They will very briefly the test, go back to the questions you didn't
describe what is in the unit. answer and try again. Remember, you are not
competing with anyone but yourself. Take your
• Skim through the unit. Look at the figures
time and do your best.
and headings to see what's familiar to you
and what isn't. They will tell you what to When you finish a self-check test, turn to the
expect. answer key at the end of the section to check
your answers. References are provided as to
• Read the content carefully. Go back to the
where the answers can be found. Make sure that
beginning of the unit and read the content,
you understand the correct answers before
paragraph by paragraph. Study the figures. If
proceeding to another section. Check with your
you are unfamiliar with the meaning of a
resource personnel if you feel the response you
word, look it up in a dictionary.
gave is correct. Don't forget to let your program
• Check your understanding. Try to put into coordinator know that you have completed the
your own words the paragraph you have just section.
read. Go back and underline or make notes Upon completion of a section, ask your
of important points. This will help you to supervisor any questions you might have before
review the content of the unit later. taking the in-class section test. Successful
• Review the unit. At the end of each unit, take completion of the test enables you to move on to
a few minutes to look over your notes. the next section. Remember that successful
completion of all in-class section tests and the
• Take the unit quiz. Try not to refer to the comprehensive course final examination enables
text when you are filling in the blanks in the you to be enrolled in the appropriate next level
unit quiz. Write your answers in your school.
workbook.

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 Introduction to Stimulation

The Purpose of Stimulation in an Oil Well

After an oil or gas well is drilled, the wellbore • Fluid type
pressure is reduced to less than the oil or gas
bearing formation. This higher formation • Viscosity requirements
pressure forces the oil or gas to the wellbore, • Fluid rheology
where it then travels to the surface. Sometimes,
the flow of oil or gas (well production or • Fluid Safety
productivity) is too small for the operator to • Economics of the fluid
make any profit. If the reservoir does contain
enough oil or gas to make it commercially • Proppant selection
sufficient, then the problem may be formation • Material availability
damage near the wellbore caused during the
drilling process or be a formation with low • Experience with local formations
permeability (ability to allow flow). In either • Laboratory data on the formation
case, the flow needs to be stimulated.
In fact, Halliburton tailors the treatment fluid
Stimulation treatments include both acidizing specifically to the reservoir. The results are
and hydraulic fracturing. Acidizing refers to the minimized damage and maximized results.
use of acid pumped into the oil-bearing Whether the application calls for linear gels,
formation to dissolve parts of the formation so crosslinked gels, viscosified oils, or foam, we
that oil (or gas) can flow more easily to the well. have the experience and knowledge to design,
Hydraulic fracturing refers to pumping a fluid prepare, and carry out the stimulation operation.
into the formation at sufficiently high pressures
so that the formation rock actually cracks, again
creating paths for the fluid to flow. These cracks
may be further etched with acid or have a
proppant (such as Ottawa sand) pumped into
them to prop the cracks open after the pressure is
released (Figure 1.1).

Delivering Quality and Value

Halliburton’s challenge is to create an

economical fluid that easily and safely transports
the required proppant into the fracture. The fluid
must then break and be recovered from the
fracture, allowing the proppant pack to produce
unimpeded by the placement fluid. Our solutions
include the wide range of Fracturing Fluid
Systems. Halliburton has long been the industry
leader in giving the most value from the
stimulation treatment by increasing hydrocarbon
production from the formation. We must
consider all of the design requirements
necessary for a successful job including: Figure 1.1 - Stimulation increases the flow
of oil or gas from the reservoir to the well.

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Halliburton and the Drilling of an Oil Well

To begin, an oil company (called an operating • add a new joint of drill pipe as the hole
company or the operator, such as Shell, Texaco, deepens
or BP-Amoco) must locate areas where there is a
good potential for hydrocarbons to be found (an • trip the drill string out of the hole to put on a
oil or gas reserve). To do this, they examine the new bit and running it back to bottom
geology and conduct other tests (such as • help run and cement casing, which is steel
seismic) using Reservoir Engineers, Geologists, pipe that is put into the hole at various,
Geophysicists, and Petrophysicists from their predetermined intervals.
own staff or using a contractor such as
Halliburton’s Reservoir Description PSL. If the Often, special casing crews are hired to run the
potential exists, the operator must then acquire casing, and usually a cementing company is
the right to drill by buying or leasing the land. called on to place cement around the casing to
bond it in place in the hole. Still, the rig crew
The operator will then hire a drilling contractor usually assists in casing and the cementing
to actually drill the well (such as Parker Drilling operation.
or Santa Fe International). The operator may
manage the whole drilling project or they may For drilling to be effective, a special fluid (called
hire a contractor to manage it, such as drilling mud) must be used to carry away the
Halliburton’s Integrated Solutions PSL. Before drill cuttings and lubricate and cool the drill bit.
drilling can begin, the operating company must The industry’s top provider of drilling fluids is
determine the following: Halliburton’s BAROID PSL. Also, Halliburton’s
Security DBS PSL is one of the top providers of
• How deep is the reservoir (the depth of an drilling bits. And if the well is to be drilled at an
oil or gas well can range from a few hundred angle other than straight down (called a
to more than 20,000 feet)? deviated well), a subcontractor with the
specialized equipment and knowledge may be
• What kind of pressures will be encountered?
brought in, such as Halliburton’s Sperry-Sun
• What will be the cost? Drilling Services.
• How will the reservoir be controlled?
• Will this well be profitable? Running Drill Pipe
The operator must also hire a service and supply
company (such as Halliburton) to provide The drill bit is made up (screwed on) the bottom
drilling mud and bits, casing and casing end of the first drill collar which is heavy wall
attachments, cementing, and measuring and pipe (Figure 1.2) Enough collars and drill pipe
testing services. are made up and lowered in (called tripping in)
until the bit is almost to bottom. Then, the kelly
is attached. (kelly is a four- or six-sided piece of
Drilling Operations pipe that fits into the kelly bushing, which fits
into the master bushing in the rotary table
(Figure 1.3). The rotary table is the part of the
Simply stated, the drilling rig crew’s normal
derrick floor that spins the drill pipe. The system
drilling operations are to:
is like a wrench turning a bolt.) The drill string
• keep a sharp bit on bottom, drilling as then starts to rotate and weight is applied to drill
efficiently as possible the hole. (The bit is allowed to contact the
bottom of the hole.)

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 Introduction to Stimulation

casing, which is large in diameter and, like all

casing, is nothing more than steel pipe and
comes in 30- or 40-ft lengths (Figure 1.4).
Running casing into the hole is very similar to
running drill pipe, except that the casing
diameter is much larger and thus requires special
elevators, tongs, and slips to fit it. For example,
in a 17 1/2-in. hole, 13 3/8-in. casing might be
used.

Figure 1.2 - Drill bit.

Figure 1.4 - Casing.

Also, devices called centralizers and scratchers

(Figure 1.5) are often installed on the outside of
the casing before it is lowered into the hole.
Centralizers are attached to the casing and, since
they have a bowed-spring arrangement, keep the
casing centered in the hole after it is lowered in.
Centralized casing can be better cemented in the
Figure 1.3 - Kelly, kelly bushing, and rotary hole. Scratchers also help make better cement
table. jobs by removing the wall cake formed by the
drilling mud as the casing is moved up and down
or rotated (depending on scratcher design)
When near the end of the pipe, rotation is allowing the cement to better bond to the
stopped and another section of pipe is attached. formation.
This continues until the desired depth is reached Other casing accessories include a guide shoe, a
or the drill bit must be replaced. Then the drill heavy steel and concrete piece attached to the
pipe is picked up and disassembled (called bottommost joint of casing that helps guide the
tripping out), the new bit is attached, and the casing past small ledges or debris in the hole;
string is tripped back into the hole. and a float collar, a device with a valve installed
in the casing string two or three joints from
bottom. A float collar is designed to serve as a
Running Surface Casing receptacle for cement plugs and to keep drilling
mud in the hole from entering the casing as it is
At predetermine times, the drill pipe is removed run into the hole. Just as a ship floats in water,
and the casing crew moves in to do its work. The casing floats in a hole full of mud (if mud is kept
first string of casing they run is called surface out of the casing). This buoyant effect helps

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relieve some of the weight carried on the mast or equipment to handle this material in bulk. Bulk
derrick as the long string of heavy casing hangs cement storage and handling equipment is
suspended in the hole. moved out to the rig, making it possible to mix
large quantities of cement at the site. The
cementing crew mixes the dry cement with
water, using a recirculating mixer (Figure 1.6).
The dry cement is gradually added to the tub,
and a jet of water thoroughly mixes with the
cement to make slurry (very thin, watery
cement).

Figure 1.6 - Cement Recirculating Mixer

(RCM).

Special pumps pick up the cement slurry and

send it up to a valve called a cementing head
(also called a plug container) mounted on the
topmost joint of casing that is hanging in the
mast or derrick a little above the rig floor
(Figure 1.7). Just before the cement slurry
arrives, a rubber plug, called the bottom plug
(Figure 1.8), is released from the cementing
head and precedes the slurry down the inside of
the casing. The bottom plug stops or “seats” in
the float collar, but continued pressure from the
cement pumps opens a passageway through the
bottom plug (by rupturing a diaphragm). Thus,
. the cement slurry passes through the bottom
Figure 1.5 – Scratcher and centralizer plug and continues on down the casing. The
slurry then flows out through the opens in the
guide shoe and starts up the annular space
between the outside of the casing and wall of the
hole. Pumping continues and the cement slurry
Cementing fills the annular space.
A top plug, which is similar to the bottom plug
After the casing string is run, the next task is for
except that it is solid, is released as the last of
Halliburton to cement the casing in place. As
the cement slurry enters the casing. The top plug
when casing is run, the rig crew is available to
follows the remaining slurry down the casing as
assist.
displacement fluid (usually water or drilling
Halliburton stocks various types of cement and mud) is pumped in behind the top plug.
cement additives and has special transport Meanwhile, most of the cement slurry flows out

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of the casing and into the annular space. By the

time the top plug seats on or “bumps” the
bottom plug in the float collar, which signals (by
an increase in pressure) the cementing pump
operator to shut down the pumps, the cement is
only in the casing below the float collar and in
the annular space. Most of the casing is full of
displacement fluid.

Figure 1.8 - Top and bottom plugs for

cementing.

Figure 1.7- Plug container

After the cement is run, a waiting time is allotted

to allow the slurry to harden. This period of time
is referred to as waiting on cement (WOC).
After the cement hardens, tests may be run to
ensure a good cement job.
After the WOC and tests indicate that the job is
good, the rig crew attaches or nipples up the
blowout preventer (BOP) stack to the top of the
casing (Figure 1.9). The BOP stack is
pressure-tested, and drilling is resumed with a
smaller bit that fits inside the surface casing.
Figure 1.9 - Blowout preventer (BOP).

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Tripping In such as 7 7/8-in. for our example. This bit is

tripped in, drills out the intermediate casing
shoe, and heads toward what everyone hopes is a
To resume drilling, a smaller bit is selected,
pay zone, which is a formation capable of
because it must pass down inside the surface
producing enough oil and/or gas to make it
casing. To drill the surface hole, the example rig
economically feasible for the operating company
crew used a 17-1/2 inch bit, whereas a 12-1/4
to complete the well.
inch bit will now be used. In this case, the
outside diameter of the surface casing is 13-3/8 Once again several bits will be dulled and
inches, so in order to get adequate clearance, a several round trips will be made, but before long
12-1/4 inch bit is used. As before, the bit is the formation of interest (the pay zone, the oil
made up on the drill collars followed by drill sand, or the formation that is supposed to
pipe. contain hydrocarbons) is penetrated by the hole.
It is now time for a big decision. The question is,
“Does this well contain enough oil or gas to
Running and Cementing make it worthwhile to run the final production
Intermediate Casing string of casing and complete the well?”

At this point, particularly in deep wells, another,

smaller diameter string of casing may be set and
Completing the Well
cemented in the hole, such as using a 12 1/4-in.
bit and 8 5/8-in. casing. This casing string is the After careful consideration of the data obtained
intermediate string. It runs all the way from the from tests run on the formation or formations of
surface, down through the surface casing, and to interest a decision is made on whether to set
the bottom of the intermediate hole. Sometimes production casing and complete the well or
intermediate string is needed in deeper holes “plug and abandon” it (PTA). If the decision is
because there are almost always so-called to abandon it, the hole is considered to be dry,
troublesome formations are encountered in the that is, not capable of producing oil or gas in
hole. commercial quantities. In other words, some oil
or gas may be present but not in amounts great
Troublesome formations are those that may enough to justify the expense of completing the
contain formation fluids under high pressure well.
and, if not sealed off by casing and cement,
could blow out, making it difficult if not Therefore, several cement plugs will be set in
impossible to eventually produce oil or gas from the well to seal it off (Figure 1.10). However,
the well. Or perhaps there is sloughing shale, a sometimes wells plugged and abandoned as dry
formation composed of rock called shale that at one time in the past may be reopened and
swells up when contacted by the drilling mud produced if the price of oil or gas has become
and falls or sloughs off into the hole. Many more favorable. The cost of plugging and
types of troublesome formations can be abandoning a well may only be a few thousand
overcome while they are being drilled but are dollars. Contrast that cost with the price of
better cased off and cemented prior to drilling setting a production string of casing --$50,000 or
the final portion of the hole. more. Therefore, the operator’s decision is not
always easy.

Drilling To Final Depth

Whether intermediate casing is set or not, the

final part of the hole is what the operating
company hopes will be the production hole. To
drill it, the crew makes up a still smaller bit,

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Perforating

Because the pay zone is sealed off by the

production string and cement, perforations must
be made in order for the oil or gas to flow into
the wellbore. Perforations are simply holes that
are made through the casing and cement and
extend some distance into the formation. The
most common method of perforating
incorporates shaped-charge explosives (similar
to those used in armor-piercing shells).

Figure 1.10 - Cement used to plug a well.

Setting Production Casing

If the operating company decides to set casing,

casing will be brought to the well and for one
final time, the casing and cement crew run and Figure 1.12- Perforating gun: (A) gun in
cement a string of casing. Typically, the hole, (B) gun firing, and (C) oil flowing
production casing is set and cemented through through perforations.
the pay zone; that is, hole is drilled to a depth
beyond the producing formation, and the casing
(5 ½-in. for our example) is set to a point near Shaped charges accomplish penetration by
the bottom of the hole. As a result, the casing creating a jet of high-pressure, high-velocity gas
and cement actually seal off the producing (the leading supplier is Halliburton’s Jet
zone--but only temporarily. After the production Research Center). The charges are arranged in a
string is cemented, the drilling contractor has tool called a gun that is lowered into the well
almost finished his job except for a few final opposite the producing zone. The gun can be
touches. lowered on wireline or tubing. When the gun is
in position, the charges are fired by electronic
means from the surface (Figure 1.12).
Conductor
Casing After the perforations are made, the tool is
Cement
retrieved. Perforating is usually performed by a
Surface
Casing
service company that specializes in this
technique, such as Halliburton’s Logging &
Intermediate
Casing
Perforating PSL or Tools, Testing, and Tubing-
Conveyed Perforating (TT&TCP) PSL.
Cement
Production
Casing

Reservoir
Casing Shoe
Cement

Figure 1.11- Schematic of casing and

cement in well.

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• disposal and removal of formation sand

Installing the Completion • casing damage from compressive loading
System caused by subsidence
Halliburton’s Completion Products and Services
Even though the oil or gas can flow into the PSL provides specialized surface and downhole
casing after it is perforated, usually, the well is equipment including gravel pack packers and
not produced through the casing. Instead, screens to inhibit the movement of formation
smaller diameter pipe called production tubing sand into the wellbore, surface pumping
is placed in the well to serve as a way for the oil equipment, and filtration systems.
or gas to flow to the surface. The tubing is run
into the well with a packer installed at or near
the end of the tubing. The packer is placed at a
depth just above the producing zone. When the
packer is expanded, it grips the wall of the
production casing and forms a seal in the
annular space between the outside of the tubing
and the inside of the casing. Thus, as the
produced fluids flow out of the formation
through the perforations, they are forced to enter
the tubing to get to the surface.
Additional devices are placed in the well or in
the production tubing string to control and
monitor the fluid flow, such as subsurface safety
valves and flow control equipment, surface
safety systems, packers and specialty completion
equipment, production automation, and well
screens. Halliburton’s Completion Products and
Services PSL can supply all these products.

Figure 1.13 - Production tubing with screen

Sand Control and gravel pack in place.

At times, the producing zone may also produce

formation sand as well as the oil or gas. A
screen may be attached to the end of the
production tubing to help keep the sand out. Installing the Christmas Tree
Often, when a screen is used, gravel is also
placed in the hole around the screen, which is When casing is set, cemented, and perforated
known as a gravel pack (Figure 1.13). and when the tubing string is run, then a
collection of valves called a Christmas tree is
Formation sand can present a major obstacle to
installed on the surface at the top of the casing
well production. The petroleum industry spends
(Figure 1.14). The tubing in the well is
millions of dollars each year to prevent and
suspended from the tree, so as the well's
repair sand control problems including
production flows up the tubing, it enters the tree.
• reduced production rates As a result, opening or closing valves on the
Christmas tree can control the production from
• sand bridging in tubing and casing the well. Usually, after the Christmas tree is
• erosion of downhole and surface equipment installed, the well is said to be complete.

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Fracturing

When sandstone rocks contain oil or gas in

commercial quantities but the permeability is too
low to permit good recovery (or the formation
has been damaged), a process called fracturing
may be used to increase conductivity to a
practical level. To fracture a formation, a
fracturing service company (such as
Halliburton’s Production Enhancement PSL)
pumps a specially blended fluid down the well
and into the formation under great pressure.
Pumping continues until the formation literally
cracks open.
Meanwhile, sand or man-made granules, called
proppants (Figure 1.15), are mixed into the
fracturing fluid. The proppant enters the
Figure 1.14 - Christmas tree.
fractures in the formation, and, when pumping is
stopped and the pressure released, the proppant
remains in the fractures. Because the fractures
try to close back together after the pressure is
Acidizing released, the proppant is needed to hold or prop
the fractures open. These propped-open fractures
Sometimes, petroleum exists in a formation but provide passages for oil or gas to flow into the
is unable to flow readily into the well because well.
the formation has very low permeability
(capability for fluid flow). If the formation is
composed of rocks that dissolve when contacted
by acid, such as limestone or dolomite, then a
technique known as acidizing may be required.
Acidizing is usually performed by an acidizing
service company (such as Halliburton’s
Production Enhancement PSL) and may be done
before the rig is moved off the well; or it can
also be done after the rig is moved away.
In any case, the acidizing operation basically
consists of pumping anywhere from fifty to
thousands of gallons of acid into the well. The
acid travels down the tubing, enters the Figure 1.15 - Sand, which can be used as a
perforations, and contacts the formation. proppant.
Continued pumping forces the acid into the
formation where it dissolves channels that
provide a way for the formation's oil or gas to
enter the well through the perforations.

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Historical Background of Stimulation

The first attempts at stimulation occurred in the the Dow Well Service Group. Halliburton Oil
1890s when nitroglycerin was used to stimulate Well Cementing Co., began acidizing oil wells
hard rock wells in the northeastern states. The commercially in March of 1935.
concept here was to fracture (rubbilize) the The ability of pressure to part or fracture the
production interval in the near wellbore region formation was recognized during these first acid
to increase production rates. Although quite stimulation treatments of the 1930s. It was
hazardous, this technique was extremely noted that acid would etch the faces of the
successful for increasing oil, gas, and water fracture, thereby not allowing for complete
production. closure.

History of Acidizing History of Hydraulic Fracturing

Acidizing must be considered one of the oldest The first attempts at hydraulic fracturing were
stimulation techniques still in modern use. made in 1947 in the Hugoton gas field in Grant
Earliest records indicate that the first acid County, Kansas, using Napalm thickened
treatments were probably performed in 1895. gasoline followed by a gel breaker. The results
Herman Frasch, a chief chemist at Standard Oil were not good, but the concept was introduced
Company’s Solar Refinery at Lima, Ohio, is in a paper written by J.B. Clark of Stanolind in
credited with having invented the technique. 1948. In 1949 the process was patented and
The first acidizing patent, issued to Frasch on Halliburton was given an exclusive license on
March 17, 1896, involved a reagent the new process.
(hydrochloric acid) that would react with The first two commercial fracturing attempts
limestone to produce soluble products. These were performed on March 17, 1949 in Stephens
soluble products were then produced from the County, Oklahoma (Figure 1.16) and Archer
formation with the well fluids. Although County, Texas. These treatments were
successful, for some unknown reason the use of completed using lease crude or a blend of crude
acid declined and no evidence of acidizing is and gasoline and about 100 to 150 lb of sand.
available during the ensuing 30 years. Due to the outstanding results of these first two
Many have described the modern era of attempts, using hydraulic fracturing as a means
acidizing which began in 1932 with discussions of increasing production grew rapidly across the
between Pure Oil Co. and the Dow Chemical US to the point where 3000 jobs per month were
Co. Pure had oil wells in the same area of being completed in the mid 1950s.
Michigan as Dow’s brine wells. Pure’s In the 10 years that followed, more than 1.2
geologist, W. A. Thomas, and John Grebe, who billion pounds of sand were pumped into wells
was in charge of Dow’s Physical Research within the United States as acceptance grew for
Laboratory, suggested well productivity of a what has become one of the industry's most
limestone formation could be improved with an outstanding well stimulation techniques.
acid treatment. Pure chose a test site and on
February 11, 1932 the well was treated with 500 In the early days of fracturing, a "big" job may
gallons of hydrochloric acid. Subsequently, have involved 2,000 gal of fluid and 1,000 lb of
Dow formed a new subsidiary on November 19, proppant. 25 years after the first fracturing jobs,
1932 to handle the growing acidizing business. treatments averaged about 37,000 gal of fluid
The subsidiary takes its name, Dowell Inc., from and 45,000 lb of proppant. Today, jobs with

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 Introduction to Stimulation

500,000 gal of fluid and one million pounds of fracturing may also be used to help overcome
proppant are not uncommon (Figure 1.17). wellbore damage, aid in secondary recovery
operations, and help inject and dispose of brine
and industrial wastes.
With the advancement of computer technology,
field engineers can now use hydraulic fracture
design simulators on the job site for more than
just research purposes. These simulators require
rock mechanic properties, fluid properties,
treatment data, and economic data as inputs to
calculate the most effective frac design. Pre-
Frac data acquisition has become more
sophisticated and varied in recent years because
of new tools and technology. In-situ rock
stresses, fracture orientation, fracture closure
pressure, fluid efficiency, treatment pressure,
Figure 1.16 - One of the first two hydraulic and many other parameters can be determined
fracturing jobs, this one performed in through pre-frac treatment methods.
Stephens County, Oklahoma.
Two valuable aids to well stimulation became
available with the introduction of Nitrogen and
By 1981, more than 800,000 treatments had CO2 services. Along with the advantages of
been performed. As of 1988, this has grown to using Nitrogen and CO2 in stimulation work,
exceed 1 million. About 35 to 40% of all major advances have been made in pumping
currently drilled wells are hydraulically equipment, storage, and safety measures.
fractured. Conservative estimates suggest that
approximately 75% of wells that have been
fractured have increased production.
Many fields exist today because of the use of
hydraulic fracturing techniques. About 25 to
30% of total U.S. reserves have been made
economically producible by the process.
Fracturing is responsible for increasing North
America’s oil reserves by 8 billion barrels. In
addition to creating reservoir fractures for
improving well productivity, hydraulic Figure 1.17 - Large frac-acid job

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Halliburton Energy Services Vision and Mission

HES 2003 Vision Statement

The Halliburton Energy Services 2003 Vision is to be the undisputed leader in Real Time
Reservoir Solutions.
The fundamental principles to achieving our vision involve:
• Providing superior value to shareholders and customers
• Creating a company-wide environment for developing, motivating, and rewarding our people
• Being the undisputed leader in innovative technology, integrated solutions and health, safety
and the environment.
• Being No. 1 or 2 in core discrete businesses
• Leveraging Halliburton Company's total capability

Production Enhancement Vision and Guiding Principles

The leader in optimizing well performance through reservoir understanding and integrating
intelligent stimulation and completions, we strive to
• Demonstrate the greatest value created
• Make it easy to do business with HES
• Consistently provide best-in-class performance

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HES Mission Statement

Our Mission Statement defines our purpose and our beliefs in how we want to achieve our vision by
providing "markers or guideposts" to our beliefs as a company.
Halliburton Energy Services (HES), a business unit of Halliburton Company, is a global
provider of products, services, and solutions to the energy industry. To be successful,
HES must focus on the needs of our customers. We are to continually find creative
solutions that maximize the economic recovery of the oil and gas reservoir.
The means by which we will enable our customers to be successful is by aligning with
their goal of reducing the cost of oil and gas produced, through providing reliable, cost-
effective solutions, delivered by expert personnel with the following values and
principles:
• Perform at the highest levels of service quality that exceed our customers’
expectations
• Believe that all accidents are preventable and strive for an incident-free workplace
• Recognize that we are responsible for protecting the environment and consistently
meeting those responsibilities
• Continually apply new technology that benefits our customers and distinguishes
Halliburton Energy Services from our competitors as a leader in fit for purpose
solutions
• Support a culture of real-time decision-making and speed to ensure responsiveness
to our customers’ needs
• Maintain integrity in all of our actions — always honor our commitments
• Be flexible and innovative in our business models and recognized as the leading
company with whom it is easy to do business
By virtue of our mission and values, Halliburton Energy Services expects to be the most
valued provider of solutions to our customers. And because we are successful in
meeting our customers’ needs and good business practices, we expect to deliver
superior financial performance to our shareholders.
We can only accomplish this with the efforts and participation of our employees;
therefore, we must commit to invest in our people to promote a climate of enthusiasm,
teamwork, and challenge which attracts, motivates and retains superior personnel and
rewards performance.

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General Safety and Work Guidelines

Everyone, at times, hesitates to admit that he or can be hazardous if the way is littered with loose
she does not know all there is to know about the boards, scraps of oil field equipment, nails and
job, operation, or machine to which he or she is scrap iron, or mud-filled holes.
assigned. Consequently, the supervisor in charge Always wear safety hats and safety shoes on the
of the job, who is responsible for the safety of job. When assembling hammer-up type unions
the crew, may assume that the worker fully wear safety shields or goggles for the operation.
understands the safety rules. So he leaves them
alone. Carefully observe the following precautionary
measures:
As a result of this assumption, sooner or later
someone is injured, equipment is ruined, or a 1. No smoking is allowed on or near the well
well is damaged. Every supervisor prefers that site.
workers ask questions about the job--it shows 2. Never wash tools and equipment in
interest and a desire to learn and progress. flammable mixtures in areas without proper
Remember, no one knows everything, even ventilation.
about his or her work. It is no admission of
dumbness or lack of experience to admit “I’m 3. Keep all hammers, chisels, punches, etc.
not sure I know how you want this done.” properly dressed to eliminate the possibility
of steel particles becoming dislodged. Cold
Safety begins for the job even before you leave chisels and hammers have destroyed the
home. A worker who gets plenty of proper rest sight of countless numbers of eyes.
and nourishment is provided the alertness that is
necessary to be a safe worker. 4. Make certain of proper footing when
climbing around the equipment. Do not
Get up in plenty of time to thoroughly awaken grasp anything for support that is not
and clean up before driving to the job. Take properly secured.
enough clothing to comfortably complete the
pending job. If it is to be a long job, be certain 5. Your supervisor is responsible for the safety
you have plenty of spare clothes. of the crew. Follow his or her instructions
and always seek advice if you do not
On the way to the location is a good time to understand the procedure at hand.
become oriented with the coming operation. Ask
questions concerning what is expected of you 6. Before every job, you must have a tailgate
and the crew on the job. On the way back home safety meeting on location to discuss the job
it is a good idea to discuss the job. It may reveal and potential safety hazards while on
mistakes that could have been prevented. It may location.
recall to your mind an unsafe condition, which 7. Think the project through before proceeding
can be avoided under similar conditions in the with any operation around the well site.
future. And it will aid in keeping the driver from
becoming drowsy and sleepy through the 8. The most dangerous part of your job is on
boredom of a long drive. If the driver does the roads to and from the field. Ask your
appear to be getting drowsy, it’s time for another Supervisor for special instructions
coffee break. concerning your driving duties.

After arriving at the location and changing to 9. All safety equipment should be carried in its
work clothes, clear the way to the equipment proper place on the vehicle. This equipment
site. This preparation is especially important on should be checked periodically. It is the duty
a new location. Transporting heavy equipment

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of the operator to know the location of the • If you are not sure, ask the advice of your
equipment and its proper operation. supervisor.
In short: • Study the rules and regulations in the HES
• Be sure you know how to do the job. Safety Policy Manual

• Be sure you know the hazards of the job and

how to protect yourself.

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Stimulation Job Descriptions (Frac/Acid)

Operator Assistant • Drives a truck or other assigned equipment
as required. Requires a high school diploma,
• Assists in rigging up and down of Frac/Acid
GED, or equivalent experience. May require
service line equipment.
a valid Commercial Driver's License.
• Assists in assembly and preparation of
• Must have successfully passed company
equipment for installation and service.
tests or met task guideline requirements.
• Assists in the running of a job and in the
Service Supervisor
clean up, repair, and preparation for the next
job. • Coordinates and oversees the Frac/Acid
service line work at the well site handling
• Promotes and takes an active part in the
the more complex, hazardous, and/or high
Quality Improvement Process.
profile jobs providing quality service to the
• Ensures compliance with Health, Safety, and customer.
Environmental (HSE) regulations and
• Provides the planning necessary for the job
guidelines.
including instructions to the crew and
• Promotes safety awareness and equipment used, including dispute
environmental consciousness, and complies resolutions to approved levels.
with all applicable safety and environmental
• Promotes and takes an active part in the
procedures and regulations.
Quality Improvement Process, and ensures
• Works under direct supervision with no that Halliburton Management System
experience required. This is the entry-level (HMS) guidelines are followed.
position into the service operator job family.
• Ensures compliance with HSE regulations
Service Operator and guidelines. Promotes safety awareness
and environmental consciousness, and
• Rigs Frac/Acid service line equipment under
complies with all applicable safety and
direct supervision to provide quality service
environmental procedures and regulations.
to the customer.
• Ensures customer satisfaction with work
• Performs, with limited supervision from the
performed.
Service Supervisor, in the rigging up and
rigging down on a location of service line • Coordinates and directs the activities of
equipment and in the clean up, repair, and service operators during the rigging up and
preparation of equipment for the next job. rigging down on a location of service line
equipment and the assembly and preparation
• Assembles and prepares, as directed,
of equipment for installation, running, and
equipment for installation and service.
service of a job.
• Promotes and takes an active part in the
• Coordinates the clean up, repair, and
Quality Improvement Process. Ensures
preparation of equipment for the next job.
compliance with HSE regulations and
guidelines. • Plans and performs necessary calculations
for the total job at the well site as needed.
• Promotes safety awareness and
environmental consciousness, and complies • Evaluates individual performance levels of
with all applicable safety and environmental the crew and trains operators to improve
procedures and regulations. their job performance.

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• Requires a high school diploma, GED, or customer satisfaction for the long term
equivalent experience and a valid growth and profitability of the NWA.
Commercial Driver's License as required.
• Manages processes to ensure job site
Demonstrates exceptional skills within the
execution as designed.
service line and a general understanding of
other service functions. • Follows up job site performance with
customer.
Service Leader
• Maintains MBU performance measures and
• In addition to responsibilities as a Service
documents results and best practices. (This
Supervisor, is also the PSL Mobile Business
classification is available only for North
Unit Leader.
America MBU participants).
• Responsible for development and leadership
of the Frac/Acid PSL profit center within the
NWA.
• The MBU Leader's emphasis is on personnel
development, operational excellence and

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Oilfield Terms, Slang, and Acronyms

Sometimes, it may seem that those working in forces. Aggregates are stable to normal stirring,
the oilfield are speaking an utterly different shaking, or handling as powder or a suspension.
language. The oil industry and Halliburton have They may be broken by drastic treatment such as
come up with many terms, slang, and acronyms ball milling a powder or by shearing a
that you need to know. suspension. An essentially inert material of
mineral origin having a particle size
predominantly greater than 100 mesh, which
Common Oilfield Terms forms a mortar or concrete when bound together
with hardened cement paste.
ABANDON- Cease effort to produce oil or gas ALKALINITY- Combines power of a base
from a well, plug a depleted formation salvaging measured by the maximum number of
all material and equipment. equivalents of acid with which it can react to
ABSOLUTE PERMEABILITY- Measures form a salt. In water analysis, it represents the
ease which a fluid will flow through a porous carbonates, bi-carbonates, hydroxides, and
medium. occasionally the borates, silicates, and
phosphates in the water.
ABSOLUTE VOLUME - Volume per unit
mass, reciprocal of absolute density. AMBIENT- We use this term to describe
temperature. Strictly speaking, the term is
ACID- Any chemical compound containing defined as “completely surrounding.” Ambient
hydrogen capable of being replaced by positive temperature would then be the temperature of
elements or radicals to form salts. In terms of the the air surrounding us. We stretch this definition
dissociation theory, it is a compound that, on a little and refer to pumping fluids at ambient
dissociation in solution, yields excess hydrogen temperature. We mean we don’t heat or cool the
ions. Acids lower the pH. Examples of acids or fluid, but use it just like it is in the tank.
acidic substances are: hydrochloric acid, tannic
acid, sodium acid pyrophosphate. Substance that AMPHOTERIC - Anionic or cationic
molecules ionize in a water solution to release depending on outside conditions pH for
the hydrogen ion from the constituent element. example.
The strength of an acid is proportional to the ANAEROBIC- Bacteria that do not require free
concentration of hydrogen ions present. oxygen to thrive.
ACIDITY - Relative acid strength of liquids as ANHYDRITE- See Calcium Sulfate. Anhydrite
measured by pH. pH value below 7. See pH. is often encountered while drilling. It may occur
ACIDIZING- The practice of applying acids to as thin stringers or massive formations. CaSO4.
the walls of oils and gas wells to remove any ANIONIC- Refers to any anion (atom or
material which obstructs the entrance of fluids. chemical group bearing a negative electrical
Also used in carbonate formations, such as charge). It is used specifically to describe certain
limestone, to increase porosity. surfactants. An anionic surfactant ionizes to
ADDITIVE - Material other than cement and produce a cation (positively charged) ion which
water which is added to cement subsequent to is usually a metallic ion such as sodium. When a
its manufacture to modify its properties. cation is produced through ionization, an anion
must also be produced.
AERATE- Intimately admixing water and air.
ANNULUS (ANNULAR SPACE) - The space
AGGREGATE- A group of two or more surrounding pipe suspended in the well bore.
individual particles held together by strong

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The outer wall of the annulus may be an open BASE - Compound of metal, or a metal-like
hole or it may be larger pipe. group, with hydrogen and oxygen in the
proportion to form an OH radical, which ionizes
API- American Petroleum Institute.
in aqueous solution to yield excess hydroxyl
API GRAVITY- The gravity (weight per unit ions. Bases are formed when metallic oxides
volume) of crude oil or other related fluids as react with water. Bases increase the pH.
measured by a system recommended by the Examples are caustic soda and lime.
American Petroleum Institute. It is related to
BASICITY - pH value above 7, ability to
specific gravity by the following formula:
neutralize or accept protons from acids.
Deg API = 141.5_- 131.5
BED - Specific layer of earth or rock material in
sp gr 60°F/60°F
contrast to other layers of earth or rock of
APPARENT VISCOSITY- The viscosity a different material lying above, below, or
fluid appears to have on a given instrument at a adjacent to the bed in reference.
stated rate of shear. It is a function of the plastic
BENTONITE- A highly plastic, highly
viscosity and the yield point. The apparent
colloidal clay, largely made up of the mineral,
viscosity in centipoises, as determined by the
montmorillonite, plastic, colloidal clay, largely
direct-indicating viscometer (which see), is
made up of the mineral sodium montmorillonite,
equal to 1/2 the 600-rpm reading. See also
a hydrated aluminum silicate. Used in drilling
Viscosity, Plastic Viscosity and Yield Point. In a
fluids, bentonite has a yield in excess of 85
Newtonian fluid, the apparent viscosity is
bbl/ton. The generic term “bentonite” is neither
numerically equal to the plastic viscosity.
an exact mineralogical name, nor is the clay of
AQUEOUS - Used to describe fluids prepared definite mineralogical composition.
from water. Usually used to distinguish from
BICARB - See Sodium Bicarbonate.
hydrocarbon fluid. An aqueous fluid may be
plain fresh water, or it may have a great number BIOCIDE- Used interchangeably with the word
of additives, which give it properties much bactericide. “Bio” means life and “cide” means
different from plain water. Examples are salt kill.
water of various weights, HCL, KCL water,
BLOCKS, CROWN AND TRAVELING- The
formic and acetic acids.
block and tackle on a rig that raises and lowers
AROMATIC- Describes those hydrocarbons the drill string.
that have carbon chains bent and connected to
BLEED OFF OR BLEED DOWN- Reduce
form a ring or cycle. Aromatic hydrocarbons are
pressure by letting oil or gas escape at a low
sometimes called “cyclic” hydrocarbons. Many
rate.
of these compounds, as the name implies, have a
fragrant or spicy odor. Xylene bottoms are a BLOOIE LINE- Flow line for air or gas
mixture of aromatic compounds including drilling.
xylene, benzene and toluene. A solid aromatic BLOWOUT - Uncontrolled escape of drilling
hydrocarbon which is commonly used is fluid, gas, oil, or water from the well caused by
napthalene or mothballs. the formation pressure being greater than the
BACK-OFF- Unscrew. hydrostatic head of the fluid in the hole.
BACK PRESSURE - Pressure resulting from BLOWOUT PREVENTER- A device attached
restriction of full natural flow of oil or gas. immediately above the casing, which can be
closed and shut off the hole should a blowout
BACTERIA- The simplest form of animal life.
occur.
BACTERICIDE - Agent capable of destroying
BOTTOM-HOLE PRESSURE- The pressure
bacteria.
at the bottom of a well.
BARREL - A volumetric unit of measure used
in the petroleum industry consisting of 42 gal.

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BOTTOMHOLE TREATING PRESSURE- CALCIUM CHLORIDE - CaC12. A very

The pressure in the wellbore at the perforations soluble calcium salt sometimes added to drilling
required to extend the fracture while overcoming fluids to impart special properties, but primarily
closure pressure, fracture friction, and rock to increase the density of the fluid phase.
strength. See Fracture Extension Pressure.
CALCIUM HYDROXIDE - Ca(OH)2. An
BREAKDOWN PRESSURE- The pressure active ingredient of slaked lime also the main
observed from a well when the formation is constituent in cement (when wet). This material
fractured for the first time. This data is also is referred to as “lime” in field terminology.
useful in the drilling and cementing processes.
CATALYST - Chemical useful for enhancing
BREAKER- Chemicals that function by the rate at which a chemical reaction takes place
degrading the long chain polymer into shorter while undergoing no chemical change itself.
chains with controlled and predictable viscosity
CATIONIC- Refers to any cation (atom or
decrease.
chemical group bearing a positive electrical
BRINE- Water saturated with or containing a charge). It is used specifically to describe certain
high concentration of common salt (sodium surfactants. A cationic surfactant ionizes to
chloride); hence, any strong saline solution produce an anion (negatively charged ion) which
containing such other salts as calcium chloride, is usually a non-metallic ion such as chloride or
zinc chloride, calcium nitrate, etc. sulfate. When an anion is produced through
ionization, a cation must also be produced.
BUBBLE POINT- The pressure above which a
hydrocarbon fluid exists only as a liquid; CAUSTIC OR CAUSTIC SODA- See Sodium
synonymous with saturation pressure. Hydroxide.
BUFFER - Substance or mixture capable in CENTIPOISE (CP) - A unit of viscosity equal
solution of neutralizing both acids and bases, to 0.01 poise. A poise equals 1 g per meter-
thereby maintaining the original hydrogen-ion second, and a centipoise is 1 g centimeter-
concentration. second. The viscosity of water at 20°C is 1.005
cp (1 cp = 0.000672 lb/ft-sec).
BY-PASS- Usually refers to a pipe connection
around a valve or other control mechanism. A CHERT - Quarzitic rock with hardness equal to
by-pass is installed in such cases to permit or harder than flint.
passage of fluid through the line while
CHRISTMAS TREE- A term applied to the
adjustments or repairs are made on the control,
valves and fittings assembled at the top of a well
which is by-passed.
to control the flow of the oil or gas.
CAKE CONSISTENCY- According to API RP
CIRCULATE- To cycle drilling fluid through
13B, such notations as “hard,” “soft,” “tough,”
drill pipe and well bore while drilling operations
“rubbery,” “firm,” etc., may be used to convey
are temporarily suspended. This is done to
some idea of cake consistency.
condition the drilling fluid and the well bore
CAKE THICKNESS- The measurement of the before hoisting the drill pipe and to obtain
thickness of the filter cake deposited by a cuttings from the bottom of the well before
drilling fluid against a porous medium, most drilling proceeds. Circulation of the drilling fluid
often following the standard API filtration test. while drilling is suspended is usually necessary
Cake thickness is usually reported in 32nd of an to prevent drill pipe from becoming stuck.
inch. See Filter Cake and Wall Cake.
CLAY- A hydrated aluminum silicate. Clays are
CALCIUM CARBONATE - CaCO3. An components of soils in varying percentages.
insoluble calcium salt sometimes used as a Some types swell with absorption of water.
weighting material (limestone, oyster shell, etc.), Various types are: kaolinite, smectite, illite,
in specialized drilling fluids. It is also used as a chlorite and mixed-layer. A plastic, soft,
unit and/or standard to report hardness. variously colored earth, commonly a hydrous

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silicate of alumina, formed by the decomposition CORROSION- The adverse chemical alteration
of feldspar and other aluminum silicates. See on a metal or the eating away of the metal by air,
also Attapulgite, Bentonite, High Yield, Low moisture, or chemicals; usually an oxide is
Yield, and Natural Clays. Clay minerals are formed. Deterioration of metal due to reaction
essentially insoluble in water but disperse under with the environment.
hydration, shearing forces such as grinding,
CORROSION INHIBITOR INTENSIFIER-
velocity effects, etc., into the extremely small
An additive that cannot be considered as an
particles varying from submicron to 100-micron
inhibitor when used alone but has the ability to
sizes.
improve the effectiveness of conventional
CLAY CONTROL ADDITIVES- Chemical organic inhibitors when used with them.
additives used to minimize the possibility of clay
CRATER (TO CRATER) - Term meaning the
crystals breaking loose and migrating using
hole is caving in. To crater refers to the results
ionic charge and organic polymer.
that sometime accompany a violent blowout
CLEAN VOLUME- Volume of fracturing fluid during which the surface surrounding the well
before adding proppant. bore falls into a large hole blown in the earth by
the force of escaping gas, oil, and water. The
CLOSURE PRESSURE- There is two uses of
crater sometimes covers an area of several acres
this term: (1) The minimum hydraulic pressure
and reaches a depth of several hundred feet.
required to hold a fracture open. This pressure is
obtained from either minifracturing or CRITICAL POINT - The pressure and
microfracturing data. The closure pressure is the temperature where all lines of constant liquid
same Closure Pressure as the least principal rock content coverage for a given hydrocarbon
stress. (2) This term is also used to refer to mixture; the pressure and temperature at which
“closure stress,” or the stress the formation all intensive properties of the vapor and liquid
applies to the proppant bed after fracturing. are the same.
Note: These two uses of this term should not be
CRITICAL PRESSURE- The point at which a
confused.
constant pressure occurs indicating a reduction
CLOSURE STRESS- Stress applied to the in the fracture extension rate (as defined by
proppant bed after fracturing. Closure stress is Nolte).
not equal to closure pressure. Closure stress is
CROSSLINKING - Union of high-polymer
equal to instantaneous shut-in pressure minus
molecules by a system involving primary
bottomhole flowing pressure. Consequently,
chemical bonds.
closure stress in the proppant bed is a function of
time.- CROWN BLOCK - Sheaves and supporting
beams on top of derrick.
COLLAR - Pipe coupling threaded on the
inside. D’ARCY - Unit of permeability. A porous
medium has a permeability of 1 darcy when a
COMING OUT OF HOLE - Withdrawing of
pressure of 1 atm on a sample 1 cm long and 1
the drill pipe from the well bore. This
sq cm in cross section will force a liquid of 1-cp
withdrawal is necessary to change the bit, or
viscosity through the sample at the rate of 1 cc
change from bit to core barrel, to prepare for a
per sec.
drill stem test, and for other reasons.
D’ARCY’S LAW- The rate of flow of a
CONDENSATE- Hydrocarbons which are in
homogeneous fluid through a porous medium is
the gaseous state under reservoir conditions but
proportional to the pressure of hydraulic
which become liquid either in passage up the
gradient and to the cross-sectional area normal
hole or at the surface.
to the direction of flow and inversely
CONDUCTIVITY - See Fracture Conductivity. proportional to the viscosity of the fluid.

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DENSITY- When used in relation to materials change alone. Natural gas that is produced with
such as solids, liquids, or gases, this means the liquids; also a gas that has been treated to
weight of a unit volume of the material. Many remove all liquids.
types of units are used to measure density. The
DRY HOLE- Somewhat loosely used in oil
chemist usually uses grams per cubic centimeter
work, but in general any well that does not
(gm/cc). In the oil patch we may use pounds per
produce oil or gas in commercial quantities. A
cubic foot (lb/cu ft) for solids, pounds per gallon
dry hole may flow water, or gas, or may even
(lb/gal) for liquids and pounds per cubic foot
yield some oil to the pump, but no in
(lb/cu ft) for gases.
commercial quantities.
DIFFERENTIAL ETCHING- The removal of
ELEVATORS- Latches which secure the drill
formation during fracturing acidizing in an
pipe or casing; attached to the traveling block
uneven manner (hills and valleys). Once the
which raises and lowers the pipe from the hole.
formation closes, the area where the most rock
was removed can act as permeable flow EMULSION- A substantially permanent
channels while the other areas act as support to heterogeneous liquid mixture of two or more
keep these channels open. liquids that do not normally dissolve in each
other but which are held in suspension or
DIFFERENTIAL PRESSURE -Difference in
dispersion, one in the other, by mechanical
pressure between the hydrostatic head of the
agitation or, more frequently, by adding small
drilling-fluid column and the formation pressure
amounts of substances known as emulsifiers.
at any given depth in the hole. It can be positive,
Emulsions may be mechanical, chemical, or a
zero, or negative with respect to the hydrostatic
combination of the two. They may be oil-in-
head.
water or water-in-oil types.
DIFFUSION -Spreading, scattering, or mixing
ENZYME- One of a group of complex organic
of a material (gas, liquid, or solid).
substances formed in the living cells of plants
DIRTY VOLUME - Volume of fracturing fluid and animals. They are necessary catalysts for the
after adding proppant. chemical reactions of biological processes (such
as digestion).
DOG-LEG - The “elbow” caused by a sharp
change of direction in the well bore. Bend in FATIGUE - Failure of a metal under repeated
pipe, a ditch, or a well. loading.
DOPE- Material used on threads of pipe or FAULT - Geological term denoting a formation
tubing to lubricate and prevent leakage. break, upward or downward, in the subsurface
strata. Faults can significantly affect the area
DOUBLE- Two lengths or joints of pipe joined
mud and casing programs.
together.
FEMALE CONNECTION - Pipe or rod
DRILL-STEM TEST (DST)- A test to
coupling with the threads on the inside.
determine whether oil and/or gas in commercial
quantities has been encountered in the well bore. FILTER CAKE- The suspended solids that are
deposited on a porous medium during the
DRILL STRING- The string of pipe that
process of filtration. See also Cake Thickness.
extends from the bit to the Kelly, carries the
mud down to the bit, and rotates the bit. FILTRATE - Liquid that is forced through a
porous medium during the filtration process. For
DRILLING MUD OR FLUID- A circulating
test, see Fluid Loss.
fluid used in rotary drilling to perform any or all
of various functions required in the drilling FITTINGS- The small pipes and valves that are
operation. used to make up a system of piping.
DRY GAS - Hydrocarbon fluid which exists at a FLOCCULATION- Loose association of
reservoir temperature above its cricondentherm; particles in lightly bonded groups, non-parallel
a gas which cannot be liquefied by pressure association of clay platelets. In concentrated

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suspensions, such as drilling fluids, flocculation filtrates. Asphalt from crude oil will also
results in gelation. In some drilling fluids, damage some formations. See Mudding Off.
flocculation may be followed by irreversible
FORMATION PRESSURE - Pressure at the
precipitation of colloids and certain other
bottom of a well that is shut in.
substances from the fluid, e.g., red beds.
FORMATION VOLUME FACTOR -
FLOORMAN - Member of the drilling crew
Reservoir pore volume occupied by a unit
whose work station is about the derrick floor. On
volume of stock-tank oil and its associated gas.
rotary drilling rigs normally there are two
floormen on each drilling crew. FRACTURE - Cracks and crevices in the
formation either inherent or induced.
FLUID FLOW- State of fluid dynamics of a
fluid in motion is determined by the type of fluid FRACTURE OPENING PRESSURE -
(e.g., Newtonian, plastic, pseudoplastic, Pressure required to open an existing fracture.
dilatant), the properties of the fluid such as Because this pressure is sometimes close to the
viscosity and density, the geometry of the closure pressure, these terms are often used
system, and the velocity. Thus, under a given set synonymously. Since the fracture extension
of conditions and fluid properties, the fluid flow pressure is obtained after the opening pressure,
can be described as plug flow, laminar (called these terms are sometimes used interchangeably.
also Newtonian, streamline, parallel, or viscous) FRACTURING - Application of hydraulic
flow, or turbulent flow. See terms and Reynolds pressure to the reservoir formation to create
number. fractures through which oil or gas may move to
FLUID LOSS- The volume of fluid lost to a the well bore.
permeable material due to the process of GAS CONDENSATE - Hydrocarbon fluid
filtration. The API fluid loss is the volume of which exists at a reservoir temperature above
fluid in a filtrate as determined according to the that of the critical point and below
Fluid-Loss Test given in API RP 10B. See cricondentherm of the mixture.
Water Loss.
GAS-OIL RATIO- The number of cubic feet of
FLUID-LOSS ADDITIVE- An additive used gas produced with a barrel of oil.
to reduce the fluid loss of cement slurries.
Material used to maintain adequate injected fluid GEL - Viscous solution or semi-solid dispersion
within the created fracture and to minimize of a solid in a liquid. The solids may be either
damage by controlling fluid leak-off. natural polymers or synthetic polymers. These
solids are composed of fibrous strings of
FLUID MOBILITY - Instantaneous ratio of extremely long molecules. The polymer particles
effective permeability for fluid to its viscosity. swell when placed in a fluid and take part of the
FOAM- A foam is a two-phase system, similar fluid into the fibrous structure. This gives the
to an emulsion, where the dispersed phase is a fluid viscosity which may vary from a slight
gas or air. Dispersion of a gas in a liquid. thickening of the fluid to the creation of a rigid
gel similar to set gelatin. Gels are clear or
FOAMING AGENT - Substance that produces
translucent.
fairly stable bubbles at the air-liquid interface
due to agitation, aeration, or ebullition. In air or GONE TO WATER- Describes a well in which
gas drilling, forming agents are added to run water production is increasing.
water influx into aerated foam. This is GRAVITY, SPECIFIC- The weight of a
commonly called “mist drilling.” Surface active particular volume of any substance compared to
agent capable of stabilizing a foam. the weight of an equal volume of water at a
FORMATION DAMAGE- Damage to the reference temperature. For gases, air is usually
productivity of a well resulting from invasion taken as the reference substance, although
into the formation by mud particles or mud hydrogen is sometimes used.

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GROSS INTERVAL - Vertical distant between circulating water and mud into a completed well
persistent and correlatable log markers above before starting well service operations.
and below the entire reservoir interval.
LAMINAR FLOW- Fluid elements flowing
GUAR GUM- A naturally occurring along fixed streamlines which are parallel to the
hydrophilic polysaccharide derived from the walls of the channel of flow. In laminar flow, the
seed of guar plant. The gum is chemically fluid moves in plates or sections with a
classified as a galactomannan. Guar gum slurries differential velocity across the front which
made up in clear fresh or brine water possess varies from zero at the wall to a maximum
pseudoplastic flow properties. toward the center of flow. Laminar flow is the
first stage of flow in a Newtonian fluid; it is the
HYDRATION - Act of a substance to take up
second stage in a Bingham plastic fluid. This
water by means of absorption and/or adsorption.
type of motion is also called parallel, streamline,
HYDROCARBON - Compound consisting or viscous flow. See Plug and Turbulent Flow.
only of molecules of hydrogen and carbon. Fluid flow where neighboring layers are not
HYDROSTATIC HEAD- The pressure exerted mixed.
by a column of fluid, usually expressed in LEAST PRINCIPAL STRESS- The smallest
pounds per square inch. To determine the principal stress in an elemental cube with one
hydrostatic head at a given depth in psi, multiply face oriented normal to the vertical. This stress
the depth in feet by the density in pounds per is also referred to as Horizontal Effective Stress,
gallon by 0.052. Horizontal Stress, Closure Pressure or HST.
INHIBITOR (CORROSION) - Any agent LINER- Any string of casing whose top is
which, when added to a system, slows down or situated at any point below the surface.
prevents a chemical reaction or corrosion.
LOG - Running account listing a series of
Corrosion inhibitors are used widely in drilling
events in chronological order. The driller’s log is
and producing operations to prevent corrosion of
a tour-to-tour account of progress made in
metal equipment exposed to hydrogen sulfide,
drilling. Electric well log is a record of
carbon dioxide, oxygen, salt water, etc.
geological formations which is made by a well
Common inhibitors added to drilling fluids are
logging device. This device operates on the
filming amines, chromates, and lime.
principle of differential resistance of various
INORGANIC- Compounds of earthy or mineral formations to the transmission of electric
origin such as: water, limestone, dolomite, current.
gypsum, HCl, etc; no carbon compounds are
MALE CONNECTION - Connection with the
included except cyanides or carbonates.
threads on the outside.
INSTANTANEOUS SHUT-IN PRESSURE
MATRIX FLOW - Flow of fluids through the
(ISIP) - The pressure observed during a
permeable formation.
hydraulic fracturing operation immediately
following the shut-in of the well which negates MINI-FRACTURING- A series of tests
pressure transients. The difference between the performed to obtain important information
fracture extension pressure and the instantaneous pertinent to the design of the main fracturing
shut-in pressure is the frictional pressure drop job. These tests include a step rate test, a pump-
across the perforations to the fracture tip. in, flow-back test and a pressure decline test.
These tests yield the fracture extension pressure,
KELLY OR KELLY JOINT - Heavy square
the closure pressure, the instantaneous shut-in
pipe or other configuration that works through a
pressure, the opening pressure, the closure time,
like hole in the rotary table and rotates the drill
and the fluid loss coefficient. Further analysis
stem.
yields the fracture width and the fracture length.
KILLING A WELL - Bringing a well under
MISCIBLE - Solubility of one liquid in
control that is blowing out. A procedure of
another. When a solid dissolves in a liquid, we

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say it is soluble in the liquid, as salt is soluble in NONIONIC- Refers to surfactants which do not
water. When speaking of liquids, we say that ionize and to molecules which neither have
they are immiscible, partially miscible, totally positive nor negative charges. They have oil-
miscible, or miscible in all proportions. soluble and water- soluble ends and the
wettability characteristics are related to the
MONOMER - Simple molecules that join
relative sizes of these ends. Many nonionics will
together to form a polymer are known as
water wet both limestone and sand. They are
monomers and their union is called
often blended with anionics or cationics.
polymerization. k-TROLtm is pumped into a well
as a monomer and polymerizes in the formation NON-NEWTONIAN FLUIDS- Fluids that the
to form a polymer. apparent viscosity changes with agitation or
pump rate, for example, gels, emulsions,
MONTMORILLONITE - Clay mineral
polymers, mayonnaise. These are fluids that
commonly used as an additive to drilling muds.
experience apparent viscosity changes with
Sodium montmorillonite is the main constituent
agitation or pump rate. Examples are gels,
in bentonite. The structure of montmorillonite is
emulsions or polymers.
characterized by a form that consists of a thin
platey-type sheet with the width and breadth OFFSET WELL- Well drilled near another
indefinite, and thickness that of the molecule. one.
The unit thickness of the molecule consists of
OIL-BASED MUD- The term “oil-based mud”
three layers. Attached to the surface are ions that
is applied to a special type of drilling fluid
are replaceable. Calcium montmorillonite is the
where oil is the continuous phase and water is
main constituent in low-yield clays.
the dispersed phase. Oil-based mud contains
MUD- A water- or oil-base drilling fluid whose blown asphalt and usually 1 to 5 percent water
properties have been altered by solids, emulsified into the system with caustic soda or
commercial and/or native, dissolved and/or quick lime and an organic acid. Silicate, salt, and
suspended. Used for circulating out cuttings and phosphate may also be present. Oil-based muds
many other functions while drilling a well. Mud are differentiated from invert-emulsion muds
is the term most commonly given to drilling (both water-in-oil emulsions) by the amounts of
fluids (which see). water used, method of controlling viscosity and
thixotropic properties, well-building materials,
MUD PIT - Earthen or steel storage facilities
and fluid loss.
for the surface mud system. Mud pits which vary
in volume and number are of two types: OIL FIELDS - Area where oil is found.
circulating and reserve. Mud testing and Loosely defined term referring to an area in
conditioning is normally done in the circulating which one or more separate pools or reservoirs
pit system. may be found.
NET PRESSURE- The bottomhole treating OPEN HOLE- The uncased part of the well.
pressure minus closure pressure. The net
OPERATOR- The person, whether proprietor
pressure acts to propagate a fracture.
or lessee, actually operating a mine or oil well or
NEUTRALIZATION - Reaction in which the lease.
hydrogen ion of an acid and the hydroxyl ion of
OPERATING PRESSURE- The pressure at
a base unite to form water, the other ionic
which a line or system is operating at any given
product being a salt.
time.
NEWTONIAN FLUID- Fluids with the same
ORGANIC - Compounds of carbon or carbon
apparent viscosity irregardless of the pump rate
and hydrogen (hydrocarbons). Other elements
or agitation, for example, water, oil, molasses.
may be present in the make-up of the compound.
NON-EMULSIFIER - Substance which Examples are: acetic acid, formic acid, all
demulsifies (breaks) emulsions or prevents their alcohols, natural gas, propane, and crude oil.
formation.

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OXIDATION- Originally meant the PLASTIC VISCOSITY- Plastic viscosity is a

combination of oxygen with some substance. measure of the internal resistance to fluid flow
Now any chemical change in which the valence attributable to the amount, type, and size of
or oxidation state of an element is increased is solids present in a given fluid. It is expressed as
referred to as oxidation. Oxidation is always the number of dynes per sq cm of tangential
accompanied by reduction; that is, when the shearing force in excess of the Bingham yield
valence of one element is increased, the valence value that will induce a unit rate of shear. This
of another is decreased. An example of value, expressed in centipoises, is proportional
oxidation involving a combination with oxygen to the slope of the consistency curve determined
is that when natural gas and butane burn, they in the region of laminar flow for materials
combine with oxygen from the air to form obeying Bingham’s law of Plastic Flow. When
carbon dioxide and water. using the direct-indicating viscometer, the
plastic viscosity is found by subtracting the 300-
PAY ZONE OR PAY FORMATION-
rpm reading from the 600-rpm reading.
Formation drilled into that contains oil and/or
gas in commercial quantities. PLUG BACK - To seal off the bottom section
of a well bore to prevent the inflow of fluid from
PERMEABILITY - Property of a solid medium
that portion of the hole. This permits the inflow
which allows a fluid to flow through its
of oil and gas from the formations above the
interconnected pore network. Unit of
section so sealed off, without contamination of
measurement is the darcy or millicarcy (0.001
fluids below that depth.
darcy). Normal permeability is a measure of
ability of a rock to transmit a one-phase fluid PLUG FLOW - Movement of a material as a
under conditions of laminar flow. unit without shearing within the mass. Plug flow
is the first type of flow exhibited by a plastic
pH- An abbreviation for potential hydrogen ion.
fluid after overcoming the initial force required
The pH numbers range from 0 to 14, with 7
to produce flow.
being neutral, and are indices of the acidity
(below 7) or alkalinity (above 7) of the fluid. POLYMER - Substance formed by the union of
two or more molecules of the same kind linked
PIG- A scraping tool forced through a flow line
end to end into another compound having the
or pipe line to clean out wax or other deposits.
same elements in the same proportion but a
See Rabbit.
higher molecular weight and different physical
PLASTIC FLUID - Complex, non-Newtonian properties, e.g., paraformaldehyde. See
fluid which shear force is not proportional to the Copolymer. The number of simple molecules
shear rate. A definite pressure is required to start that unite to form a polymer molecule can be as
and maintain movement of the fluid. Plug flow great as hundreds or thousands. Synthetic
is the initial type of flow and only occurs in polymers we use are such materials as the FR
plastic fluids. Most drilling muds are plastic compounds, HYG-1 and HYG-2 (gelling agents
fluids. The yield point as determined by direct- for HY-GEL and LOGEL) and the PVC pipe
indicating viscometer is in excess of zero. down at the acid terminal. A substance, often
PLASTICITY- The property possessed by synthetic, composed of giant molecules that
some solids, particularly clays and clay slurries, have been formed by the union of a considerable
of changing shape or flowing under applied number of simple molecules with one another.
stress without developing shear planes or The chemical units occur in a repeating fashion.
fractures. Such bodies have yield points, and The number of simple molecules that unite to
stress must be applied before movement begins. form a polymer molecule can be as great as
Beyond the yield point, the rate of movement is hundreds of thousands.
proportional to the stress applied, but ceases POROSITY- Absolute porosity refers to the
when the stress is removed. See Fluid. total amount of pore space in a rock, regardless
of whether or not that space is accessible to fluid
penetration. Effective porosity refers to the

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amount of connected pore spaces, i.e., the space consistency decreases instantaneously with
available to fluid penetration. See Permeability. increasing rate of shear until at a given point the
viscosity becomes constant. The yield point is
POTASSIUM- One of the alkali metal elements
determined by direct-indicating viscometer is
with a valence of 1 and an atomic weight of
positive, the same as in Bingham plastic fluids;
about 39. Potassium compounds, most
however, the true yield point is zero. An
commonly potassium hydroxide (KOH) are
example of a pseudoplastic fluid is guar gum in
sometimes added to drilling fluids to impart
fresh or salt water.
special properties, usually inhibition.
PUDDLING- In cement evaluation work, the
POUR POINT - Lowest temperature at which a
term applies to agitation of cement slurry in
liquid will flow when a test container (like a test
molds with a rod, to remove any trapped air
tube) is tilted.
bubbles. In field practice, the term has been used
PPM or PARTS PER MILLION- Unit weight to denote the reciprocation or rotation of the
of solute per million unit weights of solution casing during or after a cementing operation.
(solute plus solvent), corresponding to weight-
PUMP-IN/FLOWBACK TEST- A test in the
percent except that the basis is a million instead
minifracturing series with an injection rate
of a hundred. The results of standard API
varying from a minimum of 3 to 5 barrels per
titrations of chloride, hardness, etc, are correctly
minute up to the proposed injection rate at which
expressed in milligrams (mg) of unknown per
the fracturing treatment is to be performed.
liter but not in ppm. At low concentrations, mg/l
Flowback rates vary from 0.25 to 1 bbl/min. The
is about numerically equal to ppm.
closure pressure may be obtained from the
PRECIPITATE - Material that separates out of pressure inflexion during the flowback portion
solution or slurry as a solid. Precipitation of of this test.
solids in a drilling fluid may follow flocculation
PUMP-IN/SHUT-IN TEST- See Pressure
or coagulation, such as the dispersed red-bed
Decline Test.
clays upon addition of a flocculation agent to the
fluid. An insoluble solid substance produced as a PUMPING TIME- Synonymous with
result of a chemical reaction. cementing time except in those instances where
a volume of cement slurry is premixed prior to
PRESSURE - Force per unit area.
displacement in a well. In this instance, the
Bottomhole Circulating Pressure - Pressure at pumping time will be total cementing time
the bottom of a well during circulation of any minus mixing time.
fluid. It is equal to the hydrostatic head plus the
RATE OF SHEAR - Rate at which an action,
annular friction loss required to pump fluid to
resulting from applied forces, causes or tends to
the surface plus any back pressure held at the
cause two adjacent parts of a body to slide
surface.
relatively to each other in a direction parallel to
Bottom Hole Static Pressure - The pressure at their plane of contact. Commonly given in rpm.
the bottom of a well after the well is shut-in long
RELIEF VALVE- A valve that will open
enough to reflect ambient formation pressure.
automatically when pressure gets to high.
Circulating Pressure - The pressure at a
RESERVOIR - Each separate, unconnected
specified depth required to circulate a fluid in a
body of producing formation.
well at a given rate.
RESISTIVITY - Electrical resistance offered to
Surface Pressure - The pressure measured at
the passage of a current, expressed in ohm-
the wellhead.
meters; the reciprocal of conductivity. Fresh-
PSEUDOPLASTIC FLUID - Complex non- water muds are usually characterized by high
Newtonian fluid that does not possess resistivity, salt-water muds by a low resistivity.
thixotropy. A pressure or force in excess of zero
will start fluid flow. The apparent viscosity or

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RETROGRADE CONDENSATE - A SHALE - Fine-grained clay rock with slate-like

condensate reservoir fluid with increasing liquid cleavage, sometimes containing an organic oil-
condensation as pressure declines. yielding substance.
RHEOLOGY - Science that deals with SHEAR (SHEARING STRESS) - An action,
deformation and flow of matter. resulting from applied forces, which causes or
tends to cause two contiguous parts of a body to
RIGGING UP- Before the work of drilling can
slide relatively to each other in a direction
be started, but after the derrick has been built,
parallel to their plane of contact.
tools and machinery must be installed and a
supply of fuel and water must be established. SILICA FLOUR- Silica (SiO2) ground to a
This operation, which in substance is that of fineness equal to portland cement. The fineness
getting the rig ready, is conveniently described of portland cement is specified in API Std 10A.
by the driller’s term “rigging up.”
SKIDDING THE RIG- Moving a rig from the
RISER - Pipe through which liquid travels location of a lost or completed hole preparatory
upward. to starting a new one. In skidding the rig, the
move is accomplished with little or no
ROUGHNECK- A driller’s helper and general
dismantling of equipment.
all-around worker on a drilling rig.
SLIPS- Wedge-shaped toothed pieces of metal
ROUSTABOUT - Laborer who assists the field
that fit inside a bowl and are used to support
foreman in the general work about producing oil
tubing or other pipe.
wells and around the property of the oil
company. The roustabout is a semi-skilled SLURRY DENSITY- The density of a cement
laborer in that he requires considerable training or fracturing slurry expressed in either pounds
to fit him for his work. per gallon or pounds per cubic foot. Light-
weight and heavy-weight slurries are prepared
SACK- Sack is a weight measure. Cement,
by adding suitable additives to modify slurry
bentonite, and barite are marketed in sacks
density.
containing amounts as follows:
SODIUM BICARBONATE - NaHCO3. A
- Cement- 94 pounds
material used extensively for treating
- Sand- 100 pounds contamination and occasionally other calcium
- Bentonite- 100 pounds contamination in drilling fluids. It is the half-
neutralized sodium salt of carbonic acid.
- Barite- 100 pounds
SODIUM CARBONATE - Na2CO3. A
SALT- In mud terminology, the term salt is material used extensively for treating out various
applied to sodium chloride, NaCl. Chemically, types of calcium contamination. It is commonly
the term salt is also applied to any one of a class called “soda ash.” When sodium carbonate is
of similar compounds formed when the acid added to a fluid, it increases the pH of the fluid
hydrogen of an acid is partly or wholly replaced by hydrolysis. Sodium carbonate can be added
by a metal or a metallic radical. Salts are formed to sale (NaCl) water to increase the density of
by the action of acids on metals, or oxides and the fluid phase.
hydroxides, directly with ammonia, and in other
ways. SODIUM CHLORIDE - NaCl. Commonly
known as salt. Salt may be present in the mud as
SANDED UP- Clogged by sand entering the a contaminant or may be added for any of
well bore with the oil. several reasons. See Salt.
SETTLING VELOCITY- The velocity at SODIUM HYDROXIDE - NaOH. Commonly
which a particle of particular size, type, specific referred to as “caustic” or “caustic soda.”
gravity, and concentration will settle in a fluid of Chemical used primarily to impart a higher pH.
a particular specific gravity and viscosity. It is
usually measured in millimeters per second.

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SOLUBILITY - Amount or percent of a STEP-RATE TEST- A minifracturing test

material that dissolves in a certain fluid. For performed to obtain the fracture extension
example, if 1.00 grams of a core was ground up pressure. The test is usually performed by
and placed in excess HC1, and after several pressuring a well at constant rate increments
hours the remaining material was filtered out, (example: 0.5, 1.0, 1.5, ...5 barrels per minute)
dried, weighed, and found to weight 0.70 grams, and plotting the maximum pressure at each step
the soluble portion would be 0.30 gram or 30% vs. the constant rate at each stop. The inflexion
soluble in HC1. point corresponds to the fracture extension
pressure.
SOUR GAS- Gas that smells bad because of
impurities, usually hydrogen sulfide. STRATIFICATION - Natural layering or
lamination usually characteristic of sediments
SPACING- Distance between wells producing
and sedimentary rocks. Stratification is the result
from the same pool (usually expressed in terms
of the settling of particles of different sizes and
of acres, e.g., 10-acre spacing).
specific gravities.
SPECIFIC GRAVITY- Weight of any volume
STUCK- Refers to the drill pipe or casing
of a material divided by the weight of the same
inadvertently becoming fastened in the hole.
volume of a material taken as a standard. For
May occur while drilling is in progress, casing is
solids or liquids, the standard is water. For
being run in the hole or while the drill pipe is
gases, the standard is air. It may also be defined
being hoisted. Frequently results in a fishing job.
as the ratio of the density of a substance to the
density of water or air. We deal mostly with SUBLIME - Pass directly from a solid to a
liquids and solids. The density of water is 1 gaseous state.
gm/cc or 8.33 lb/gal.
SURFACE PIPE – The first string of casing to
SPECIFIC HEAT- Number of calories required be set in a well. The length will vary in different
to raise 1 g of a substance 1 deg Centigrade. The areas from a few hundred feet to three or four
specific heat of a drilling fluid gives an thousand feet. Some states require a minimum
indication of the fluid’s ability to keep the bit length to protect fresh-water sands. On some
cool for a given circulation rate. wells it is necessary to set a temporary
conductor pipe which should not be confused
SPUDDING- Refers to the acting of hoisting the
with surface pipe as described here.
drill pipe and permitting it to fall freely so that
the drill bit strikes the bottom of the well bore SURFACE TENSION - Forces existing in the
with considerable force. This is done to clean the surface film of all liquids which tend to contract
bit of an accumulation of sticky shale that has the volume into a form with the least surface
slowed down the rate of penetration. Careless area. This would be a sphere, or a round droplet.
execution of this operation can result in kinks in The particles in the surface film are inwardly
the drill pipe and damaged bits. attracted thus resulting in tension. Generally, the
force acting within the interface between a liquid
STABBING BOARD -Temporary platform
and its own vapor, which tends to maintain the
erected in the derrick at an elevation of about 20
area of the surface at a minimum and is
to 40 feet above the derrick floor. The
expressed in dynes per centimeter.
derrickman or other crew member works on this
board while casing is being run in a well. SURFACTANT- In the broadest sense, this can
Derived from the term “to stab” meaning to be defined as a “surface active agent.” Or, a
guide a joint while it is being screwed into chemical which, when added to a liquid, will
another joint or section. change the surface tension of the liquid.
Practically, we limit the term to those chemicals
STAND OF PIPE- Two or three or sometimes
that lower the surface tension of liquids. A
four joints of pipe fastened together, called a
material that raises the surface tension of a
double, thribble, or fourble, respectively.
liquid we usually call an emulsifier. Materials
that tend to concentrate at an interface. Used in

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drilling fluids to control the degree of hole. This survey is used to find the location of
emulsification, aggregation, dispersion, inflows of water into the hole, where doubt
interfacial tension, foaming, defoaming, wetting, exists as to proper cementing of the casing and
etc. for other reasons.
SWABBING- Operation of a lifting device to TENSILE STRESS- The perpendicular
bring well fluids to the surface when the well components of internal stress exert a pull
does not flow naturally. This is a temporary between the two parts of the mass which
operation to determine whether or not the well constitutes a tensile stress. A pull-apart stress.
can be made to flow. In the event the well does
TONGS- A wrench type item used to tighten or
not flow after being swabbed, it is necessary
loosen drillpipe or casing connections.
then to install a pump as a permanent lifting
device to bring oil to the surface. TOOL PUSHER - Foreman in charge of one or
more drilling rigs or supervisor of drilling
SWIVEL - Hose coupling which forms a
operations.
connection between the slush pumps and the
drill string and permits rotation of the drill TORQUE- A measure of the force or effort
string. applied to a shaft, causing it to rotate. On a
rotary rig this applies especially to the rotation
TALLY - Measure and record length of pipe or
of the drill stem in its action against the bore of
tubing.
the hole. Torque reduction can usually be
TEARING DOWN - Act of dismantling a rig at accomplished by the addition of various drilling-
the completion of a well and preparing it for fluid additives.
moving to the next location.
TOUR- The word which designates the shift of
TECTONIC- Pertaining to the rock structures a drilling crew or other oil field workers is
and external forms resulting from the pronounced usually as if it were spelled t-o-w-e-
deformation of the earth’s crust. r. The word does not refer to the derrick or
tower, as some seem to think, the day tour starts
TEMPERATURE- The degree of heat usually
at 7 or 8 in the morning. The evening tour starts
expressed as degrees Fahrenheit.
at 3 or 4 o’clock in the afternoon. The morning
- Bottomhole Circulating Temperature - The tour starts at 11 p.m. or midnight (sometimes
temperature of any fluid at the bottom of the referred to as graveyard tour). The almost
well while it is being circulated. universal practice in oil well drilling is to work
- Bottom Hole Static Temperature - The 8-hour tours or shifts.
temperature attained at the bottom of a well after TRIP - Pull or run a string of rods or tubing
the well is shut-in. See Static Temperature. from or into a well.
- Circulating Temperature - The temperature TUBING JOB- The pulling and running of
of any fluid at any specified depth in well while tubing.
it is being circulated, as measured inside casing
TURBIDITY - Measure of the resistance of
or drill pipe.
water to the passage of light through it. It is
- Static Temperature - The temperature caused by suspended and colloidal matter in the
attained at a specified depth in a well after the water.
well is shut-in long enough to reflect the
TURBULENT FLOW - Fluid flow in which
ambient formation temperature.
the velocity at a given point changes constantly
TEMPERATURE STABILITY - Chemical in magnitude and the direction of flow pursues
characteristics of a material which determine its erratic and continually varying courses.
resistance to thermal decomposition. Turbulent flow is the second and final stage of
TEMPERATURE SURVEY - Operation to flow in a Newtonian fluid; it is the third and
determine temperatures at various depths in the

© 2005, Halliburton 1 • 34 Stimulation I

 Introduction to Stimulation

final stage in a Bingham plastic fluid. See or in some cases by a capillary block of the
Critical Velocity and Reynolds Number. pores due to surface tension phenomena.
UNDER-REAM - To enlarge a drill hole below WET GAS - Gas that carries a lot of liquids
the casing. with it.
V-DOOR (WINDOW) - An opening in a side WETTING AGENT- A substance or
of a derrick at the floor level having the form of composition which, when added to a liquid,
an inverted V. This opening is opposite the increases the spreading of the liquid on a surface
draw-works. It is used as an entry to bring in or the penetration of the liquid into a material.
drill pipe and casing from the pipe rack.
WORKOVER - Perform one or more of a
VELOCITY - Time rate of motion in a given variety of remedial operations on a producing oil
direction and sense. It is a measure of the fluid well with the hope of restoring or increasing
flow and may be expressed in terms of linear production. Examples of work-over operations
velocity, mass velocity, volumetric velocity, etc. are deepening, plugging back, pulling and
Velocity is one of the factors that contribute to resetting the liner, squeeze cementing, shooting,
the carrying capacity of a drilling fluid. and acidizing.
VELOCITY, CRITICAL - Velocity at the WORMHOLE - Large, highly conductive
transitional point between laminar and turbulent channels that result from the matrix reaction of
types of fluid flow. This point occurs in the acid with highly reactive sections of the
transitional range of Reynolds numbers of formation. Usually a wormhole starts by
approximately 2,000 to 3,000. enlarging already large permeable vugs or pores
and moves forward as it creates additional
VISCOMETER (VISCOSIMETER)- An
surface area.
apparatus to determine the viscosity of a fluid or
suspension. Viscometers vary considerably in YIELD- A term used to define the quality of
design and methods of testing. clay by describing the number of barrels of a
given centipoise slurry that can be made from a
VISCOSITY- The internal resistance offered by
ton of the clay. Based on the yield, clays are
a fluid to flow. This phenomenon is attributable
classified as bentonite, high-yield, low-yield,
to the attractions between molecules of a liquid,
etc., types of clays. Not related to yield value
and is a measure of the combined effects of
below. See API RP 13B for procedures.
adhesion and cohesion to the effects of
suspended particles, and to the liquid YOUNG’S MODULUS - Ratio of stress to
environment. The greater this resistance the strain of a material undergoing elastic strain.
greater the viscosity. See Apparent and Plastic
ZINC CHLORIDE- ZnCl2. A very soluble salt
Viscosity.
used to increase the density of water to points
VUGS- Natural cavities formed in certain more than double that of water. Normally added
formations due to leaching out of soluble to a system first saturated with calcium chloride.
minerals. These cavities are lined with a
crystalline material and a composition different
from that of the surroundings. The size of a vug Common Oilfield Acronyms
may vary from a small pea to a large boulder.
WATER BASE GELLING AGENT - Polymer ACE - Automatic Controlled Equipment
which thickens or gels water. (formerly HIC) - used in HES pumping
equipment
WATER BLOCK- Reduction of the
permeability of a formation caused by the API - American Petroleum Institute
invasion of water into the pores (capillaries). ASME - American Society of Mechanical
The decrease in permeability can be caused by Engineers
swelling of clays, thereby shutting off the pores,
BHA - Bottom Hole Assembly

© 2005, Halliburton 1 • 35 Stimulation I

 Introduction to Stimulation

BOM - Bill of Material HEI - Halliburton Energy Institute - a learning

center in Duncan, OK which provides training
BOP - Blow Out Prevention
for employees and customers
CAST -V - Circumferential Acoustic Scanning
HIPS - Halliburton Integrated Proposal System
Tool - This new generation tool brings higher
resolution, precise digital information, and HPHT - High Pressure High Temperature
simultaneous measurements for complete
HWO - Hydraulic Work Over. Well Control and
acoustic visualization in both open and cased
well maintenance duties.
holes.
ID - Inside Diameter
CBL - Cement Bond Log
ILAN - Instrument Local Area Network used for
CEMS - Computerized Equipment Management
UNIPRO communications
System - field system for tracking equipment
and repairs IRJ - Irregular Job Report
CFU - Combination Frac Unit JLAN - Job Local Area Network used for
ARC/ACE communications
CIBP - Cast Iron Bridge Plug
JSA - Job Safety Analysis
CLAM - Constant Level Additive Mixer
LGC - Liquid Gel Concentrate
CSNG - Compensated Spectral Natural Gamma
Ray LTA - Lost Time Accidents
DAS - Data Acquisition System - used in Coil LWD - Logging While Drilling - part of the
Tubing, TCCs, COMPUPACs with ACQUIRE HDS business
DOT - Department of Transportation - US M/LWD - Measurement/Logging While
Federal Agency Drilling
DST - Drill Stem Test - measure pressures at MBU - Mobile Business Unit - a team with
bottom hole equipment which can deliver products and
services to the customer
EMI - Electrical Micro Imaging (EMI(tm))
Service provides cost -effective technology for MLWD - Measurement While Drilling and
formation and reservoir evaluation with core - Logging While Drilling
like electrical micro -conductivity images of the MRIL - Magnetic Resonance Imaging Log
formation sequence.
MSDS - Material Safety Data Sheet
EPA - Environmental Protection Agency - US
Federal Agency responsible for environmental MWD - Measurement While Drilling - system
regulations. which tracks drill bit location
FAR pack - Field Activity Reporting package MWD/LWD - Measurement While
Drilling/Logging While Drilling
FOP - Field Operating Profit
N2 - Nitrogen services
FSQC - Field Service Quality Coordinator
NORM - Naturally Occurring Radioactive
FSR - Field Service Representative Material - as it relates to the EPA
GIH - Grease Injector Head NWA - Natural Work Area - A method of
GOHFER - Grid Oriented Hydraulic Fracture dividing up North America into regions which
Replicator - Stim -Lab, Inc version of a 3D have similar product and service requirements
fracture simulator OD - Outer Diameter
HEC - Hydroxy Ethyl Cellulose OH - Open Hole

© 2005, Halliburton 1 • 36 Stimulation I

 Introduction to Stimulation

OIP - Operator Interface Panel - used by a increasing technical and customer needs on a
person to control a UC global basis. Successful completion of the
program is expected to lead to promotion of the
OSHA - Occupational Safety and Health
Participant from entry level (or experienced
Administration - Federal US Agency responsible
candidates from within Halliburton) to a revenue
for worker safety
producing Service Supervisor in field
PBR - Polish Bore Receptacle operations.
PCI - Pumping Control Interface - a VME box SSIT - Service Supervisor in Training - is
PD&C - Product Development & responsible for successful wellsite job execution
Commercialization in a safe and efficient manner. The Service
Supervisor's emphasis is on operational
PM - Preventive Maintenance - system of excellence and customer satisfaction for long
checks that ensure equipment is kept at term growth and profitability of the NWA.
minimum standards to prevent failures during
normal operation. SSSV – Sub-Surface Safety Valve

PO - Purchase Order StimWin - Stimulation Design Software

POOH - Pull Out Of Hole T&E - Travel & Entertainment - System of

tracking these expenses
PPE - Personal Protective Equipment - used for
personal safety in performance of duties - TA - Technical Advisor
coveralls, gloves, eye protection, hearing TC - Team Coordinator -The PSL Team
protection Coordinator Functions as a team leader and
PSW - Pumping Services Workstation - coach for the Service Supervisors. The Team
Realtime data acquisition & display software. coordinator provides personnel development for
the MBU Team and champions best practices
PTA - Plug to Abandon and process improvements.
QA - Quality Assurance TCP - Tubing Conveyed Perforating PSL
QC - Quality Control TD - Target Depth
RIH - Run in Hole TIMS - Technical Information Management
RTO - Real Time Operations - delivery of real System
time data from wellsite to Halliburton/Client TTTCP – Tools, Testing and Tubing-Conveyed
office, typically via use of the Mobile Net Perforating.
satellite system
UWI - Unique Well Identifier
SC - Service Coordinator - is a customer
focused member of the PSL and Asset WAN - Wide Area Network
Management Team. The Service Coordinator WIT - Wellhead Isolation Tool
provides technical and operational expertise,
ZI - Zonal Isolation (ZI) is a process used in
champions service excellence, creating customer
petroleum well construction which keeps fluids
satisfaction. The Service Coordinator deploys
in one permeable zone of the well bore separate
equipment, materials, and personnel with focus
from fluids of another zone. Once the well has
on optimizing utilization and profit.
been drilled and lined with pipe, the connection
SO - Shipping Order between the geological formation and the well
SPE - Society of Petroleum Engineers/Society must be established and assured. Completion
of includes installing suitable tubing or casing, and
cementing this casing, using casing plugs and
SSDP - Service Supervisor Development packers.
Program is designed to train Supervisors to meet

© 2005, Halliburton 1 • 37 Stimulation I

 Introduction to Stimulation

Common Halliburton Acronyms What that really means is, the HMS is what we
do, how we do it, who is responsible, how we
know we've done it, and how can we make it
BU - Business Unit
better.
CAPE - Concurrent Art to Production
HPM - Halliburton Performance Management -
Environment
This function includes Market and Business
CBT - Computer-Based Training Analysis, Strategic Planning, PSL Marketing
CEMS - Computerized Equipment Management and the Product Development and
System - field system for tracking equipment Commercialization Initiative Champion
and repairs HR - Human Resource department
COE - Common Office Environment – An HRD - Human Resource Development -This
architecture of PCs that standardizes software department drives performance -focused change
and hardware throughout the company. of our people, processes, and organization,
CPI - Correction, Prevention, and Improvement. supporting Halliburton’s goal of becoming a
Halliburton’s quality improvement system. high -performing organization. Using the
developmental solutions approach, HRD
CPS - Completion Products & Services PSL – A develops and implements specific processes that
reservoir focused set of Completion Solutions change and improve performance (processes
including Subsurface Products, Sand Control, collectively known as interventions) to support
Slickline, SEWOP, and Surface Products our clients’ business needs
CT - Coiled Tubing and all its components HSE - Health, Safety, and Environment. Refers
CVA - Cash Value Added - The CVA for a to department policies for ensuring our
period is a good estimate of the cash flow compliance with HSE regulations.
generated above or below the investor's IS - Integrated Solutions PSL -was established,
requirement for that period. See also NOVA uniting the best people, technology, products,
EJCS - End of Job Customer Satisfaction and equipment to offer oil and gas companies
Survey the most effective and profitable solutions to
their challenges
F&A - Finance and Administration
IT - Information Technology
FPD - Focused Product Development Process
used in Technology Centers ITP - Integrated Technology Products -The
purpose of the Integrated Technology Products
FSQC - Field Service Quality Coordinator Group is to offer solutions with reservoir
FSR - Field Service Representative performance focus; champion the rapid
development and introduction of new
HALCO21 - Halliburton’s team and processes technologies that cross PSL boundaries; focus
for revolutionizing business processes globally on cross -PSL technology delivery as a business;
to provide dramatic improvements for and commercialize multi-PSL solutions based on
Halliburton Company, enabling our success in value creation transfer technology to countries.
the 21st Century
JSA - Job Safety Analysis
HEI - Halliburton Energy Institute – the
development center in Duncan, Oklahoma, KBR - Kellogg Brown and Root – Halliburton’s
which provides training for employees and business unit that provides a full spectrum of
customers services: project development, technology
licensing and development, consulting, project
HMS - Halliburton Management System - is an management, engineering, procurement,
integrated management system designed to meet construction, operations and maintenance
operations, quality, health, safety, and services.
environmental management systems needs.

© 2005, Halliburton 1 • 38 Stimulation I

 Introduction to Stimulation

KPI - Key Performance Indicator; used as a champions service excellence, creating customer
measure in Service Quality PII satisfaction. The Service Coordinator deploys
equipment, materials, and personnel with focus
L&P - Logging and Perforating PSL
on optimizing use and profit.
MBU - Mobile Business Unit - a team with
SS - Shared Services - the enabler for change by
equipment, which can deliver products and
pulling together the various functions that were
services to the customer
common to all our operations under one
NOVA - Net Operating Value Added management structure that exists along side of
NWA - Natural Work Area - A method of the other mainstay processes of acquisition and
dividing up the United States into regions which execution. Through this model each Business
have similar product and service requirements Unit is able to access the resources necessary to
acquire and execute its work, yet gain the
PD&C - Product Development & efficiencies and synergies available by "sharing"
Commercialization key services between Business Units.
PE - Production Enhancement PSL SSDP - Service Supervisor Development
PII - Performance Improvement Initiative - Program is designed to train Supervisors to meet
Three areas of Performance we can focus on in increasing technical and customer needs on a
the delivery of our services, In addition to our global basis. Successful completion of the
financial performance. -Doing the Job Right the program is expected to lead to promotion of the
First Time by Using Standard Processes and Participant from entry level (or experienced
Procedures -Reducing Injuries by Better candidates from within Halliburton) to a revenue
Management of Risk -Protecting the producing Service Supervisor in field
Environment by Reducing the Amount of Waste operations.
Created and Using Environmentally Friendly SSDS - Sperry-Sun Drilling Services
Operating Practices
SSIT - Service Supervisor in Training - is
PPR - People Performance Results - part of the responsible for successful wellsite job execution
People Performance Management system used in a safe and efficient manner. The Service
to establish goals, provide feedback on Supervisor's emphasis is on operational
performance, assess performance and deliver excellence and customer satisfaction for long
pay or other incentive based rewards term growth and profitability of the NWA.
PSL - Product Service Line T&E - Travel & Entertainment - System of
PSMT - Product Service Management Team tracking these expenses

QA - Quality Assurance TA - Technical Advisor

QC - Quality Control TC - Team Coordinator -The PSL Team

Coordinator functions as a team leader and
RTO - Real Time Operations - delivery of real coach for the Service Supervisors. The Team
time data from wellsite to Halliburton/ Client Coordinator provides personnel development for
office, typically through use of the Mobile Net the MBU Team and champions best practices
satellite system and process improvements.
SC - Service Coordinator - is a customer- TTTCP - Tools & Testing and Tubing-
focused member of the PSL and Asset Conveyed Perforating PSL
Management Team. The Service Coordinator
provides technical and operational expertise,

© 2005, Halliburton 1 • 39 Stimulation I

 Introduction to Stimulation

Unit A Quiz

Fill in the blanks with one of more words to check your progress in Unit A.
1. Stimulation treatments refer to ____________ and _______________.

2. What are three (3) design requirements necessary for a successful job design?

3. BOP is the acronym for ____________ __________.

4. The first string of casing in a well is called ___________________ ______________________.

5. Who is responsible for the safety of the crew?

6. PTA is the acronym for ____________ __________ __________.

7. The most common method of perforating incorporates __________-__________ __________ .

8. Proppant is used to provide passages for __________ or __________ to flow into the well.

Now, look up the suggested answers in the Answer Key.

© 2005, Halliburton 1 • 40 Stimulation I

 Introduction to Stimulation

Answer Key
Refer to the pages provided as references if you answered any of these items incorrectly, or if you
were unsure of your answers.
Items from Unit A Quiz Refer to
Page
1. Acidizing/fracturing 5

2. Fluid type, viscosity requirements, fluid rheology, fluid safety, economics of

fluid, proppant selection, material availability, experience with local formations,
laboratory data on the formation(s). 5

3. Blowout preventer 9

4. Surface Casing 7

5. Service Supervisor 18

6. Plug to abandon 35

7. Shaped-charged explosives 11

8. Oil/gas 13

© 2005, Halliburton 1 • 41 Stimulation I

Section 2

Calculations

Table of Contents
Introduction ............................................................................................................................................... 2-3
Objectives .............................................................................................................................................. 2-3
Unit A: Definitions .................................................................................................................................... 2-4
Unit A Quiz............................................................................................................................................ 2-6
Unit B: Capacity, Rate, and Hydrostatic Pressure ..................................................................................... 2-7
Rectangular Volume .............................................................................................................................. 2-7
Cylindrical Volume................................................................................................................................ 2-8
Capacity ................................................................................................................................................. 2-8
Annular Capacity ................................................................................................................................... 2-9
Hydrostatic Pressure ............................................................................................................................ 2-10
Fill-Up.................................................................................................................................................. 2-10
Rate ...................................................................................................................................................... 2-10
Unit B Quiz .......................................................................................................................................... 2-12
Unit C: Fluid Flow................................................................................................................................... 2-13
Newtonian vs. Non-Newtonian Fluids................................................................................................. 2-13
Fluid Density........................................................................................................................................ 2-14
Fluid Flow Patterns .............................................................................................................................. 2-14
Friction Pressure .................................................................................................................................. 2-15
Unit C Quiz .......................................................................................................................................... 2-16
Unit D: Job Design Calculations ............................................................................................................. 2-17
Working with Equations ...................................................................................................................... 2-17
Bottomhole Treating Pressure.............................................................................................................. 2-18
Friction Loss in Pipe ............................................................................................................................ 2-18
Slurry Density and Volume.................................................................................................................. 2-19
Wellhead Pressure................................................................................................................................ 2-21
Hydraulic Horsepower ......................................................................................................................... 2-21
Pump Rate............................................................................................................................................ 2-22
Unit D Quiz.......................................................................................................................................... 2-23
Self-Check Test: Calculations ................................................................................................................. 2-25
Answers to Unit Quizzes ......................................................................................................................... 2-27
Self-Check Test Answer Key............................................................................................................... 2-32

2•1 Stimulation I
© 2005, Halliburton
 Calculations

Use for Section notes…

© 2005, Halliburton 2•2 Stimulation I

 Calculations

Introduction
Stimulation work today ranges from very small,
one transport acid jobs to large frac jobs where Objectives
more than 1 million gallons of fluid are pumped.
Since the best job for a given set of conditions
needs to be run, the design of these jobs is After completing this section, you will be able to
critical. Although it may seem that small and • Calculate the capacity of tubing
large jobs have little in common, this is not the
case. Every stimulation job is affected by some • Calculate the capacity of an annular volume
of the same factors such as fluid properties, flow • Calculate tank volumes
rates, and well configurations. These factors are
the basis for job calculations, which are essential • Calculate wellhead, friction, hydrostatic and
to stimulation work. Job design relies on the bottom hole treating pressures
values that these calculations give. This section • Calculate hydraulic horsepower
is designed to help you understand the “how and requirements
why” of the calculations necessary for
stimulation work. • Calculate slurry density and volumes
• Calculate the size of additive pump needed
for a given additive concentration.

© 2005, Halliburton 2•3 Stimulation I

 Calculations

Unit A: Definitions
There are a variety of terms used in calculations D’arcy’s Law - For linear flow as in through a
for stimulation work. These terms need to be sand plug in casing.
clearly defined and understood before a job
design can be attempted. This unit defines many kA∆P
of these terms and can be used as a reference µL
when necessary.
where:
Absolute Permeability -Absolute Permeability
is the D’arcy‘s law permeability. K = Permeability
A = Area
Absolute Volume Factor - Absolute Volume ∆P = Delta Pressure
factors typically refer to units of gallons per
µ = Viscosity
pound (liters per kilogram). This is the absolute
L = Length
volume that a solid will take up in water. One
pound of Ottawa sand will take up 0.0452 Density - The Density of a body is its mass per
gallons of space in a liquid environment. One unit volume. Water density is 8.33 lb per gallon
kilogram of Ottawa sand will take up 0.3774 at 70°F.
liters of space in a liquid environment. For
example, in pouring one pound of sand into a Dirty Volume - Dirty Volume is the "clean”
one gallon jar of water, 0.0452 gallons of water volume plus the volume of the proppant.
will be displaced from the jar. Effective Permeability - Effective Permeability
Barrel – Oil field barrel is 42 gallons. is the permeability to one fluid in a multi-fluid
system and is a function of the fluid saturation.
BHTP - The Bottom Hole Treating Pressure, or
BHTP, is the amount of pressure required at the Flash Point - Flash Point refers to the lowest
perforations to cause fracture extension. Many temperature at which vapors above a volatile
times this value is reported as the “frac combustible substance ignite in air when
gradient.” The gradient is calculated by dividing exposed to spark or flame.
the BHTP by the depth to the center of the Frac Gradient - (Hydrostatic pressure at
perforations. perforation mid point + ISIP) divided by depth
bbl/min - This term refers to the pump rate or of perforation mid point.
Barrels Per Minute (use bpm instead of Hydrostatic Pressure - Hydrostatic Pressure
bbl/min). reflects the pressure exerted by a vertical column
bpm - This term refers to the pump rate or of fluid. This pressure is calculated from the true
Barrels Per Minute. vertical height and density of the fluid.
Hydrostatic pressure is not area sensitive.
Closure Pressure - Closure Pressure is the
amount fluid pressure required to reopen an ISIP – ISIP (PISIP) is the instantaneous shut-in
existing fracture. This pressure is equal to, and pressure. It can be determined during a pump-in
counteracts, the stress in the rock perpendicular test. The pumps are brought on line at a rate that
to the fracture plane. This stress is the minimum will cause the formation to fracture ("break
principal in-situ stress and is often called the down"). Fluid is pumped into the formation for a
closure stress. short time then pumping is stopped. ISIP reflect
the amount of pressure recorded immediately
Clean Volume - Clean Volume refers to the after shutting the pumps down. ISIP values can
volume of the treating fluid without taking into be hard to determine if the bottom hole slurry
account proppant.

© 2005, Halliburton 2•4 Stimulation I

 Calculations

rate is not zero and/or water hammer is psi. The movement of fluid past a stationary
introduced. Graphical methods are used to object causes this friction, which in this case is
determine an ISIP when water hammer is the pipe wall.
present by extrapolating back along a straight
Pperf - The friction caused by fluid flow through
line section to the intersection of the first rise of
a perforation or group of perforations. This
the first oscillation of the water hammer.
symbol stands for perforation friction.
HHP - Hydraulic Horsepower is a unit of
Porosity – A fractional or percentage value
measurement for the amount of work that is or
Referring to the void spaces inside a rock or the
can be done by hydraulic equipment. HHP can
part of the rock that is not rock.
be calculated by (pressure × rate)/40.8
Relative Permeability - Relative permeability is
Mgal - The M is the Roman numeral for one-
the ratio of the effective permeability to the
thousand. Therefore, this refers to Thousands of
absolute permeability of the porous medium.
Gallons. Used in concentration statements.
Slurry Volume - Slurry Volume is the total
Net Pressure - Net Pressure is defined as the
volume of fluid, additives, and proppants. This
difference in ISIP pressure and closure pressure.
reflects the total volume of fluid that is pumped
Permeability - Permeability is a function of the also referred to as Dirty Volume.
geometry, configuration, and scalar dimensions
Specific Gravity - Specific Gravity is a unit-less
of the voids or pores and is not as such a
ratio relationship between a substance and a base
physical property derived from a dynamic
substance. For liquids, the base is water, so the
system.
specific gravity of water is 1.0 (8.33/8.33). For a
Ph - This symbol is used for hydrostatic 10 lb/gal brine the specific gravity will be
pressure, the pressure exerted at the bottom of a 10.0/8.33=1.2. For gases, air is the base
fluid column. (Note that the P in this and the substance.
following symbols refers to pressure.)
Temperature Gradient - Temperature Gradient
Pw - The Wellhead Pressure is the gauge defines a linear relationship of temperature to
measured treating pressure at the surface. depth. Temperature Gradient from a well at
10,000 feet at 200°F and surface temperature of
∆Pfrict - The symbol ∆ indicates delta (or
68°F would be (200-68) /10 = 13.21°F per 1000
incremental) change; therefore, ∆P means the
feet.
gradual change in pressure. Pfrict stands for
“friction loss in pipe,” as measured by units of

© 2005, Halliburton 2•5 Stimulation I

 Calculations

Unit A Quiz

Fill in the blanks with one or more words to check your progress in Unit A.
1. The term BHTP stands for the bottomhole _____________________ _______________________.

2. The BHTP gradient is also referred to as the ______________________ gradient.

3. bbl/min refers to the pump rate in ___________________________________.

4. ISIP is the _______________________ ______________________ pressure, which can be

determined during a __________________________ test. In this test, the formation is fractured.

5. Pw stands for ____________________________ pressure.

6. Pfrict is the ______________________________ loss in pipe.

7. ________________________ is defined as the part of the rock that is not rock.

8. Dirty volume is the _______________________ plus the __________________________.

9. Hydrostatic pressure is calculated from _________________________ and ____________________.

10. Net pressure is defined as the difference between ___________________ and __________________.

Now, compare your answers with the Answer Key.

© 2005, Halliburton 2•6 Stimulation I

 Calculations

Unit B: Capacity, Rate, and Hydrostatic Pressure

Capacity calculations are important in Solution:
stimulation work. They are used in calculating
Volume = L× W× H = 20 ft× 16 ft× 10 ft
displacement volume as well as pit or tank (a)
volume. Hydrostatic pressure is equally = 3200 ft 3
important in basic stimulation design equations.
At the end of this unit you should be able to (b) Conversion factor for ft3 to bbl = 0.1781
bbl/ft3
• calculate open pit or unmarked tank volume
bbl
Volume = 3200 ft 3 × 0.1781 3
• volume of pipe based on its inner diameter ft
• rate of pumping from observing pits or tanks = 569.92 bbl

• displacement volume This can also be used to calculate the volume of

• hydrostatic pressure at a certain point in the a rectangular open pit.
hole. Pit Example:
A pit has the dimensions of 12 ft deep, 30 ft
Rectangular Volume wide and 40 ft long. How many barrels will it
hold? How many gallons will it hold?
Looking first at rectangular objects, volume can Solution:
be calculated by multiplying length, by width,
bbl
by height. Figure 2.1 illustrates these Volume = 12 ft × 30 ft × 40 ft × 0.1781
dimensions. ft 3
= 2,564.64 bbl

gal
2 ,564 .64 bbl × 42 = 107,714.88 gal
bbl
Height A useful way to gauge how much fluid remains
Width in a tank or pit is to get a bbl/in. of depth or
Length bbl/ft of depth factor.

Figure 2.1 – The three basic dimensions. In the tank example, what is the bbl/in. factor?
Solution:
A uniform tank that is 10 ft high has a total
Tank Example: volume of 569.92 bbl. Therefore,
The tank illustrated in Figure 2.1 is 10 feet high,
in
20 feet long and 16 feet wide. 10ft × 12 = 120 in deep
ft
What is the volume, expressed in cubic feet 569.92bbl bbl
(ft3)? What is the volume expressed in barrels rate factor = = 4.7493
(bbl)? 120in in. of depth
If you measure the fluid level in the tank and
find 66 inches of fluid, how many barrels are
there?

© 2005, Halliburton 2•7 Stimulation I

 Calculations

bbl We can calculate a bbl/in. or bbl/ft factor for a

Volume = 66in × 4.7493 = 313.456 bbl vertical cylindrical tank. If the tank is horizontal
in
(such as an acid transport) the volume factor
In our pit example, what is the bbl/ft factor? changes for each inch. This method will not
2564.64bbl bbl work for containers that change in area as they
Factor = = 213.72 change in height. Horizontal cylindrical tanks
12ft ft
should have a gauge stick or a table that shows
volume remaining per in. or ft of depth.
Cylindrical Volume What is the bbl/in. factor for the previous
cylindrical tank example? What is the bbl/ft
You can calculate the volume of cylindrical factor?
objects by multiplying the circular flat surface Solution:
area by the height. Figure 2.2 illustrates these
dimensions. in
20ft × 12 = 240 in.
For oilfield calculations, you will determine ft
areas based on diameter (d), so the equation for 629.459 bbl bbl
factor = = 2.623
the area of a circle is: 240 in. in.
Ac = 0.7854 × d 2 629.459 bbl bbl
factor = = 31.473
20ft ft
So, the calculation for the volume of a cylinder
is: If we are pumping from a tank and we know the
bbl/in. or bbl/ft factor, we can calculate the
Volume = (Area) × (Height) pumping rate. Use a watch to time how long it
so, takes to pump out a certain depth of fluid (i.e.,
one inch, six inches, one foot, etc.). Since we
Volume = 0.7854 × d × d × Height have a rate in inches or feet per minute, and
know our factor, we can then calculate a rate.
Diameter Using the cylindrical tank example above, what
is our pump rate if we are pumping from the
tank at 1 ft/10 minutes?

Height Solution:
bbl 1.0ft
Rate = 31 .473 × = 3.1473 BPM
Radius ft 10 min

Figure 2.2
Capacity
Cylindrical Tank Example: Capacity is a term frequently used when talking
What is the volume of a cylindrical tank 15 feet about volume. When referring to the oilfield, it
in diameter and 20 feet high in barrels? is the volume a certain length of pipe will hold.
When knowing the shape of a pipe is round, the
Solution: volume can be calculated by hand.
V = 0.7854 × 15ft × 15ft × 20ft = 3534.3ft 3 This calculation can be greatly simplified by
bbl using a handbook, such as the Halliburton
3534.3ft 3 × 0.1781 3 = 629.459 bbl Cementing Tables (the Red Book). In the
ft
Capacity Section (Section 210), you’ll find
capacity factors for various sizes of drill pipe,

© 2005, Halliburton 2•8 Stimulation I

 Calculations

tubing and casing. Currently, these are listed as

gallons per foot, barrels per foot, and cubic feet
per foot.
To apply this information, locate the table for
the type of pipe; drill pipe, tubing or casing.
Next, locate the size and weight of a pipe in the
two left columns. (For tubing, it is four
columns.) Then find the volume units desired
across the top. Read the conversion factor where
the columns intersect. For example, to find the
capacity of 4 1/2 in., 16.60 lb/ft internal upset
drillpipe in gallons, locate 4 1/2 in. 16.60 lb/ft in
the two left columns. Then locate gallons per Figure 2.3 – The annulus of a cased hole.
foot at the top (third column from left) and read
the capacity factor at the intersection. The
capacity factor is 0.5972 gal/ft. Multiply the To calculate annular capacities, you need to
capacity factor by the length of pipe in feet to know the size and weight of the outside tubular
calculate the capacity of this pipe. as well as the size and weight of the inside
tubing or casing. If you know this information,
Capacity Example:
you can refer back to the Red Book, Section 221,
What is the capacity of 5000 feet of a 5 1/2 in., to calculate factors involving volume and height
17.0 lb/ft casing in gallons? What is the capacity between tubing, tubing and casing, casings, or
in barrels? drill pipe and casing.
Solution: Annular Capacity Example:
gal We have a 2-3/8 in, 4.7 lb/ft tubing inside of 7
Capacity (gal) = 0.9764 × 5000ft = 4882 gal
ft in., 26 lb/ft casing. There is a packer set at 7500
bbl ft. What is the number of barrels of water
Capacity (bbl) = 0.0232 × 5000ft = 116 bbl needed to completely fill the annulus?
ft
This is the amount of fluid needed to displace all Solution:
the treating fluids out of the casing or to load it. To calculate the capacity factor, open the Red
Book to Section 221, Vol. & Hgt. Between:
Tbgs., Tbg & Csg., Csgs, D.P. & Csg.
Annular Capacity
Find the table with the heading: Inside Tubing
Annular Capacity is the volume contained O.D. 2.375"
between the outside of the drill pipe or tubing ONE STRING
and the open hole or inside of the casing (Figure
2.3). Look for 7”, 26.00 row
From the “Barrels Per Lin Ft” column, the factor
is 0.0328 bbl/ft.
bbl
Volume = 7500ft × 0.0328 = 246 bbl
ft

© 2005, Halliburton 2•9 Stimulation I

 Calculations

Hydrostatic Pressure Solution:

psi
Hydrostatic Pressure is the force exerted by the Ph = 6000ft × 0.433
ft
weight of a column of fluid and expressed in
= 2598 psi
pounds per square inch (psi). The size or shape
of the hole or container makes no difference.
The true vertical height of the fluid column and
the density (lb/gal) of the fluid are the only
Fill-Up
factors involved in hydrostatic pressure.
Hydrostatic pressure can be calculated at any The Fill-Up of pipe is defined as the length of
depth in a hole or container. pipe a specified volume will fill. Fill-up factors
are listed in Section 210 (Capacity) of the Red
The best method for this calculation is to use the Book.
Hydrostatic Pressure and Fluid Weight
Conversion Tables in Section 230 of the Red Fill-Up Example:
Book. The extreme left column of the table gives How many feet of 2-7/8 in., External Upset
the fluid densities in lb/gal. For each fluid (EUE), 6.5 lb/ft tubing will 25 barrels of acid
density, the table lists its weight per cubic foot fill?
(lb/ft3) and kilogram per liter (kg/L), its specific
gravity and the pressure in lb/sq in. for one ft of Solution:
depth (psi/ft). Fill-up Factor = 172.76 ft/bbl (from Red Book)
To determine the density of a fluid without the ft
Red Book you can multiply the fluid’s weight in Fill = 172.76 × 25 bbl = 4319 ft
bbl
lb/gal by 0.05195 to get an approximate
hydrostatic pressure of the fluid.
Hydrostatic Pressure Example: Rate
The fluid weight of 12.0 lb/gal times 0.05195
equals 0.6234 psi/ft. You need the ability to calculate additive rates in
order to pick the right size of pump for a job.
Solution: Additive concentrations for job designs are
The Red Book value is 0.6234 psi/ft. given as “gallons per thousand gallons”
(gal/Mgal). From this information, and the
Example: “clean” rate, you can calculate the gallons per
The density of fresh water is 8.33 lb/gal at 68°F. minute the additive pump must deliver.
This exerts a pressure of 0.433 psi/ft (See Also, you need the ability to calculate the
below). With perforations at 6000 ft, what is the amount of time fluid takes to go from surface to
hydrostatic pressure at that location? perforations or the “travel time” for a fluid. This
is typically called "pipe time" or “time to
perforations”. To calculate the pipe time in
minutes, begin with the capacity of the tubulars
7 in.- 29 lb/ft
Casing being used, and then divide by the pump rate.
8.33 lb/gal
Additive Rate Example:
6,000 ft The crosslinker has to be injected at 4 gallons
Perf Location per thousand gallons (4 gal/Mgal) while
6,100 ft
pumping at a "clean” rate of 25 bbl/min. What is
Total Depth the pump rate in gal/min for the additive pump?

Figure 2.4

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 Calculations

Solution: Now, reworking the previous example:

First convert clean rate from bbl/min to gal/min: 25 bbl 0.042 gal
× 4 gal × = 4.2
min bbl min
bbl gal gal
Clean Rate = 25 × 42 = 1050
min bbl min Pipe Time Example:
gal gal We have a "slurry rate" of 25 bbl/min, pumping
1050 ×4
min Mgal gal through 6000 ft of 3 ½ in, 9.3 lb/ft, N-80 tubing.
Additive Rate = = 4.2 What is the travel time through the tubing?
gal min
1000
Mgal Solution:
To shorten the above process, take the two steps From the Red Book’s Capacity section, we have
and make them one step by taking the constants: 114.99 Linear feet per barrel for the 3 ½” tubing.
So:
42 gal 1
× bbl
bbl 1000 gal Pipe Capacity = 6000ft × 0.00870 = 52.2 bbl
ft
combine them into: 52.2 bbl
Pipe Time = = 2.09 min.
42 gal bbl
25
1000 gal bbl min

to get:
0.042
bbl

© 2005, Halliburton 2 • 11 Stimulation I

 Calculations

Unit B Quiz

Solve the following problems to check your progress in Unit B:

1. If we have a rectangular tank that is 132 in. wide, 21 ft long and 6 ft deep, what is the volume of the
tank in barrels? In gallons?

2. We are pulling fluid from a pit that is 50 ft long, 30 ft wide and 15 ft deep, what is the volume of the
pit in barrels? In gallons?

3. What is the bbl/ft of depth factor for question 1? For question 2?

4. How many barrels of water is in a cylindrical tank that is 20 ft high with a diameter of 6 ft?

5. If you are pumping out the cylindrical tank in question 4 at 1 ft/minute, what is the pump rate in
bbl/min?

6. You are on a job reflecting the following data:

2 7/8 in, 6.5 lb/ft external upset N-80 tubing

5 ½ in, 15.50 lb/ft J-55 casing

A packer is on the end of the tubing and set at 8000 ft

Perforations are at 8213 ft

Treatment fluid is 9 lb/gal, 30 lb/Mgal WG-19

ClaySta XP added at 4 gal/Mgal

ScaleChek added at 1 gal/Mgal

Surface clean pump rate of 18 bbl/min

Calculate:

a. Displacement to perforations in barrels

b. Pipe time to perforations

c. Amount of fresh water (8.33 lb/gal) needed to fill annulus in barrels

d. d. Hydrostatic pressure at perforations.

e. Additive pump rate needed for the ClaySta XP? For the ScaleChek?

Now, look up the answers in the Answer Key.

© 2005, Halliburton 2 • 12 Stimulation I

 Calculations

Unit C: Fluid Flow

Successful stimulation treatments are dependent Shear is the movement of one fluid particle past
on the characteristics of the stimulation fluid. another. Shear rate is computed by the equation
Understanding these characteristics will lead to of Shear Rate = Velocity / Length.
better job design and performance.
Units for shear rate are reciprocal seconds (sec-
1
Flow behavior of a fluid is affected by ). Figure 2.5 shows the ideal system of two
parallel plates with a distance between them of L
• the rheological properties of the fluid
and with one plate moving at a velocity V.
(viscosity and shear)
• the dimensions of the tubular goods
• the rate of flow through the pipe
In this unit, you will learn about these topics:
• Newtonian and Non-Newtonian fluids
• Fluid density
• Fluid flow patterns
• Friction pressure
Figure 2.5
Newtonian vs. Non-Newtonian
Fluids In pipe flow, pressure drop represents shear
stress and velocity of the shear rate. When using
Fluids such as water, acid, and most crude oils a Fann Viscometer, shear stress can be
that contain no additives are classified as determined from the dial reading and the shear
Newtonian (or true) fluids. To understand the rate from the rotational speed of the sleeve.
definition of a Newtonian fluid, you must
understand the definitions of two other terms, The most common rheological test performed on
viscosity and shear. fracturing fluids is the shear stress/shear rate
test. This data is used to construct a flow curve
The viscosity of a fluid is the physical property of which the slope is the fluid's viscosity. Higher
that characterizes the flow resistance of simple rates of shear result from faster movement of the
(Newtonian) fluids. Viscosity is responsible for fluid particles.
the frictional drag (or viscous force) which one
part of the fluid exerts on an adjacent part if the Temperature, however, has a strong effect on the
two parts are in relative motion. viscosity of fluids. Liquid viscosity decreases
with the increase of temperature. Gas viscosity
Viscosity is a measure of a fluid's resistance to increases with an increase in temperature.
the deformation rate. Said another way, viscosity
is the measure of a fluid's resistance to flow. The definition of a Newtonian fluid, then, is that
Viscosity is generally written with the Greek it has the same viscosity at all flow rates or shear
rates. In comparison, non-Newtonian fluids do
symbol mu (µ) and reported in units of
not have constant viscosity at all flow rates or
centipoise (cp).
shear rates.
The higher the viscosity, the higher the fluid's
resistance is to flow.

© 2005, Halliburton 2 • 13 Stimulation I

 Calculations

Most of the fluids we use in the oilfield are non- only relevant at a given shear stress or shear
Newtonian "pseudo plastic" or shear thinning rate.
fluids. This behavior is represented graphically
From the shear rate equation,
in the figure below.
Shear Rate = Velocity
Length
60 there will be a different shear rate and as a
50 result, a different viscosity for different
40
geometry’s. So the shear rate down the tubing,
30
casing and fracture will all have different
20
viscosities due to the different shear rates
10

0
0 100 200 300 400 500 600 700 800
To help minimize the confusion of reporting
Shear Rate apparent viscosity at arbitrary shear rates, it has
Figure 2.6 become standard practice to report apparent
viscosity based on either 100 or 300 rpm
(revolution per minute) speeds of the Model 35A
In general, the addition of chemicals such as Fann Viscometer. Halliburton assumes that all
fluid loss additives, gelling agents, friction apparent viscosity values are at the 300 rpm with
reducers, and emulsifiers to a Newtonian fluid a B1 bob for linear gels and 100 rpm with a B2
tends to change the fluid to a non-Newtonian bob for crosslinked gels unless otherwise stated.
type. The viscosity of a Newtonian fluid is a
constant ratio of shear stress to shear rate.
Fluid Density
As for non-Newtonian fluids, because their flow
curves are not linear or linear but not passing The density of fracturing fluids must be
through the origin viscosity is not constant but is considered since it affects hydrostatic pressure.
a function of shear rate. Apparent viscosity, or The density of a fluid is expressed in units of
µa, is often used when referring to the pounds per gallon (lb/gal). The proppant
consistency of non-Newtonian fluids. The concentration added to fracturing fluids affects
apparent viscosity of non-Newtonian fluids at the density of the treating slurry. Therefore, this
any shear rate represents the viscosity of value must be known when performing
Newtonian fluids at the same shear stress and calculations to find density and hydrostatic
shear rate (Figure 2.7). pressures.
Adding proppant to a fluid will also increase the
fluid’s apparent viscosity and thus its friction
60 characteristics will increase.
50

40

30 Fluid Flow Patterns

20

10
Two types of fluid flow patterns will be
0
0 100 200 300 400 500 600 700 800 discussed here: Laminar and Turbulent. Both are
Shear Rate
depicted in Figure 2.8.
Figure 2.7
Laminar flow is the smooth steady flow of a
fluid.
Apparent Viscosity then, is a simplistic view of Turbulent flow is fluctuating and agitated. When
the consistency of a non-Newtonian fluid and a fluid is in turbulent flow, friction is at
maximum. Eddies and currents are in the flow

© 2005, Halliburton 2 • 14 Stimulation I

 Calculations

stream. Lower viscosity fluids change from Friction is affected mainly by rate, pipe
laminar to turbulent flow at lower velocities. As diameter, pipe roughness, pipe length, viscosity
the viscosity of a system goes up it will take a and density. As the flow rate increases for a
greater velocity to achieve turbulence. given fluid, the friction pressure increases. As a
fluid moves into turbulent flow, the friction
The distinction between the two flow patterns
pressure also increases. As a pipe’s diameter
was first demonstrated by a classic experiment
increases, friction pressure decreases due to the
performed by the British physicist Osborne
decrease in velocity.
Reynolds. By injecting a colored dye into a
stream of fluid moving at a low flow rate, To determine the friction pressures of a fluid,
Reynolds found that the jet of the dye flowed use the Halwin\StimWin program "Friction." To
intact along with the main stream and no cross use this program, you will need to select the
mixing occurring. fluid you are interested in and input the tubular
sizes and lengths. Then hit the "DO" button and
When the flow rate was increased to critical
you can view the results in graphical or text
velocity, the velocity at which turbulent flow
format.
starts, the thread of color disappeared and the
color diffused uniformly throughout the entire Figure 2.9 is the graphical output for WG-11
cross-section. pumped through 10,000 feet of 3 ½ in., 9.3 lb/ft
tubing. Read pump rate across the bottom (X
axis) and the corresponding pressure for a
particular rate on the left hand (Y axis).

Friction Pressure
WG-11, 40.0
100009
8 Pressure 1
7
6
Rate W4
5
1 5.00 279.7
4

3
Friction Pressure (psi)

10009
8
7
6

Figure 2.8- Fluid flow types. 4

100 2 3 4 5 6 7 8 9 2 3 4 5 6 7 8 9
1 10 100
Rate (bpm)

Friction Pressure StimWin v4.3.0

20-Jul-00 14:34

Figure 2.9 – StimWin output.

As a fluid is pumped through tubing or casing, a
certain amount of friction is created. This is due
to fluid moving past the pipe wall (shear).

© 2005, Halliburton 2 • 15 Stimulation I

 Calculations

Unit C Quiz

Fill in the blanks with one or more words to check your progress in Unit C.
1. A Newtonian fluid has the same ____________________________ regardless of the rate of
___________________________.

2. Density of fracturing fluids must be considered since it affects ______________________________.

3. Two fluid flow patterns of fluids are _______________________ flow and ____________________
flow.

4. Friction pressure is dependent upon _________________, ________________, _________________,

__________________, and __________________.

5. Halliburton assumes that all apparent viscosity values for linear gels are at _____________ rpm with
a B1 bob, unless otherwise stated.

6. The Halwin/StimWin program that is used to calculate friction is _________________________.

Now, look up the suggested answers in the Answer Key.

© 2005, Halliburton 2 • 16 Stimulation I

 Calculations

Unit D: Job Design Calculations

In this unit you will learn how to calculate:
• Bottomhole Treating Pressure (BHTP) WHTP
Maximum friction
• Friction Loss in Pipe ( Pfrict) pressure occurs at
the top of the well.
• Slurry Density (ρ) and Volume Maximum
hydrostatic pressure

P -Hydrostatic
•

P - Friction
Wellhead Pressure (WHTP) occurs at the bottom
of the well.
• Hydraulic Horsepower (HHP)
• Pump Rate (Q)
When Halliburton prepares to mobilize BHTP
equipment for a stimulation treatment, two
major job variables must be determined. These
are: Figure 2.10 -

• What is the estimated Wellhead Treating

Pressure? (WHTP) As stated in the definitions:
• What is the proposed pumping rate? BHTP: The pressure inside the formation.
Calculating these two variables helps us Hydrostatic Pressure, Ph : The fluid column’s
determine the Hydraulic Horsepower, blending pressure (as a function of the fluid density).
and proppant delivery equipment to spot on
location. Friction Pressure, Pfrict : Pressure due to fluid
movement in the pipe. The faster we pump, the
To make these calculations, it is advisable to higher the velocity and the higher the Pfrict.
always draw a wellbore sketch. This helps you
to visualize fluid movement through the Therefore, WHTP is influenced by BHTP, Ph,
wellbore and the resulting forces which must be and Pfrict. Always remember the following:
overcome to properly place the stimulation • The higher the BHTP, the higher the
treatment. WHTP.
Where does WHTP come from? Simply stated, • The higher the pump rate, the higher the
WHTP is the surface pressure required to pump fluid velocity which causes higher Pfrict and
into the formation. Looking at the basic wellbore results in higher WHTP.
diagram helps to define the problem:
• The higher the fluid column density, the
higher the Ph and the lower the WHTP.

Working with Equations

Before beginning the actual calculations in this
unit, two basic principles about equations must
be understood. First, an equation is a
mathematical statement (simple expression in

© 2005, Halliburton 2 • 17 Stimulation I

 Calculations

English) that says two things are equal or evenly BHTP = Pisip + Ph
balanced.
PISIP = 1800 psi (given)
For example, the equation BHTP = PISIP + Ph
Hydrostatic pressure for 8.33 lb/gal
says that bottomhole treating pressure is equal to
fresh water = 0.4330 psi/ft (from Red Book)
instantaneous shut-in pressure (PISIP) plus
hydrostatic pressure. (Ph) psi
Ph = 0.4330
× 7050ft
Keep in mind that you can rewrite an equation ft
and not affect its value. You can perform the = 3052.65 psi
same operation (that is, add, subtract, multiply, BHTP = 1800psi + 3052.65psi
or divide by the same number or symbol) on
= 4852.65psi
both sides of an equation.
In another example, assume you know the value
of BHTP and the Ph. You need to calculate the Friction Loss in Pipe
value of PISIP. You can rewrite the equation for
BHTP (presented above) by subtracting Ph from To calculate the friction loss for a treating
both sides: tubular, you will use the “StimWin” program
BHTP - Ph = PISIP + Ph – Ph “Friction.” Keep in mind that the fluids in
“Friction” do not have breakers in them, the
On the right side of the equation, Ph minus Ph fluids on location may be off by some
cancels out, so you are left with BHTP - Ph = percentage. Also be aware that the roughness for
PISIP. You can now solve for PISIP by subtracting the tubular has not been taken into account.
Ph from BHTP.
Example:
What is the friction pressure in the tubing under
Bottomhole Treating Pressure these conditions?

To calculate bottomhole treating pressure Tubing is 2 3/8 in. OD, 1.995 in. ID,
(BHTP), you will also need to know fluid 4.7 lb/ft, EUE, J-55 with a packer at 8500 ft.
density and the depth of the perforations.
Knowing the fluid’s density, you can then use Casing is 5 1/2 in., 4.892 ID, 17 lb/ft, J-55, LTC
the Hydrostatic Pressure and Fluid Weight Perforations are at 8560 ft.
conversion tables from the Red Book to find the
psi/ft pressure gradient. Hydrostatic pressure Treating fluid is fresh water at 8.33 lb/gal.
(Ph) can be calculated by multiplying the psi/ft Pump rate is 10 bbl/min.
value and the depth of the perforations.
a. Solution:
Example: a. In “StimWin” choose “Fresh Water”
What is the BHTP under the following b. Set the rate from 1 to 10 bbl/min,
conditions?
c. Set Increment to 1
Tubing is 2 3/8 in., 4.7 lb/ft, EUE, J-55 to 7000
ft. d. Use Internal n’ and K’,
Casing is 5 1/2 in., 20 lb/ft, J-55 to 7100 e. Go to the Wellbore tab by clicking the
right or left arrow on the toolbar.
Perforations are at 7050 ft.
Well fluid is 8.33 lb/gal fresh water.
f. Navigation icons
PISIP = 1800 psi
g. Fill in the tubing and casing information
Solution:
h. Hit F5 key or click the “DO” icon

© 2005, Halliburton 2 • 18 Stimulation I

 Calculations

specific gravity is measured in grams per cc

i. DO icon (cubic centimeter).
j. Click the “Text Output” Icon So, the Bulk Density (or Specific Gravity) is
measured as if the proppant were a solid and not
made up of individual particles.
k. Text icon

l. h. The program arrives at the value of Example:

10318.6 psi at 10 bbl/min. What is the slurry density (lb/gal) and slurry
volume (gal) of fresh water with 2 lb/gal Ottawa
proppant added?
Slurry Density and Volume
Solution:
Slurry density is an extremely important factor Set up a table as shown:
in stimulation. It is used during the calculations Absolute
of BHTP and friction pressure while running Absolute
Materials Volume
Materials Volume
sand-laden fluid. (pounds) Factor
(gallons)
(gal/lb)
On a fracturing job, proppant is added to the gel
on a lb/gal basis. For example, one pound of dry Fresh
8.33 ---- 1
Water
sand will be added to one gallon of fluid.
Because sand adds density and volume, the Sand 2 0.0452 0.0912
resulting slurry density and volume will change. TOTALS 10.33 lb 1.0912 gal
The absolute volume factors in Table 2.1 will be
used to help calculate slurry density and volume Divide total pounds by total gallons to calculate
in the following example problems. slurry density.
Table 2.1 – Absolute Volume Factors lb 10.33 lb lb
Slurry Density = = = 9.4666
Bulk Specific Absolute gal 1.0912 gal gal
PROPPANT TYPE Density Gravity Volume
(lb/ft3) (g/cc) (gal/lb) The total of the absolute volume column (in
20/40 Ottawa 95.9 2.65 0.0452 gals) is also referred to as "dirty" volume.
20/40 AcFRAC BLACK 102 2.55 0.0470 If you were to run 2,000 gallons of water with 2
20/40 AcFRAC BLACK 100 2.57 0.0466 lb/gal Ottawa sand, then "clean" volume is 2,000
20/40 SUPER HS 95.5 2.55 0.0470
gallons. The "dirty" volume is the "clean"
volume plus the sand volume (in gallons). Total
20/40 ECONO- PROP 96 2.70 0.0444
pounds of sand would be 2000 gal × 2 lb/gal =
20/40 CARBO- LITE 97 2.71 0.0442 4000 lb. Sand volume (in gallons) is the total
16/20 CARBO- LITE 97 2.71 0.0442 pounds of sand times the absolute volume factor
20/40 CARBO- PROP 117 3.27 0.0366
for sand. In this case the sand volume is 4000 lb
× 0.0452 gal/lb.
16/30 INTER- PROP 120 3.32 0.03671
To calculate "dirty" volume:
20/40 INTER- PROP 120 3.13 0.0383
12/18 CARBO HSP 2000 128 3.56 0.3366 ⎛ gal ⎞
Dirty Vol = 2000 gal + ⎜ 4000 lb sand × 0.0452 ⎟
16/30 CARBO HSP 2000 128 3.56 0.3366 ⎝ lb ⎠
20/40 CARBO HSP 2000 128 3.56 0.3366 = 2000 gal + 180.8 gal
30/60 CARBO HSP 2000 128 3.56 0.3366 = 2180.8 gal
3
(1 ft is equal to one sack of proppant)
The absolute volume of proppant is calculated
from the specific gravity of the proppant. The

© 2005, Halliburton 2 • 19 Stimulation I

 Calculations

Example: maximum allowable value. Usually, the job is

shut down at that point.
What is the slurry density and "dirty" volume?
Example:
• Fracturing fluid is Diesel #2 with a density
of 7.33 lb/gal. We are pumping 2% KC1 water (8.43 lb/gal)
with 4 lb/gal 20/40 Ottawa sand. The casing is
• Sand concentration is 10 lb/gal. 4-1/2 inch, 10.5 lb/ft. Perforations are at 3,000
Stage size is 10,000 gallons "clean" volume. ft. As soon as the 4 lb/gal stage gets to the perfs,
the well screens out. How many sacks of sand
Solution: are left in the casing? What is the hydrostatic
Absolute
Absolute pressure at the perforations?
Materials Volume
Materials Volume
(pounds) Factor gal
(gal/lb)
(gallons) Casing Capacity = 3000ft × 0.6699
ft
Diesel #2 7.33 ---- 1 = 2009.7 gal
Sand 10 0.0452 0.452
Therefore, we have 2009.7 gallons of slurry in
TOTALS 17.33 lb 1.452 gal the casing. In order to calculate the sand volume
we need to use the equation.
lb 17.33lb lb
Slurry Density = = = 11.935
gal 1.452gal gal Volume Factor = 1 + (Prop Conc × Abs Vol)
lb gal
"Dirty" Volume = = 1 + (4 × 0.0452
"Clean" volume + (sand concentration × gal lb
clean volume × absolute volume factor) = 1 + 0.1808 = 1.1808
⎛ lb gal ⎞ To calculate the clean volume, rearrange the
10,000 gal + ⎜⎜10 × 10,000 gal × 0.0452 ⎟
lb ⎟⎠
following equation:
⎝ gal
= 14,520 gal " dirty" volume Slurry Volume = Clean Vol × Volume Factor
Slurry Volume
Instead of using a table you can use the Clean Vol =
Volume Factor
following equations for Slurry Density, Slurry
2009.7 gal
Volume, and Volume Factor: Clean Vol =
1.808
ρ BaseFluid (lb/gal) + Prop Conc(lb/gal)
ρ Slurry = = 1701.9817 gal 2% KCL water
Volume Factor
Now to calculate the sand volume:
where:
lb
Wsand = 1701.9817 gal × 4 = 6807.927 lb
ρSlurry = Slurry Density gal
ρBaseFluid = Base Fluid Density Since there are 95.9 lb of Ottawa sand in one
Prop Conc = Proppant Concentration sack: (Table 2.1):
Volume Factor = 6807.9268 lb
Vs = = 71 sacks of sand
⎛ lb
⎛ lb ⎞ ⎛ gal ⎞ ⎞⎟ 95.9
1 + ⎜⎜ Prop Conc⎜⎜ ⎟⎟ × Abs Vol factor⎜ ⎟
⎝ lb ⎠ ⎟⎠
sk
⎝ ⎝ gal ⎠
To calculate the hydrostatic pressure, we need to
One place where an understanding of slurry use a different equation:
density and volume is necessary is when a well
"screens out". A screen out occurs when fluid
and proppant can no longer be pumped into the
formation and causes the pressure to reach its

© 2005, Halliburton 2 • 20 Stimulation I

 Calculations

Slurry Density =
Base fluid density + sand concentration • Casing is 7 in., 20 lb/ft, J-55 to 7900 ft.
volume factor
• Packer is at 7700 ft.
The volume factor (1.1808) has already been
calculated. • Flow rate is 20 bbl/min.
lb lb • Perforations are two shots per foot, 0.40 in.,
8.43 +4 at 7750 ft to 7775 ft (50 shots).
gal gal
Slurry Density =
1.1808 • Treating fluid is fresh water mixed with
lb WG-18, at 30 lb/1000gal. From the StimWin
12.43 Frict Program, we should get a total pipe
gal
= friction value of 2966.1 psi to the top perf.
1.1808
lb • Assume that perforation friction is zero.
= 10.5268
gal • Instantaneous shut-in pressure with fresh
water is 1775 psi.
lb
Ph Gradient = 10.5268 × 0.05195 Calculate pressure at the wellhead (Pw) by using
gal
this formula:
psi
= 0.5469 Pw = PISIP + Pf rict+ Pperf
ft
psi Solution:
Ph = 3000 ft × 0.5469
ft PISIP = 1775 psi (given)
= 1640.6 psi Pfrict = 2966.1 psi (from the Friction Program)
or Pw = 1775psi + 2966.1psi + 0psi
Ph = 3000 ft × 0.5455 (RedBook) = 4741.1psi
= 1636.5 psi

Hydraulic Horsepower
Wellhead Pressure
Two equations may be used to determine
The equation for calculating pressure at the hydraulic pressure (HHP). The unit in which the
wellhead is flow rate is given in (bbl/min or gal/min) should
Pw = BHTP - Ph + Pfrict + Pperf or determine the equation used.
= PISIP + Pfrict + Pperf (since PISIP = BHTP - Ph) ⎛ bbl ⎞
Pw (psi )× Rate ⎜ ⎟
Where: ⎝ min ⎠
HHP =
BHTP = Bottomhole Treating Pressure 40.8
or
Ph = Hydrostatic Pressure
⎛ gal ⎞
Pfrict = Fluid friction from Surface to the top Pw (psi) × Rate ⎜ ⎟
HHP = ⎝ min ⎠
perforation 1713.6
Pperf = Fluid friction across all perforations The value 1713.6 is 40.8 × 42 gal/bbl
PISIP = Instantaneous Shut In Pressure Example:
Example: What is the HHP under these conditions?
• Tubing is 2 7/8 in., 6.5 lb/ft, EUE, J-55 to • Pressure at the wellhead is 3000 psi
7700 ft.
• Injection rate is 30 bbl/min.

© 2005, Halliburton 2 • 21 Stimulation I

 Calculations

Solution: psi
P lb = 0.433 × 9100 ft = 3940.3 psi
⎛ bbl ⎞
h- 8.33 ft
Pw (psi ) × Rate ⎜
gal
⎟
⎝ min ⎠ = 0.5195
psi
× 9100 ft = 4727.45 psi
HHP = P lb
40.8 h-10
gal ft
bbl ∆Ph = 4727.45 psi − 3940.3 psi = 787.15 psi
3000 psi × 30
= min
40.8
The change is an increase in Ph
= 2205.88 HHP
Example:
P lb = 1800 psi − 787.15 psi = 1012.85 psi
ISIP-10
What is the Pfrict, Pw, and HHP under these gal

conditions? Pperf = 150psi (given)

• Tubing is 2 3/8 in., 4.7 lb/ft, EUE, N-80 Pw = 1012.85 psi + 6300 psi + 150 psi
• Packer at 9000 ft = 7462.85 psi

• Casing is 5 1/2 in., 17 lb/ft, N-80 to 9500 ft bbl

7462.85 psi × 30
Pw × Rate min
• Perforations are at 9100 ft HHP = =
40.8 40.8
• Well fluid is fresh water. PISIP with fresh = 5487.390 HHP
water = 1800 psi
• Frac using 10 lb/gal salt water with WG-6
mixed at 40 lb/1000 gal and CW-1 mixed Pump Rate
at 10 lb/1000 gal
By rewriting the base equation for HHP, you can
• Injection rate is 5 bbl/min. Pfrict gradient for
obtain an equation for calculating bbl/min.
the tubing is 70 psi/100 ft
Multiply both sides of the equation by 40.8:
• Assume Pfrict in the casing is zero
HHP × 40.8 = Pw × Rate
• Assume Pperf to be 150 psi
Solution: Now divide both sides by Pw. This gives you rate
in bbl/min.
psi
Pfrict = 70 × 9000ft = 6300psi HHP × 40.8 ⎛ bbl ⎞
100ft = Rate ⎜ ⎟
Pw ⎝ min ⎠
Pw = PISIP + Pfrict + Pperf
Example:
Pisip with fresh water = 1800 psi (given).
What is the maximum pump rate in bbl/min that
Fracturing fluid is 10 lb/gal.
can be delivered at maximum psi under these
Solution to the problem requires PISIP be conditions?
calculated with 10 lb/gal fluid.
• Treating fluid is 15% HC1 acid, 8.962 lb/gal
• 1000 HHP is available at the location.
• Maximum wellhead pressure is 5700 psi.
Solution:
⎛ bbl ⎞ 1000 HHP × 40.8 bbl
Rate ⎜ ⎟= = 7.1579
⎝ min ⎠ 5700 psi min

© 2005, Halliburton 2 • 22 Stimulation I

 Calculations

Unit D Quiz

Solve the following problems to check your progress in Unit D.

1. What is the BHTP under these conditions?
Perforations are at 8000 ft.
Well fluid is 9.3 lb/gal salt water.
Pisip = 1200 psi.

2. What is the BHTP gradient under these conditions?

Perforations are at 9050 ft.
Well fluid is 9.7 lb/gal salt water.
Pisip = 1975 psi.

3. What is the Pisip with sand-laden fluid? (Assuming we might have an unexpected shutdown.)
Perforations are at 7450 ft.
BHTP gradient is 0.65 psi/ft
Fracturing fluid is 2% KC1 water mixed with WG-11 at 60 lb/1000 gal, WAC-11 at 20 lb/Mgal and
20/40 Ottawa sand at 5.5 lb/gal.
Density of 2% KC1 water is 8.42 lb/gal.

4. Tubing is 2 7/8 in., 6.5 lb/ft, EUE, N-80 with packer at 9000 ft.
Casing is 7 in., 23 lb/ft, J-55 to 9200 ft.
Perforations at 9050 ft
Well fluid is 10 lb/gal salt water.
PISIP with 10 lb/gal fluid is 2000 psi.
Fracture using 10% salt water at 8.93 lb/gal mixed with WG-17 at 40 lb/1000 gal
Proppant is 20/40 Econoprop
Injection rate is 20 bbl/min.
Pfrict gradient is 38.3 psi/100 ft. (Disregard Pfrict in casing and Pperf)

a) What is the displacement to the perfs in barrels?

b) How many barrels of fresh water are needed to fill the annulus?

c) What is the tubing friction pressure?

d) What is the wellhead pressure?

e) What is the required HHP?

© 2005, Halliburton 2 • 23 Stimulation I

 Calculations

f) If you are on the 5 lb/gal proppant stage and the well screens out with the well full of
slurry, what is the hydrostatic pressure at the perfs?

g) How much proppant is left in the well (sacks)?

Now, look up the suggested answers in the Answer Key.

© 2005, Halliburton 2 • 24 Stimulation I

 Calculations

Self-Check Test: Calculations

Fill the blanks with the best answer to the following items. (NOTE: You will need a Red Book for
reference during this self-check test.)
1. The flow pattern of fluid where fluid velocity and friction are high, and the fluid moves primarily as
one unit is called what? ___________________ ______________________.

2. bbl/min stands for _______________ _____ ______________.

3. Perforations are at 8,000 ft. The well fluid is 2% KC1 water which is 8.42 lb/gal. PISIP = 2,575 psi.
Calculate BHTP:
_______________ psi/ft × 8,000 ft = _______________ psi
BHTP = 2,575 psi + _______________ psi = ______________ psi

4. Perforations are at 11,000 ft. BHTP gradient is 0.82 psi/ft.

BHTP = _______________ psi

5. Perforations are at 9,060 ft.

BHTP gradient is 0.72 psi/ft.
Fracturing fluid is 2% KC1 water mixed with WG-19 at 40 lb/Mgal
Proppant is 20/40 Econoprop at 3 lb/gal
Calculate PISIP with sand-laden fluids.

Materials Materials Absolute Absolute

(Pounds) Volume Factor (Gal/Lb) Volume (Gallons)
2% KC1 _______________________ _________________________ ____________________
Proppant _______________________ _________________________ ____________________
TOTAL _______________________ lb _________________________gal/lb ____________________ gal
Slurry Density = __________________lb/gal
BHTP = _______________________ ft × _________________________psi/ft = ____________________ psi
Ph = _______________________ ft × _________________________psi/ft = ____________________ psi
PISIP = _______________________ psi - _________________________psi = ____________________ psi

6. Casing is 5 1/2 in., 20 lb/ft, J-55 to 6300 ft. Perforations are at 6300 ft.
Treating fluid is salt water mixed with WG-17 at 40 lb/1000 gal.
Injection rate is 40 bbl/min. Pfrict gradient is 7.68 psi/100 ft.
Pfrict = _________________ psi

© 2005, Halliburton 2 • 25 Stimulation I

 Calculations

7. Tubing is 2 7/8 in., 6.5 lb/ft, EUE, J-55 to 6600 ft

Perforations are at 6750 ft.
Well fluid is 2% KC1 water, 8.43 lb/gal
Pw = 6000 psi.
Injection rate is 12 bbl/min.
Assume Pperf = 0.
What is the hydraulic horsepower required? = _______________ HHP
8. Casing is 4 1/2 in., 11.6 lb/ft, N-80 to 11,000 ft.
Tubing is 2 3/8 in, 4.7 lb/ft.
Perforations are at 10,875 ft.
Packer is at 10,500 ft.
Well fluid is 2% KC1 water (8.42 lb/gal).
Pisip with well fluid is 2900 psi.
Fracturing fluid is 25 lb Delta fluid(using WG-22) in 2% KC1 water.
Crosslinker is being added at 2 gal/Mgal.
Sandwedge is being added at 4 gal per sack
Injection rate is 10 bbl/min.
You are pumping out of a rectangular tank 20 ft long, 10 ft wide, and 8 ft deep. Pperf is 200 psi. Pfrict
gradient is 41.96 psi/100 ft in the tubing. Pfrict in casing can be assumed to be negligible.
Calculate:
a. Displacement to perfs in bbl?
b. Water needed to fill annulus in bbl?
c. Tank volume in bbl?
d. How fast the tank level is dropping (in./min)?
e. Pfrict = ________________ psi/ _______________ ft × ______________ ft = _____________ psi
f. Pw = __________ psi + __________ psi + ___________ psi = _________ psi
g. HHP = _____________
h. You are going to pump 15,000 gals with 8 lb/gal Interprop 20/40. If the well screens out as soon as
the 8 lb/gal stage gets to the perfs, how many sacks of Interprop are left in the well?
i. What is the hydrostatic pressure at the perfs in question ‘h’?
j. What is the top of proppant in wellbore?
k. What is the pump time to the top perf?
l. What rate will be required of the liquid additive pump running crosslinker?
Now, look up the suggested answers in the Answer Key.

© 2005, Halliburton 2 • 26 Stimulation I

 Calculations

Answers to Unit Quizzes

Items from Unit A Quiz
1. treating pressure
2. Frac
3. Barrels Per Minute
4. instantaneous shut-in/pump-in
5. Wellhead
6. Friction
7. Porosity
8. Clean Volume/Volume of Proppant
9. True Vertical Height and Density of Fluid
10. ISIP Pressure and Closure Pressure

Items from Unit B Quiz

132 in.
× 21 ft × 6 ft = 1386ft 3
in
12
ft
bbl
1386ft 3 × 0.1781 3
ft
1. = 246.847 bbl
gal
246.8466 bbl × 42
bbl
= 10,367.56 gal

50 ft × 30 ft × 15 ft = 22,500 ft 3
bbl
22,500 ft 3 × 0.01781 3
ft
2. = 4007.25 bbl
gal
4007.25 bbl × 42
bbl
= 168,304.5 gal
246.8466 bbl bbl
Q1= = 41.14
6ft ft
3.
4007.25 bbl bbl
Q2= = 267.15
15 ft ft

© 2005, Halliburton 2 • 27 Stimulation I

 Calculations

A c = 6ft × 6ft × 0.7854 = 28.2744ft 2

28.2744ft 2 × 20ft = 565.488ft 3
4. bbl
565.488ft 3 × 0.1781
ft 3
= 100.713 bbl
100.71341 bbl bbl
= 5.0357
20ft ft
5.
ft bbl
1 × 5.0357 = 5.0357 BPM
min ft
bbl
Tubing = 8000ft × .00579
ft
= 46.322 bbl
bbl
6. a. Casing = (8213 − 8000)ft × .0238
ft
= 5.0694 bbl
5.0694 bbl + 46.322 bbl
= 51.389 bbl

51.389 bbl
b. T = = 2.8550 min
p 18BPM
bbl
c. V = 8000ft × 0.0158 = 126.4 bbl
ft
lb gal
Ph = 8213ft × 9 × 0.05195 2
d. gal in ft
= 3839.99psi
18bbl 42gal 4gal
Rate 1 = × ×
min bbl 1000gal
gal
= 3.024 ClaySta − XP
min
or
gal
18 × .0 42 × 4 = 3.024
min
e.
bbl gal 1gal
Rate 2 = 18 × 42 ×
min bbl 1000gal
gal
= 0.756 ScaleChek
min
or
gal
18 × .042 × 1 = 0.756
min

© 2005, Halliburton 2 • 28 Stimulation I

 Calculations

Items from Unit C Quiz

1. viscosity/shear (flow)
2. Hydrostatic Pressure
3. Laminar/Turbulent
4. rate/pipe diameter/pipe roughness/pipe length/viscosity/density
5. 300
6. friction
Items from Unit D Quiz
psi
Ph = 0.4831 × 8000ft
1. ft
= 3864.8 psi

BHTP = 1200psi + 3864.8psi

= 5064.8psi
psi
Ph = 0.5039 × 9050ft
ft
= 4560.295psi
BHTP = 1975psi + 4560.295psi
2. = 6535.295psi
6535.295psi
Frac Grad. =
9050ft
psi
= 0.722
ft
2% KCl : 8.42 lb : abs. vol. 1
Sand : 5.5 lb : abs. vol. factor 0.0452 : abs. vol. 0.2486
TOTALS: Weight = 13.92 lb
Volume = 1.2486 gal
13.92 lb lb
Density = = 11.1485
1.2486 gal gal
psi
BHTP = 7450 ft × 0.65
ft
= 4842.5 psi
psi
3. Ph Grad = 0.5766 (RedBook)
ft
psi
Ph = 7450 ft × 0.5766
ft
= 4295.67 psi
PISIP = 4842.5 psi − 4295.67 psi
= 546.83 psi

© 2005, Halliburton 2 • 29 Stimulation I

 Calculations

bbl
Tubing = 9000ft × 0.00579
ft
= 52.11 bbl
bbl
4. a. Casing = 50ft × 0.0393
ft
= 1.965 bbl
Volume = 52.11bbl + 1.965bbl
= 54.075 bbl

bbl
Vann = 9000ft × 0.0313
b. ft
= 281.7 bbl

psi
38.3
Pfrict = 100ft × 9000ft
c. ft
100
100ft
= 3447 psi

Pw = PISIP + Pfrict + Pperf

P lb = 2000 psi
ISIP −10
gal
psi
P lb = 0.5195 × 9050 ft
h −10 ft
gal
= 4701.475 psi
psi
P lb = 0.4623 × 9050 ft
h −8.9 ft
d. gal
= 4183.815 psi
∆Ph = 4701.475 − 4183.815
= 517.66 psi
P lb = 2000 psi + 517.66 psi
ISIP −8.9
gal
= 2517.66 psi
Pw = 2517.66 psi + 2447 psi
= 5964.66 psi

Pw × Q
HHP =
40.8
5964.66psi × 20BPM
e. =
40.8
= 2923.853 HH P

© 2005, Halliburton 2 • 30 Stimulation I

 Calculations

⎛ lb gal ⎞
Vol factor = 1 + ⎜⎜ 5 × 0.0444 ⎟
⎝ gal lb ⎟⎠
= 1 + 0.222
f.
= 1.222
8.93 lb + 5 lb lb
Density = = 11.399
1.222gal gal
Ph = 9050ft × 0.5922(RedBook )
= 5359.41 psi

gal
54.075bbl × 42
Clean Vol = bbl
1.222
= 1858.55 gal
lb
g. Wsand = 1858.55gal × 5
gal
= 9292.76 lb
9292.76lb
Vsand = = 96.8 sks
lb
96
sk

© 2005, Halliburton 2 • 31 Stimulation I

 Calculations

Self-Check Test Answer Key

1. laminar flow
2. barrels per minute
psi
Ph = 0.4364 (RedBook) × 8000ft = 3491.2 psi
3. ft
BHTP = 2575psi + 3491.2psi = 6066.2 psi

psi
4. BHTP = 11000ft × 0.82 = 9020 psi
ft

5. Material Material (lb) Abs. Vol. Factor (gal/lb) Abs. Vol. (gal)
2% KC1 8.42 1
Proppant 3 0.0444__ 0.1332
TOTALS 11.4 1.1332
11.42lb lb
SlurryDensity = = 10.0777
1.1332gal gal
psi
BHTP = 9060 ft × 0.72 = 6523.2 psi
ft
psi
Ph = 9060 ft × 0.5247 (RedBook) = 4753.78 psi
ft
PISIP = 6523.2 psi − 4753.78 psi = 1769.42 psi

psi
7.68
6. Pfrict = 100ft × 6300ft = 483.84 psi
100ft

bbl
6000psi × 12
7. HHP = min = 1764.706 HHP
40.8

bbl
Vtubing = 10,500ft × 0.00387 = 40.6350 bbl
ft
bbl
8 a. Vcasing = 375ft × 0.0155 = 5.8125 bbl
ft
Vtotal = 40.6350bbl + 5.8125bbl = 46.4475 bbl

© 2005, Halliburton 2 • 32 Stimulation I

 Calculations

bbl
b. Vann = 10,500ft × 0.0101 = 106.05 bbl
ft
V(ft 3 ) = 20ft × 10ft × 8ft = 1600ft 3
c. bbl
V(bbl) = 1600ft 3 × 0.1781 = 284.96 bbl
ft
⎛ bbl ⎞
PumpRate⎜ ⎟
⎛ in ⎞ ⎝ min ⎠
Rate⎜ ⎟=
⎝ min ⎠ TankFactor⎛ bbl ⎞
⎜ ⎟
⎝ in ⎠
284.96bbl bbl
d. Tank Factor = = 2.96833
96in in
bbl
10
⎛ in ⎞ min in
Rate⎜ ⎟= = 3.369
⎝ min ⎠ 2.96833 bbl min
min
psi
e. Pfrict = 41.96 × 10,500ft = 4405.8 psi
100ft
f. Pw = 2900 psi + 4405.8 psi + 200 psi = 7505.8 psi
bbl
7505.8psi × 10
g. HHP = min = 1839.657 HHP
40.8

⎛ lb gal ⎞
Volume Factor = 1 + ⎜⎜ 8 × 0.0383 ⎟ = 1.3064
⎝ gal lb ⎟⎠
gal
46.4475bbl × 42
CleanVolume = bbl = 1493.260 gal
h. 1.3064
lb
WInterProp = 1493.260gal × 8 = 11,946.08 lb
gal
11,946.08lb
VInterProp = = 99.551 sacks
lb
120
sk

© 2005, Halliburton 2 • 33 Stimulation I

 Calculations

lb lb
+8
8.42
gal gal lb
Slurry Density = = 12.569
i. 1.3064 gal
lb
Ph = 10875ft × 12.569 × 0.05195 = 7100.935 psi
gal

ft 3
Vcasing = 375ft × 0.0872 (RedBook) = 32.7ft 3
ft
VProp in tubing = 99.551ft 3 − 32.7ft 3 = 66.851ft 3
j.
ft
Fill = 66.851ft 3 × 46.067 (RedBook) = 3079.625ft
ft 3
Top of Proppant = 10,500ft - 3079.625ft = 7420.375 ft
46.4475 bbl
k Pipe Time = = 4.64475 min
bbl
10
min
bbl 2gal 0.042 gal
l. LA - Rate = 10 × × = 0.84
min Mgal bbl min

© 2005, Halliburton 2 • 34 Stimulation I

Section 3

Blenders and Auxiliary

Equipment

Table of Contents
Introduction................................................................................................................................................3-3
Topic Areas ............................................................................................................................................3-3
Learning Objectives ...............................................................................................................................3-3
Unit A: Hoses.............................................................................................................................................3-4
Suction Hose Selection...........................................................................................................................3-4
Discharge Hoses .....................................................................................................................................3-5
Hose Storage and Use ............................................................................................................................3-6
Hose Inspection ......................................................................................................................................3-6
Basic Do’s and Don’ts............................................................................................................................3-7
Unit A Quiz ............................................................................................................................................3-8
Unit B: Centrifugal Pumps.........................................................................................................................3-9
Principles of Operation...........................................................................................................................3-9
Definitions of Terms ............................................................................................................................3-10
Performance Characteristics.................................................................................................................3-10
Water Hammer .....................................................................................................................................3-11
Parallel and Series Operation ...............................................................................................................3-11
Unit B Quiz ..........................................................................................................................................3-12
Unit C: Tub Agitators ..............................................................................................................................3-13
Unit D: Additive Systems ........................................................................................................................3-14
Liquid Additive System .......................................................................................................................3-14
Liquid Additive Equipment..................................................................................................................3-14
Dry Additive Equipment ......................................................................................................................3-16
Unit D Quiz ..........................................................................................................................................3-16
Unit E: Sand Screws ................................................................................................................................3-17
Sand Screws .........................................................................................................................................3-17
Unit E Quiz...........................................................................................................................................3-18
Unit F: Hydraulic Systems.......................................................................................................................3-19
Unit F Quiz...........................................................................................................................................3-21
Unit G: Instrumentation ...........................................................................................................................3-22
Flow Meters..........................................................................................................................................3-22
Pressure Transducers............................................................................................................................3-23
Radioactive Densometers .....................................................................................................................3-23
pH Probe...............................................................................................................................................3-23
The Graphical User Interface (GUI) ....................................................................................................3-24

© 2005, Halliburton 3•1 Stimulation I

 Blenders and Auxiliary Equipment

Electronic Failures from welding EMI.................................................................................................3-25

Unit G Quiz ..........................................................................................................................................3-26
Self Check Test for Section 3: Blenders & Auxiliary Equipment ...........................................................3-27
Answers Keys ..........................................................................................................................................3-29

© 2005, Halliburton 3•2 Stimulation I

 Blenders and Auxiliary Equipment

Introduction
Specialized equipment is necessary to properly • Hydraulic Systems
add chemicals and sand into fracturing fluids.
Proportioners (blenders) have been developed • Instrumentation
that have the needed equipment mounted on a
single truck or trailer (Figure 3.1). The overall
operation of the blender with its different
Learning Objectives
systems is an extremely important phase of
stimulation work. Upon completion of this section, you will be
familiar with
• Use and care of hoses
Topic Areas
• Pumping systems used on blenders
The section units are • Use and care of additive systems
• Hoses • Hydraulic systems introduction and safety
• Centrifugal Pumps • Basic instrumentation used for job control
• Tub Agitator • Sand screw delivery rates and calculations
• Additive Systems • Systems of the blender and how they relate
• Sand Screws to the overall job functionality

Figure 3.1

© 2005, Halliburton 3•3 Stimulation I

 Blenders and Auxiliary Equipment

Unit A: Hoses
Flexible rubber hoses are key components in The first question asks if the hose is spiral
successful fracturing and stimulation jobs. The reinforced with wire. Reinforcement will
critical nature of hose applications requires prevent the hose from collapsing under suction.
careful selection, care and maintenance. Proper What may not be so easily recognized is that the
handling of these hoses will contribute to the wire also serves as a conductor that grounds the
successful completion of a stimulation job. equipment.
The second question asks about flow rate. In
Suction Hose Selection Section 2: Calculations, you learned the effect
of flow rate on friction pressure (Pf) in steel
tubular goods. Friction pressure also exists in
Frac hoses used for suction applications connect suction hoses. There is a limit to the amount of
reservoirs of stimulation fluids (frac tanks) to the fluid that can be transferred through one hose.
blender (Figure 3.2). Therefore, more hoses are required when the
flow rate increases. The viscosity, which is a
measure of a fluid’s resistance to flow, will also
affect the number of hoses required for a job.
Table 3.1 was developed to provide an easy
guide for selecting the number of suction hoses
to use on a given job based on the flow rate and
viscosity of the fluid. Use it to gain experience
in hose selection. However, before the chart can
be properly used, some terms need to be defined:
• Water: Fresh water or salt water to which
nothing has been added that could cause the
water to develop viscosity. The water could
also contain friction reducers.
Figure 3.2 – Suction Hose • Thin oil: Thin oil is normally considered to
be diesel or kerosene. While the higher API
gravity oils and condensates are also very
As you consider “rigging up” equipment for the thin, they should be included with high
stimulation jobs, ask yourself these questions to vapor pressure fluids.
help select the best hose arrangement for a
particular application: • Low, moderate, and high viscosity fluids:
Low viscosity fluid is water with less than
1. Is the hose spiral reinforced with wire to 30 pounds gel per 1000 gallons of gel added
prevent the hose from collapsing under to it. A moderate gel would be 40 pounds
suction? gel per 1000 gallons of gel added. A high
2. What is the flow rate? Remember: higher viscosity fluid would be 60 to 80 pounds
flow rates and friction restriction require that per 1000 gallons of gel added.
more hoses be used. • High vapor pressure: The higher the API
3. What kind of treating fluid will be used? The gravity of an oil, the greater the amount of
viscosity of the fluid also affects the number vapor given off by the oil. Gasoline is a
of hoses selected for the stimulation fluid.

© 2005, Halliburton 3•4 Stimulation I

 Blenders and Auxiliary Equipment

good example of a fluid with a high vapor Example 1:

pressure.
The gel being Pumped is 70 lb/Mgal WG-18 at
API gravity is the American Petroleum 60 bpm. Each suction hose is 20 ft. in length.
Institute’s relative comparison of the specific
60 BPM
gravity of oils. Water has an API gravity of 10. # Hoses = = 6 hoses
Most oils have a higher API gravity than water. 10 BPM per hose
The higher the gravity, the lighter the oil. 6 hoses × 1.5 (for thick fluid) = 9 hoses
The value for API gravity is measured with a
hydrometer. The temperature of the sample is
also taken because temperature will affect the
Discharge Hoses
gravity of the oil. API gravity is reported as
degrees API at 60°F. A correction needs to be Discharge hoses are used to transfer combined
made if the sample temperature is not 60°F. For liquids and additives from the blender to the
each degree F above 60°, add 0.1° API to the high-pressure pumps. Since these hoses are
reading. For each degree below 60°, subtract usually supercharged when transferring the
0.1° API from the reading. treating fluid from the blender, they will have a
higher pressure rating than the suction hoses.
If the specific gravity is known, the API gravity Discharge hoses are normally about ten feet
can be calculated from the following formula: long. Like suction hoses, discharge hoses are
141.5 also spiral reinforced with wire.
API gravity = – 131.5
SpecGrav@60°F
API gravity is an area that needs consideration
in pumping oils. For example, very little
difficulty would be experienced in pumping oil
with an API gravity of 48°. However, it is very
difficult to pump oil with an API gravity of 19°.

Minimum Number of Suction Hoses

Recommended for High Viscosity Fluids or
Fluids with High Vapor Pressures (20-ft lengths)
Volume (bbl/min) No. of Lines Size (in. ID)
5 2 4
10 3 4 Figure 3.3
30 5 4
40 6 4
Since the discharge hoses are under pressure
50 8 4
when transferring liquids and additives, they
Table 3.1 should be covered with hose covers to deflect
fluid in case of leaks. This is especially true
when pumping flammable fluids. Failure to
Rule of Thumb: To determine the minimum cover the hose may cause a flammable liquid to
number of 4 inch suction hoses required for be sprayed into the intake manifold on an engine
water and moderate gels, calculate a 10 bbl/min and cause an equipment fire.
capacity for each 20 feet of length. When
If using three inch discharge hoses, remember
pumping thick or gaseous fluids, add 50% more
that a 4 inch hose has 12.6 square inches of area
hoses to the result of your calculations.
to flow through while a 3 inch hose has only
7.07 square inches of area. So, it will take two, 3

© 2005, Halliburton 3•5 Stimulation I

 Blenders and Auxiliary Equipment

inch discharge hoses to equal the flow carrying

capacity of one 4 inch hose.
Warning: Do not stand on or straddle any line
or hose under pressure!

Hose Storage and Use

To increase hose life, follow these common-

sense procedures while using and storing hoses:
• Never drag the hose or pull it by the
coupling when moving a hose from the
blender to the tanks.
• Do not drive vehicles over hoses or use Figure 3.4
hoses for wheel chocks.
• Do not drop hoses so the couplings receive
undue shock.
• Because of the hose weight and the
tremendous vibration associated with well
stimulation operations, be extremely careful
when connecting hoses with crossovers. Pay
particular attention to any sharp edge that
might cut the hose, such as a well-beaten
hammer union lug.
• Be sure to allow enough free length in the
hose to avoid a problem. Hoses could
contract up two to three percent in length
when pressurized during frac jobs. A hose
that is too short for the application will be
damaged at the coupling (Figure 3.3) and Figure 3.5
can lead to early hose failure.
• When the job is completed, flush and drain
the frac hoses prior to placing them back on
the blender. If it is not possible to flush the Hose Inspection
hoses then, flush them at the first
opportunity. The hoses should be placed on The key to efficient maintenance is constant
the blender in a straight flat position. awareness of the hose condition. Frac crew
members should inspect a hose for the following
signs of wear and tear each time the hose is
loaded or unloaded:
• Couplings - Check for cracks, signs of
slippage, kinks, and hose condition at the
coupling. The abrasive action of sand laden
fluids will wear the hose faster if it is
kinked.

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 Blenders and Auxiliary Equipment

• Hose cover - Be on the lookout for cuts, Basic Do’s and Don’ts
exposure of the reinforcement, a kink (flat
spot) or blister. Frac hoses used in the well servicing business
• Hose tube - Shine a flashlight into one end are very rugged and dependable, but they can
of the frac hose and look into the other end fail if excessively abused. Following are some
for obstructions, cracks, tube pulling away helpful tips developed over the years that can
and blisters. help increase hose life:
An investment in hose inspection time and • DO use the proper hose for each particular
procedures can pay dividends in hose service life well servicing application – i.e., suction
and create safer working conditions. No one hose for suction application and the proper
wants a hose that is transporting frac fluid to hose for the materials being pumped.
burst under high pressure.
• DON’T stretch a hose to reach a connection.
Be aware of the safety hazard of flying pieces of The stress added to the internal pressure
metal when making up hoses. Wing ends that could lead to shortened hose life.
have become too worn (pointed) should be
• DO inspect hose as often as practical. Look
replaced. (Figure 3.6) Always wear safety
for signs of leakage, blistering or loose
glasses with side shields when making up hoses
covers. Cuts, gouges and abrasions can lead
or iron or if you are in the vicinity.
to weakened hose reinforcement.
• DON’T drag the hose over especially
abrasive or sharp surfaces. Never pull it by
the coupling assembly.
• DO match hose pressure ratings with job
specifications.
• DON’T recouple a failed hose.
• DO protect threaded ends of a coupling to
enhance a leak-proof seal.
The last thing needed at a frac job is a premature
failure because the wrong hose was used on the
job or the hose was not properly maintained. It is
good business to follow a few simple common-
Figure 3.6 Worn Wing End sense practices in the selection, care and
maintenance of a frac hose to help perform a
safe, efficient and profitable operation.

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 Blenders and Auxiliary Equipment

Unit A Quiz

Fill in the blanks with one or more works to check your progress in Unit A.
1. The proper handling of suction hoses helps in the successful completion of a stimulation job. Each
time a hose is loaded or unloaded, these three areas should be inspected for wear and tear:
1. _______________________________
2. _______________________________
3. _______________________________

2. To prevent the hose from collapsing under suction, the hose is __________ __________ with
___________.

3. The number of suction hoses selected for use on a stimulation job is determined by the
_______________________ and the ____________________ of the treating fluid used.

4. The higher the API gravity of an oil, the greater the amount of _________________ given off by the
oil, and the ___________________ the oil.

5. A fracturing job requires a 40 bbl/min injection rate. The base gel is 60 lb/1000 gal WG-11. Each
suction line will be 20 ft in length. Using Table 3.1, how many 20-ft suction hoses will be required
for the job?

6. When transferring high-vapor pressure fluids from the blender to the high pressure pumps, the
discharge hoses should be ________________ to deflect __________________ in case of leaks.

7. Discharge hoses could contract when pressurized during frac jobs. Allow enough ______________ in
the hose to avoid a problem.

8. After a job, __________________ and _________________ frac hoses before storing them back on
the blender.

9. Frac hose should be stored in a _______________, flat position.

10. Obstructions, cracks, tube pulling away, and blisters can be located on the inside of a frac hose by
shining a _____________________ into one end of the frac hose and ____________________ into
the other end.

Now, look up the suggested answers in the Answer Key.

© 2005, Halliburton 3•8 Stimulation I

 Blenders and Auxiliary Equipment

Unit B: Centrifugal Pumps

Centrifugal pumps are used on blenders to draw
fluids out of storage tanks and convey sand
laden fluids to high pressure pumps.
Understanding centrifugal pump operation and
performance is vital if blenders are to be
operated correctly.

Figure 3.8 – Right-hand centrifugal pump.

The head or pressure developed by the

centrifugal pump is entirely the result of the
Figure 3.7 - Gorman Rupp fluid rate caused by the impeller rotation. This
pressure is not created by any type of positive
displacement methods (plungers).
Centrifugal pumps are used because they are
more tolerant of abrasive fluids than gear or
vane pumps. This tolerance causes less wear on
the pumps, therefore increasing pump life.
However, they are much less tolerant of air.
In this unit, you will learn about how centrifugal
pumps operate.

Principles of Operation

A centrifugal pump consists essentially of one or

more impellers equipped with vanes. The
impeller is mounted on a rotating shaft and
enclosed by a casing. Fluid enters the pump at
the center of the impeller. The fluid is then Figure 3.9
directed radially toward the case by the vanes
(Figure 3.8). As the fluid leaves the impeller, it
is collected in a volute or series of diffusing
passages. This causes the fluid rate to drop and
the pressure to increase.

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 Blenders and Auxiliary Equipment

Definitions of Terms Although all factors of Available NPSH can be

controlled to some extent, the friction loss can
be altered more easily than the others. This is
Before centrifugal pump principles and
usually done by varying the number and/or
operations can be fully understood, there are
length of the suction lines. The maximum
certain terms that must be defined. Centrifugal
volume that should be pulled through one 20 ft,
pumps are classified according to suction and
4 in. suction hose is 420 gal/min (10 bbl/min).
discharge manifold diameters, impeller
This is only a rule of thumb, and there will be
diameters, number of vanes, direction of
times when the volume per hose must be lower.
discharge, and many other characteristics.
The higher the flow rate, the higher the friction
An important distinguishing feature is whether
loss, which can result in air or vapor separation.
the pump is a right-hand or left-hand pump. To
This is further complicated when elbows or tees
determine this, use Figure 3.8 as a reference. As
are used close to the pump or the hose length is
you look into the impeller from the suction side
increased beyond 20 ft. Uneven flow patterns,
of the pump, note on which side of the case the
vapor separation, or both, can keep the liquid
discharge manifold starts. In Figure 3.8 the
from evenly filling the impeller. This upsets the
discharge starts on the right. Therefore, it is
hydraulic balance and can lead to cavitation,
called a right-hand pump. A left-hand pump has
vibration and excessive shaft deflection. Shaft
the discharge starting on the left.
breakage or premature bearing failure may
Here are some other key terms: result.
• Head is generally used with centrifugal Suction lines should be as short and as straight
pumps rather than pressure. It refers to the as possible. They also should not have
height (in feet of water) that a pump can intermediate in-line high places to create air
discharge. This is important because the pockets. O-rings should be in good condition
heavier the fluid (ie. Sand concentration) the and should be in place to prevent air intake at
lower the head the pump will have or the the connections.
less boost pressure the pump will have.
• Horsepower is the power required by the Performance Characteristics
pump, not the hydraulic horsepower
delivered. Unless otherwise noted on the
curves, these values are based on a specific The centrifugal pump will adjust its rate
gravity of 1.0. If the fluid being pumped has depending on the input and output pressures. If
a different density than water, multiply the an adequate head of fluid (input pressure) is
horsepower by its specific gravity. available, the pump rate will adjust to match the
output pressure. If an adequate head of fluid is
• Net Positive Suction Head (NPSH) is not present, then vapor pockets can form in the
divided into two categories. Required NPSH center of the impeller and cause cavitations. This
is the amount of pressure that must be can also cause serious structural damage to the
supplied to the suction of the pump for the pump. Cavitations can be eliminated by down-
pump to operate properly. It is shown on throttling (partially closing) a valve in the
performance curves. The Available NPSH discharge line to reduce the output rate to a point
varies with suction conditions and must be where the input head is adequate.
equal to or greater than the Required NPSH.
Faster speeds produce more pressure or head and
Both are measured in feet of liquid.
demand more horsepower. Slower speeds have
Halliburton field personnel will not be expected the opposite effect.
to calculate Available NPSH, but it is important
to understand this characteristic of centrifugal
pumps to avoid possible problems when laying
temporary suction manifolds.

© 2005, Halliburton 3 • 10 Stimulation I

 Blenders and Auxiliary Equipment

Water Hammer In parallel operation:

• The discharge head is equal to that of one
Some centrifugal pump cases have been split by pump.
water hammer. Water hammer occurs when a
valve in the discharge line of the pump is closed • The volume is equal to the total of the two
too quickly. This brings the fluid to a sudden pumps.
stop and exerts very high pressure throughout • Use care with the suction manifold so that
the system upstream from the valve. Normally, one pump does not starve.
the pump case is the weakest part of the system
and is the part that fails. • Be sure the discharge capabilities of the
pumps are fairly equal.
A typical water hammer break is characterized
by a crack running around the centerline of the • Do not operate the pumps at relatively high
case. This may not happen the first time a water heads and low capacities to avoid the
hammer occurs, but it definitely weakens the possibility of one pump moving fluid back
case and increases the probability of future through the second pump.
failure.
A surge chamber can be installed in the
Series
discharge line to reduce the hammer, but won’t
eliminate it. If possible, pump speeds should be The result of a series operation is the opposite of
reduced and valves closed gradually. parallel systems (Figure 3.11):

Parallel and Series Operation

Sometimes it is necessary to operate two or

more pumps at the same time. Depending on the
arrangement of the pumps, the operation will be
either parallel or series.

Parallel
Figure 3.11 – An example of series pump
system.
Parallel centrifugal pump operation is illustrated
in Figure 3.10. An example of a parallel
operation would be connecting two centrifugals
An example of a series operation would be in
to separate frac tanks and discharging them both
using a booster pump trailer to feed the suction
into a third tank.
side centrifugal of the blender.
In series operation:
• The volume is limited to the capacity of one
pump.
• The head is equal to the sum of the two
pumps (the second pump will add its head to
the head supplied to its suction by the first
pump).
• You must know the maximum case working
Figure 3.10 - An example of a parallel pressure of the pump to avoid bursting the
operation. second pump.

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 Blenders and Auxiliary Equipment

• You must take care to not part the lines with Solution:
dresser sleeve connections. Parallel Operation:
• At high rates, leakage may occur at the Volume = 500 + 500 = 1,000 gal/min
stuffing box seals or packing of the second
pump. Head = 120 ft
Example: Series Operation:
Two pumps, each having the capacity of 500 Volume = 500 gal/min
gal/min @ 120 ft of head, are to be operated Head = 120 + 120 = 240 ft
together. What is the output for parallel and
series operations? Although the theoretical head for series
operation is 240 feet, the actual head will be
lower. This is due to the friction loss in the
manifold between pumps and will vary with
volumes and manifold arrangement.

Unit B Quiz

Fill in the blanks to check your progress in Unit B.

1. Centrifugal pumps on blenders draw fluid out of _______________ _______________ and convey
sand-laden fluids to ___________ ___________ ___________.

2. Centrifugal pumps have been selected for use on blenders because centrifugal pumps are more
tolerant of ____________________ ______________________.

3. The disadvantage of the centrifugal pump is that it is less tolerant of _______________.

4. Instead of pressure, the term _______________ is generally used with centrifugal pumps.

5. If an adequate head is not present, vapor pockets can form and cause _______________, which can
be eliminated by partially closing a valve in the discharge line.

6. Water hammer occurs when a _______________ in the discharge line is closed too quickly.

7. In a parallel operation of two pumps, the head is equal to that of _______________ pump(s), and the
volume is equal to that of _______________ pump(s).

8. Fluid enters a centrifugal at the _______________ of the impeller.

9. As the fluid leaves the impeller, it is collected in a volute or series of diffusing passages. This causes
the fluid rate to ________ and the pressure to __________.

Now, look up the suggested answers in the Answer Key.

© 2005, Halliburton 3 • 12 Stimulation I

 Blenders and Auxiliary Equipment

Unit C: Tub Agitators

The tub agitator consists of two sets of blades on to pick up air, which will cause a decrease in
a shaft. The bottom blades are set just off bottom boost pressure.
of the mixing tub (Figure 3.12). The purpose of The agitator’s speed (revolutions per minute-
the agitator is to help keep the proppant rpm) is computer controlled. In the computer,
suspended in the fluid without entraining air. If the agitator is given a set speed without
the agitator speed is too low, the proppant can proppant. When proppant is added to the fluid in
build up on the bottom of the tub and suddenly the tub, computer will increase the agitator’s
get picked up as a slug and sent to the pumps. If rpm as the proppant concentration is increased.
the agitator speed is set too high it can whip or A default setting is 40 rpm without proppant and
entrain air in the fluid causing the booster pump adding 4 rpm per pound of proppant added.

Figure 3.12 - Blender Tub (High Rate Blender) - Sectional view

© 2005, Halliburton 3 • 13 Stimulation I

 Blenders and Auxiliary Equipment

Unit D: Additive Systems

Due to the nature of stimulation fluids, some
additives can only be added “on-the-fly” (while Liquid Additive Equipment
pumping). These additives are in liquid or solid
form. Various pumps and hoppers mounted on
the blender allow accurate measuring and
addition of these additives. Equipment for both
liquid and dry additives will be discussed in this
unit.

Liquid Additive System

Halliburton has many fracturing fluids that

require a large number of chemical additives for
proper performance. Many of these additives are Figure 3.13 Roper Progressive Cavity Pump
liquid. Some of the liquid chemical additives are
crosslinkers, surfactants, breakers and oil gelling
agents. The liquid additive systems on blenders With the advent of today’s fluid systems, the
are designed to blend the liquid chemicals into liquid additive equipment has to be capable of a
the fracturing fluids. high level of precision. The blenders come
equipped with from 3 to 7 liquid additive
Injection points on the blender will be dependent
systems. These additive systems consist of a
on the liquid additive type. Some chemicals are
pump, typically a Roper Progressive Cavity
split into two pumps. This split is not because of
(Figure 3.13) and a Micro-Motion Flow Meter.
the amount of chemical added, but due to the
fact that the viscosity of the fracturing fluid may
get so high that it will not leave the tub or the
proppant may just stack on top of the slurry. So,
some will be injected into the tub slurry and the
rest of the chemical will be injected into the
slurry at a point after it leaves the tub. Injection
points are in the suction side, in the tub, in the
eye of the discharge booster pump or in the
discharge manifold. There is one chemical (sand
wedge) that is commonly injected into the sand
screw at various distances in the sand screw
housing. The exact placement is area specific.

Figure 3.14

Progressive pumps are used mainly because they

are more tolerant of trash and the most
accurately controlled. These pumps have to be

© 2005, Halliburton 3 • 14 Stimulation I

 Blenders and Auxiliary Equipment

sized for the amount of fluid you wish to pump.

The minimum rate they will pump is typically
one tenth of the maximum volume they will
pump. The most common problem with these
pumps is that when they are run dry, it destroys
the stator (pump liner). The pumps can be
purchased with different stators, Buana N, Viton
and Butyl Rubber. The type of Stator to be used
will depend on the chemical to be pumped. The
accuracy and the life of this pump is dependent
on the operator using the appropriate stator
material and taking care not to run the pump dry.
The Roper pump has a very poor suction
capability. The chemical tanks should always be
above the suction of the pump. Slurry hoses to
the suction side of the pump should be large
enough to free flow the amount of chemicals
you intend to pump.
Figure 3.15
Stainless steel liquid additive tanks are mounted
on the blender (Figure 3.15). All of the stainless
steel tanks have a bottom suction connection. MicroMotion flow meters are installed on the
They also have sight tubes for visually checking liquid additive pumps because of their accuracy
levels along with electronic fluid level sensors. (Figure 3.16). MicroMotions provide feedback
They have the capability to be tied to another to the computer on the blender that allows it to
holding tank that will be able to keep the tank on accurately control the addition of chemicals to
the blender filled when it gets to a certain level.
the treatment slurry.
Care must be taken to only put chemicals inside
that are compatible with stainless steel. Vicon
HT breaker is one chemical that is not
compatible with stainless steel.

Figure 3.16 – MicroMotion Flow Meters

Typically, they are accurate to within 1% of the

volume actually pumped. A problem that may be
encountered with the MicroMotion meter is that
air in the fluid causes an erroneous flow rate.
Thick or viscous fluid is not recommended. The
MicroMotion flow meters must also be sized for
the rate of the fluid that is to be pumped through
them.

© 2005, Halliburton 3 • 15 Stimulation I

 Blenders and Auxiliary Equipment

Dry Additive Equipment dispersed for each revolution of the Acrison

Screw for each dry additive to be used.
In addition to the liquid additives required to At the end of the job, the hopper and screw
make up the different fracturing fluids, there are should be cleaned of material. Material left
also many dry additives that must be used. A dry inside can harden and prevent them from
additive system improves the blending of dry turning.
additives into a fracturing fluid. The mechanical
equipment on the dry additive system usually
includes two Acrison-Feeders. Tube diameter
size depends on the area that the blender is used
in. The sizes can run from 1-3/8 inches to 4-1/2
inches. Blenders typically come equipped with
two Acrisons, a 4 inch and a 1 3/8 inch.
Dry additives are sack-fed into the hopper and
dispensed by a screw feeder through eductors or
by gravity into the blender mixing tub. The
eductor should be used with caution on high
pump rate jobs as air entrainment into the slurry
can cause the boost pressure to decrease. Proper
calibration of the dry additive screws is
imperative for correct additive dispersal. This Figure 3.17
requires the operator to have a set point value for
the amount of pounds of dry additive that will be

Unit D Quiz

Fill in the blanks with one or more words to check your progress in Unit D.
1. The minimum rate a Roper pump will pump is typically _____________ of the maximum rate.

2. A Roper Progressive cavity pump should never be pumped without _______________ in it as this
will _______________ the stator.

3. Micro motion flow meters are accurate to within ________ of the volume pumped.

4. Dry additives are __________-__________ into the hopper and dispersed by the __________
__________ through an eductor into the blender tub.

5. Dry additives remaining in the feeder after a job will __________ and prevent the feeder from
____________.

6. The hoses to the Roper pump should ____________ ____________ enough fluid to supply the pump
during the job.

Now, look up the suggested answers in the Answer Key.

© 2005, Halliburton 3 • 16 Stimulation I

 Blenders and Auxiliary Equipment

Unit E: Sand Screws

Fracturing jobs normally require the addition of
propping agents into the fluid. Sand screws Sand Screws
convey those propping agents from bulk
equipment to the blender tub. The propping
agent may be sand, lightweight ceramics, Most of the blender sand screws on newly
intermediate or high strength bauxite, or a resin manufactured blenders are 12 inch and 14 inch
coated version of any one of these types. See diameter screws, with 11 inch and 13 inch screw
Section 9 for more details on proppants. flights. These sand screws may have been
modified to be able to run a chemical additive
Each sand screw on the blender is operated called SandWedge NT.
independently through computer controlled
hydraulic throttling.

Sand Screw # 1
Sand Screw # 2 (12 inch)
(14 inch)

Sandwedge® piping

Safety Grating

Sand Screw
Latch

Hopper

Figure 3.18 – High Rate Blender tub and sand screws

© 2005, Halliburton 3 • 17 Stimulation I

The maximum output for a 12 inch screw is We are going to pump 20/40 Econoprop. Its
about 100 sacks per minute and, for a 14 inch absolute volume factor is 0.0444. The screw
screw, 130 sacks per minute at a maximum calibration set point is 30 lb/rev for Ottawa sand
speed of 350 – 360 rpm. Proppant delivery for in a 12 inch screw. What is the New Cal Factor?
Ottawa sand is about 30 – 31 pounds per gal
revolution (lbs/rev) for the 12 inch sand screw 0.0452
lb × 30 lb = 30.541 lb
and 48 – 49 pounds per revolution (lbs/rev) for
gal rev rev
the 14 inch sand screw. 0.0444
lb
Different types of proppants have different lbs
per revolution calibration settings for each
Absolute Volume Factors
screw. The reason for this can be seen in the
different bulk density and absolute volume Bulk Specific Absolute
PROPPANT TYPE Density Gravity Volume
values for each proppant in Table 3.2. Each (lb/ft3) (g/cc) (gal/lb)
proppant type will have a different volume of 20/40 Ottawa 95.9 2.65 0.0452
space it will occupy for a given weight. Proper 20/40 AcFRAC BLACK 102 2.55 0.0470
calibration of the sand screw is imperative for
20/40 SUPER HS 95.5 2.55 0.0470
correct proppant dispersal. This requires the
operator to have a calibration value for the 20/40 ECONO-PROP 96 2.70 0.0444

number of pounds the screw will discharge each 20/40 CARBO-LITE 97 2.71 0.0442
revolution. Usually a good reference is the 20/40 CARBO-PROP 117 3.27 0.0366
absolute volume of Ottawa sand (0.0452) 20/40 INTER-PROP 120 3.13 0.0383
divided by the absolute volume of the new 12/18 CARBO HSP 2000 128 3.56 0.3366
proppant times the lbs/rev cal factor for sand
equals the new lbs/rev cal factor for the Table 3.2
proppant.
Absolute vol of sand
× lb/rev of sand
Absolute vol of proppant
= New cal factor
Example:

Unit E Quiz

Fill in the blanks with one or more words to check your progress in Unit D.
1. Each sand screw on the blender is operated ________________ of the other(s).

2. Currently, most blenders being manufactured have _____ and _____ inch sand screws.

3. Different types of __________ have different __________ ______ ________________for

calibration.

4. A 12 inch sand screw has a maximum delivery of about __________ sacks per minute.

Now, look up the suggested answers in the Answer Key.

© 2005, Halliburton 3 • 18 Stimulation I

 Blenders and Auxiliary Equipment

Unit F: Hydraulic Systems

The hydraulic system powers the sand screws,
centrifugal pumps, liquid additive pumps, tub
agitator, and the lift mechanism for the sand
screws on all Halliburton blenders.
The components making up the hydraulic
system are the
• Prime movers (engines)
A prime mover, or engine, supplies
mechanical energy to drive hydraulic Figure 3.20 – Hydraulic oil cooler
pumps. The prime mover may not be the
same on all benders. Late model blenders
are equipped with either Detroit or • Tanks (reservoirs)
Caterpillar engines. The tank, or reservoir, is the first storehouse
for the fluid until it is required by the
system. The tank provides a place for air to
separate from the fluid and permits
contaminants to settle. It also helps dissipate
heat that is generated by the system.

Figure 3.19 – Caterpillar C-16 diesel engine

Refer to the blender operation and

maintenance manuals for proper
maintenance procedures for these engines.
• Oil Coolers Figure 3.21 – Hydraulic reservoir and filters
Modern blenders rely heavily on
hydraulically driven components and a large
amount of heat is created. The hydraulic • Filters and strainers
fluid needs to be kept below 180°F to be
Filters and strainers keep the hydraulic fluid
safe and effective. Hydraulic oil coolers
clean by trapping contaminants as fluid
work on the same basic principle as the
flows through them. Strainers are simply
radiator on a car engine. Hot hydraulic fluid
coarse filters.
enters an oil cooler heat exchanger where air
or water is forced past the oil to help cool it. • Pumps

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 Blenders and Auxiliary Equipment

Hydraulic pumps convert mechanical energy A drop in pressure at the outlet causes the
to hydraulic energy by pushing the hydraulic element (spring, gas, or weight) to react and
fluid through the system. Almost every force the fluid back out. Accumulators
component on a blender, from control valves absorb shocks or pressure surges due to the
to the centrifugal pumps, use this energy to sudden stopping or reversing of oil flow.
operate.
• Valves
Directional valves are used to control the
direction of flow. A check valve’s function
is to only permit fluid flow in one direction.

Figure 3.22 - Sundstrand series 90

hydraulic pump

• Accumulators
Figure 3.24 - Spool type directional valve
An accumulator stores incompressible
hydraulic fluids under pressure. As the fluid
enters the accumulator chamber, it does one
of three things: compresses a spring, • Cylinders
compresses a gas, or raises a weight. Cylinders are linear actuators. Linear means
that the ouput of a cylinder is a straight-line
motion and/or force.

Figure 3.25 – Linear actuator

Cylinders are used for remote operations

which require back and forth motion such as
sand screw lift.
• Hydraulic Motors
Figure 3.23 - Gas type hydraulic
accumulator Motor usually refers to a rotary hydraulic
actuator. Motors look very much like pumps

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 Blenders and Auxiliary Equipment

in construction, but instead of pushing the The main thing to understand about the
fluid, motors are pushed by the fluid. hydraulic system is that the hydraulic fluid needs
to be kept clean. When filling the hydraulic tank,
make sure the container you are transferring the
hydraulic fluid from is clean. Also, the hydraulic
fluid’s temperature can and does run above
180°F. The recommended heat range is below
180°F. So the fluid and thus the hoses and
connections are very hot. If the hydraulic oil
temperature is above 180°F, contact your local
mechanic.
When you see a leak, DO NOT PUT YOUR
Figure 3.26 – Sauer Series 90 hydraulic HAND ON IT. Hydraulic fluid is under pressure
motor and can be injected through your skin. This
injection of hydraulic fluid into your system can
require the injected portion to be removed.
This produces torque and rotating motion with Most of the hydraulic components on a blender
drives the sand screws, chemical additive are under computer control.
pumps, centrifugal pumps, etc.

Unit F Quiz

Fill in the blanks with one or more words to check your progress in Unit G.
1. Prime movers, or _______________, drive hydraulic _______________, which provide hydraulic
pressure to the system.

2. Hydraulic leaks should never be covered by ________________________.

3. Hydraulic lines can be very ____________.

4. Above ______°F hydraulic oil temp, you should contact your local mechanic.

Now, look up the suggested answers in the Answer Key.

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 Blenders and Auxiliary Equipment

Unit G: Instrumentation
Because of the complexity of today’s NOTE: Gelled fluids and oils affect the
stimulation chemicals and job procedures, and movement of the rotor and a turbine flow meter
the development of new, more critical processes, may give inaccurate readings at certain flow
accurate instrumentation on the blender is rates. Each fluid has a different effect on the
extremely important for the success of a flow meter.
stimulation treatment. The four most widely
Turbine flow meters range in size from ½ inch
used measuring instruments in stimulation are:
to 8 inches in diameter. The blender comes
• Flow meters equipped with two “clean side” flow meters
installed. The fluid can be pumped through
• Pressure transducers either of these flow meters by opening and
• Radioactive densometers closing valves. The choice will be determined by
the clean flow rate going through the meter.
• pH probes
It is very important for blender operations to
choose the correct size flow meter for the
Flow Meters expected rate on the clean side of the blender.
For rates less than 20 bpm, use the 4 inch flow
The most widely used flow meter for stimulation meter. For rates greater than 20 bpm use the six
is the turbine flow meter (Figure 3.27). It has a or eight inch flow meter depending on what is
rotor with vanes that spin when a fluid is installed on the blender.
pumped past the rotor. A magnetic pickup on the
outside of the flow meter counts each vane of
the rotor as it passes. Each vane creates one
pulse that is translated into a frequency. The
frequency reading from a flow meter is
converted into a rate. The flow meters have been
calibrated in Duncan with fresh water and have a
different calibration factor given in pulses per
gallon. This factor is accurate for fresh water
only.

Figure 3.28 – 8” Blender Turbine Flow

Meter

Blenders can also use an optional magnometer

type of flow meter. “Mag” flow meters have an
advantage over turbine flow meters in that they
do not have any moving parts and are less likely
to be damaged by debris traveling through them.
Figure 3.27 – 4” Blender Turbine Flow “Mag” flow meters work by measuring the
Meter. magnetic field created by fluid moving through

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 Blenders and Auxiliary Equipment

them. However, this also creates a severe is picked up by the PM tube. This can then be
disadvantage in that they are not able to measure converted into a fluid density or sand
non-conductive fluids such as diesel. Most concentration.
blenders do not have “Mag” flowmeters
installed.

Pressure Transducers

Pressure transducers take a fluid pressure and

convert it into an electrical signal that can be
recorded or used to control a piece of equipment
(Figure 3.29). There are two 0 – 300 psi pressure
transducers on the blender. The suction and
discharge side each have a transducer. These
transducers are used to control the centrifugal
pumps on the blender.

Figure 3.30 - Radioactive Densometer.

Densometers range in size from 2 inches up to 8

inches. 6 inch and 8 inch densometers are used
on the blender. Digital densometers make up the
majority of densometers in use today. A digital
densometer can be calibrated no matter what
fluid is in the flow chamber, but is more
Figure 3.29 – Blender 0-300 psi Transducer. accurate when calibrated using the Low Cal
value with the flow chamber empty of fluid.
The PM Tube should always be removed prior
to hammering up or loosening the connections.
Radioactive Densometers

Radioactive Densometers (Figure 3.30) are used pH Probe

for measuring stimulation fluid density. From
this density, the computer calculates the A pH probe on the blender is used to help
proppant concentrations. Densometers consist of monitor the pH of the fluids that are being
a lead shielded source material (Cesium-137), a pumped. This probe must be taken off the
flow chamber, and a photomultiplier tube (PM blender after every job and place in a carrier. An
tube). These densometers work on the principle electrode on the pH probe contains a solution
of absorption of radioactive particles. The source that must never dry out, so extreme care in
and PM tube are on opposite sides of the flow handling a probe is necessary. The pH probe is
chamber. Radioactive emissions are directed accurate in the pH range of 1 to 14.
across the flow channel and are detected and
amplified by the PM tube. As fluid passes in The calibration of the pH probe requires two or
front of the source, it absorbs some of the three known pH fluids. The pH probe should be
radiation. The denser the fluid, the less radiation

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 Blenders and Auxiliary Equipment

calibrated before every job to maintain accurate

measurement of the pH of the fluid.
The pH probe has a specific direction it should
be placed into the stream. The protective hood
should be placed upstream of the probe to keep
the slurry stream from coming into direct contact
with the pH probe end.

Figure 3.32 – ARC Operator Interface Panel

Factory Link ACE (Automatic Controlled

Equipment) blender software runs on Windows
NT operating system. ACE software is a later
Figure 3.31 – In-line pH probe generation of control software that employs the
use of touch screens as well as keyboard input.

The Graphical User Interface

(GUI)

On the ARC and ACE blenders, software is used

to control the blenders’ operation. An electrical
signal from the various sensors (pressure, rate,
pH, viscosity), referred to as feedback, is
constantly being returned to the controlling
computer. Feedback is an important element in
the operation of the blender. The computer must
make adjustments to each device it is monitoring
until each gives feedback that equals the “set Figure 3.33 – Factory Link ACE Graphical
point” that has been entered. Figures 3.32 And User Interface
3.33 are the ARC and ACE control screens.
ARC (Automatic Remote Control) blender
software is controlled with two-handed, push- The current version of ACE software operates
button function keys through an OIP (operator on Windows NT, 2000 and XP software.
interface panel) Improvements include: Built in error check for
operator inputs of chemical set-points as well as
automated bucket test for Liquid and dry
additives.

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 Blenders and Auxiliary Equipment

One great feature of this software is it’s ability The current version of ACE is replacing PCI-2
to be configured as a Blender, a Pump or a (Pump Controller Interface) inside our TCC’s
Mountain Mover. Another feature is the ability (Tech Command Centers). Using the same
to download the software from Halworld and GUI’s both on the equipment and insider the
install on a laptop computer for training control van, and individual has an easier
purposes. In “model mode” you can set up transition onto a job supervisor’s role.
pumps and pull slurry from the blender,
simulating a “virtual job.”
Electronic Failures from
welding EMI

During the process of welding, both conducted

and radiated electromagnetic interference (EMI)
can occur. EMI can range from tens to hundreds
of volts. EMI can cause electronic malfunction
and failure of components such as external
sensors, actuators and computers. Never weld on
any piece of Halliburton equipment without
following HMS guidelines and discussing with
your supervisor both safety precautions and
what EMI could do to attached electronics.
Figure 3.34 – ACE Blender Graphical User Additional information can be found in
Interface Technology Bulletin GST- 03-005.

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 Blenders and Auxiliary Equipment

Unit G Quiz

Fill in the blanks with one or more words to check your progress in Unit G.
1. The Turbine Flow Meter has a movable _______________ with ________________ that turn as fluid
passes.

2. The magnetic pickup on a Turbine Flow Meter counts each ________________ as it passes and
creates a ________________ that is translated into a ________________.

3. Turbine Flow Meters have a calibration factor that is determined using ________________________.

4. Each fluid has a different __________ on the flow meter.

5. The pressure transducers on the blender are used to control the ____________ pumps.

6. Radioactive Densometers work by measuring the amount of ________________ ________________

which passes through a fluid.

7. A Digital Densometer can be calibrated with ________________ fluid in the fluid chamber, but is
more accurate when calibrated using the __________ __________ value.

8. The two Graphical User Interfaces used on the blenders for operation are ___________ and
__________.

Now, look up the suggested answers in the Answer Key.

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 Blenders and Auxiliary Equipment

Self Check Test for Section 3: Blenders & Auxiliary

Equipment
Mark the single best answer to the following questions.
1. API gravity is:
______ A) the force of gravity
______ B) surface tension
______ C) the specific gravity of a fluid
______ D) a relative comparison of fluid specific gravity of oils.

2. A job requires the blender to pump a 58° API oil (high vapor pressure condensate) at 70 bbl/min.
How many suction hoses are required? (show work)

3. Which of the following will help increase the life of a hose?

______ A) Never drag the hose or pull it by the coupling when moving a hose from the blender to
the job.
______ B) Do not drive vehicles over hoses or use hoses for wheel chocks.
______ C) Do not allow any free length in the hose.
______ D) Do not drop hoses so the couplings receive undue shock.
______ E) All of the above.

4. When looking at the suction side of a centrifugal pump, the discharge is on the left side. What type of
centrifugal pump is this?
______ A) right-hand
______ B) left-hand
______ C) neutral
______ D) back-hand

5. In parallel operation of two centrifugal pumps, the ___________________ is equal to that of one
pump and the _____________________ is equal to the total of both pumps.
6. ______ True ________ False: If the pumps in #5 were in series operation, the system output would
be the same.

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 Blenders and Auxiliary Equipment

7. Sand screws deliver proppant to the blender. Sand screws are calibrated to deliver a specific number
of _______________ of proppant for each ______________ of the screw.

8. The hydraulic system on a blender is used to power

______ A) Sand screws
______ B) Liquid-additive pumps
______ C) Centrifugal booster pumps
______ D) Tub agitator
______ E) A, B, C and D

9. ______ True ______ False: Turbine Flow Meters are accurate for all fluids without any corrections
necessary.

10. ______ True ______ False: Radioactive Densometers are used to determine the density of a fluid.

Now, look up the suggested answers in the Answer Key.

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 Blenders and Auxiliary Equipment

Answers Keys
Refer to the pages provided as references if you answered any of these items incorrectly, or if you
were unsure of your answers.
Items from Unit A Quiz
1. couplings / hose cover / hose tube
2. spiral reinforced / wire
3. flow rate / viscosity
4. vapor / lighter
5. 40 bpm ÷ 10 bpm/hose = 4 hoses
4 hoses × 1.5 (for high vis fluids) = 6 hoses
6. covered / fluid
7. free length
8. flush / drain
9. straight
10. flashlight / looking

Items from Unit B Quiz

1. storage tanks / high pressure pumps
2. abrasive fluids
3. air
4. head
5. cavitation
6. valve
7. one / two
8. center (eye)
9. drop / increase

Items from Unit D Quiz

1. one tenth (1/10)
2. fluid / destroy
3. one percent (1%)
4. sack-fed / screw feeder
5. harden / turning
6. free flow

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 Blenders and Auxiliary Equipment

Items from Unit E Quiz

1. independent
2. 12 / 14
3. proppant / lbs per revolution2. proppant / lbs per revolution
4. 100
Items from Unit F Quiz
1. engines / pumps
2. your hand
3. hot
4. 180
Items from Unit G Quiz
1. rotor / vanes
2. vane / pulse / frequencyvane
3. fresh water
4. effect
5. centrifugal
6. radioactive particles
7. any / any / emptylow cal
8. ARC / ACE

Self Check Test

1. D
2. 70 bpm ÷ 10 bpm per hose = 7 hoses
7 hoses × 1.5 (for high vapor pressure fluid) = 3.5 round up to 4
7 hoses + 4 hoses = 11 hoses
3. E
4. B
5. head/rate
6. F
7. lbs per revolution pounds / revolution
8. A, B, C, D
9. F
10. T

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Section 4

High Pressure Pumping

Equipment

Table of Contents
Introduction ................................................................................................................................................ 4-3
Topic Areas ............................................................................................................................................ 4-3
Learning Objectives ............................................................................................................................... 4-3
Unit A: HT-400 Pumps .............................................................................................................................. 4-3
Pumping Units ........................................................................................................................................ 4-4
HT-400 Pump ......................................................................................................................................... 4-4
Power End .............................................................................................................................................. 4-4
Fluid End ................................................................................................................................................ 4-5
Spacer ..................................................................................................................................................... 4-7
Protective Front Covers .......................................................................................................................... 4-8
Unit A Quiz ............................................................................................................................................ 4-9
Unit B – HQ-2000 Pumps ........................................................................................................................ 4-10
Unit B Quiz .......................................................................................................................................... 4-13
Long-Life Monoblock Fluid End Section ............................................................................................ 4-15
Standard HT-400 Valving .................................................................................................................... 4-15
Unit C Quiz .......................................................................................................................................... 4-16
Unit D: Pressure-Volumetric Rate and Hydraulic Horsepower ............................................................... 4-17
Horsepower .......................................................................................................................................... 4-17
Torque Speed Characteristics ............................................................................................................... 4-17
Volumetric Rate ................................................................................................................................... 4-18
Unit D Quiz .......................................................................................................................................... 4-21
Answer Keys ........................................................................................................................................ 4-24

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 High Pressure Pumping Equipment

Use for Section notes…

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 High Pressure Pumping Equipment

Introduction
Accurate performance in the field is up to the • HT-2000 Pumps
individual stimulation operator. As with all areas
of stimulation, you can do the best job if you • Pressure, Volumetric Rate and
know exactly what you are doing and what Hydraulic Horsepower
equipment you need to use.
This section discusses high pressure pumping Learning Objectives
equipment that will help you perform on the job.
As you learn more about the equipment, Upon completion of this section, you will be
remember that it is important to pay attention to familiar with:
specific uses.
• Descriptions and functions of high
pressure pumping equipment
Topic Areas • Care of high pressure pumping
equipment
The section units are:
• Basic calculations used with high
• HT-400 Pumps pressure pumping equipment
• HQ-2000 Pumps

Unit A: HT-400 Pumps

Figure 4.1 - FPR-A Twin HT-400 Pumping Trailer

All Halliburton built positive displacement HT-400 Pump is different from most other
pumps have a power end and a fluid end. Some pumps because it is:
have a spacer installed between the two ends to • Capable of extremely high pressure, up to
keep unwanted fluids from entering the power 20,000 psi (2 3/8 in. fluid end)
end. There are basic design characteristics that
are the same for various pumps. However, the

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 High Pressure Pumping Equipment

• Capable of producing up to 38 bbl/min (6

in. fluid end)
• Lightweight and compact
• Precision-built to give high performance
and long life.
This unit will discuss HT-400 pump power ends,
fluid ends and spacer components.

Pumping Units
Figure 4.2 – Three main parts of an HT-400
The FPR-A Twin HT-400 Pumping Trailer is
designed for high pressure, high volume
fracturing (Figure 4.1). It is powered by 2
Detroit 12V-92TA turbocharged diesel engines Power End
that deliver 800 BHP (Brake HorsePower) each.
Two Allison CLT-6061 5 speed transmissions
The power end converts rotary input power into
deliver this power to two Halliburton HT-400
reciprocating power that is applied to the
pumps.
plungers of the fluid end. There are left and
Operating information relating to the truck, right-hand power ends. Left-hand power ends
trailer or skid on which the HT-400 pump is have ring gear housings (the enlarged part of the
installed can be found in manuals written about cases) on the left side, which can be seen when
that truck or trailer. These manuals are furnished looking at the pump from the fluid end. Right-
with new equipment, but additional copies are hand pumps have gear housings on the right
available from the Engineering Department, (Figure 4.3).
Drawer 1431, Duncan, OK 73536.
Operation and maintenance information relating
to the engine and transmission driving the pump
is covered in the Pumping Equipment Data Book
(277.17165) published by the Engineering
Department in Duncan and available through the
Materials Department.

HT-400 Pump

The workhorse of Halliburton’s pumping

equipment is the HT-400 pump. This is a well-
designed, long-life pump. The HT-400 pump Figure 4.3 – Right-hand HT 400 Pump
has three primary components: the power end,
fluid end and, in many cases, a spacer. These
three components need to be understood in
The power end lubrication system is a critical
order to use the pump to its maximum potential.
part of the pump. It should be kept well
maintained. The system’s high volume, gear-
type oil pump is driven off of a PTO on the deck
engine on most stimulation pumps. During high
speed pumping with worm mounted oil pumps,

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 High Pressure Pumping Equipment

the pump may deliver oil at rates up to 100 can be found on some HT-400’s that are used as
GPM. If the power end does not require this mud pumps on remote drilling or workover
much oil, any excess oil is bypassed. operations. Their elements can be removed,
washed and reused.
The bypass valve dumps the excess back onto
the ring gear and into the sump. The bypass Oil temperature and pressure gauges are
pressure should be set at 80-100 psi. important components of the lubrication system.
Adjustments are made by turning the regulating If the gauges are not working, you may not
screw. If the system pressure stays below 80 psi, know if the other parts of the system are failing
the piston or ball should be checked to be sure until it is too late.
that it is not stuck open.
The oil used in HT-400 power ends is an
Crosshead and gear bearing oilers are nozzles extreme pressure gear oil which performs best
that allow small amounts of oil to lubricate the when the temperature is kept below 200°F.
crossheads and bearing without robbing other Because these oils “wear out”, it is
areas of oil. It is important that these oilers stay recommended that they be changed regularly at
open. They should be cleaned out any time the six-month intervals or any time the oil is
oil system has been contaminated by solid contaminated. Seasonal changes, to adjust for
particles. temperature variations, are recommended for
most areas. Synthetic lubes may eliminate the
The crankshaft oil injector and its seal supply oil
need for seasonal changes and extend wear-out
to the crankshaft passages. The magnetic seal is
life to two years.
more dependable than the rubber lipped seal
previously used. However, the magnetic seal can
develop leaks. Those leaks may be hard to Fluid End
detect, since they occur inside the case.
Therefore, if low oil pressure is observed, check
the injector seal as a possible cause.
A tube and shell or some other type of heat
exchanger is now being used. It is attached as a
separate unit and is no longer built into the HT-
400 case. Newer pumping units use air to cool
the oil.

Figure 4.5 - HT-400 Fluid End

The fluid end (Figure 4.5) of the HT-400 is

where the work of pumping stimulation fluids is
Figure 4.4 - Tube and shell type heat done. It is composed of three fluid end sections
exchanger containing:
• suction and discharge valves, seats and
guides
Schroeder filters are used on all pumps now
being produced. Some older units will still have • a plunger
Cuno filters on them. Marvel wire-mesh filters • a packing bore

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 High Pressure Pumping Equipment

• packing arrangement Valves seal against a metal seat pressed into a

hole bored in the fluid end. The seats are tapered
• discharge flanges slightly on the outside. An adapter must be used
A Fluid End Section is a steel forging that acts as for older style pumps having straight bores.
the fluid chamber. Fluid end sections have the
same outside dimensions and the inside of the
section determines the “size” of the fluid end.
Horizontal bores are cut for 3-3/8, 4, 4-1/2, 5,
and 6 inch plungers. It also has a vertical bore
containing the suction and discharge valves. A Either Small
End
discharge passage is located at the top of the Towar d End
Plunger Toward
vertical bore. Plunger

The movement of the Plungers causes fluid and

materials to move through the fluid end section.
Plungers have a hard surface that is flame-
sprayed and fused with a hard, metallic powder
onto the plungers and then ground for
smoothness.. Plungers are connected to the
crosshead in the power end by a series of bolts.
Cylinder-Shaped Cone-Shaped
Suction and Discharge Valves control the Spr ing Spring
direction of fluid movement. Suction and
discharge valves are known as “frac” valves Figure 4.7 - Valve Set Springs
(Figure 4.4). Machined from a forging, each has
a carburized surface to cut down on wear. A
rubber insert fits on the valve to provide a Metal Springs (Figure 4.7) hold the valves
positive sealing surface. The valve has two against their seats. Newer cylindrical springs can
stems. be put in with either end up. Older, conical
springs must be put in with the small end toward
the plunger.

Figure 4.8 - Bushing Retainers

Bushing Retainers (Figure 4.8) are placed

directly below the valve seats. The lower stem of
the frac valve fits through these. Newer styles
Figure 4.6 - Frac Valve and Seal

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 High Pressure Pumping Equipment

can be installed with either side up. Older styles design, which is recommended for field service,
must be installed a certain way. These bushing is the L-2 Spacer or L-4 Spacer. Unlike its
retainers guide the valves in an up and down predecessor, the L-1 Spacer, fluid end sizes can
motion. be changed on the L-2 and L-4 without altering
alignment of the push rods.
The upper stem of the suction valve is guided by
the Suction Valve Stop. The stop is locked into Push rod seals are used in the wiper glands when
the bore above the suction valve and directly a spacer is installed. Seals that are part of the
below the plunger. The upper stem of the spacer perform the glands’ function.
discharge valve is guided by a bushing in the
Flanges are used to connect the discharge
discharge cover.
manifold to the fluid end and to seal unused ends
Pressure Packing is used to keep fluid from of the fluid end’s discharge passage.
leaking out of the back of the plunger bore.
Many different types of packing are available.
The packing bore is machined slightly larger
than the plunger bore to allow the packing to fit.
Newer HT-400’s have a removable metal sleeve
in the packing bore so the sleeve can be replaced
when it wears out. (When the packing bore wore
out on older fluid ends, they were junked.) Note:
Do not plug the vent hole in the metal sleeve.

Spacer
The spacer separates the fluid end from the
power end and prevents the plungers and the Figure 4.10 - Flanges
contaminants they carry from entering the power
end. Every pump needs a spacer. Unfortunately,
weight limitations do not allow their use on all
The blank flange (Figure 4.10) does not take up
types of equipment.
much room. It is used to seal the discharge
passage when fluid end clearance is limited.
The straight flange has a single connection for
manifolding, while the ELL flange has two
(Figure 4.7). The horizontal connection of the
ELL is used for manifolding. The top connection
is most often used for installation of a pressure
gauge. Size of the connection is designated by
its nominal diameter.
The pressure rating of the flange designates the
threads of the connections. A 15,000 psi flange,
Figure 4.9 - HT-400 spacer used on the larger fluid ends, has connections
with union threads that mate with manifolds
rated at 15,000 psi. Connections of a 20,000 psi
The D-Spacer was the earliest design. The M-1 flange, used on the smallest fluid end, are mated
Spacer, very similar to the “D”, was developed only for manifolds rated at 20,000 psi.
later for pumps used as airlift mud pumps.
Design of the “M” made the pump easier to
break down for air transport. The latest spacer

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 High Pressure Pumping Equipment

Protective Front Covers

Protective Front Covers (Figure 4.11) have been

developed to protect HT-400 fluid ends from
becoming damaged by sand packed in front of
the plunger. Damage results when the sand
creates a “sandout,” or when “closed stops”
cause excessive discharge pressures. The
protective covers prevent overloads and take
much of the risk out of pumping high sand
concentrations for well stimulation and sand
control work.

Figure 4.12 - Ruptured Front Cover

Some of the obvious advantages of using the

protective front covers are that they:
• Help prevent damaging overloads due to
sandouts or overpressure in HT-400
pumps. See the ruptured disk from a
sandout in Figure 4.9
• Help sand flow from the space in front of
Figure 4.11 - Protective Front Covers the plunger when handling high sand
concentrations.
• Allow quick replacement of the cover if
The protective front cover is a shear disc that it fails instead of having to replace the
fails before overloads become great enough to fluid end itself.
damage other pump parts. The disc is contained,
• Last as long as the average fluid end.
or “caught,” by the special retainer. The
Fatigue failures in the field should be
Retainer-Catcher is for use with the protective
rare.
cover; they must be used together. Substituting a
standard retainer causes cover seals to leak badly Protective covers should not be used with
as soon as a pump develops pressure. corrosive materials (acid) or when pumping
CO2..

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 High Pressure Pumping Equipment

Unit A Quiz

Fill in the blanks with one or more words to check your progress in Unit A.
1. Depending on the fluid end, a HT-400 pump can produce up to _______________ bbl/min or
pressure up to ________________ psi.

2. All HT-400 pumps have a ________________ end and a _________________ end.

3. As you look at the HT-400 pump from the fluid end, the left-hand power end will have the ring gear
housing on the ________________ side.

4. Fluid end sections on HT-400s have the same ________________ dimensions. The
_________________ dimensions determine the “size” of the fluid end.

5. The ____________________ cause the movement of fluids through the fluid end section.

6. ____________________ packing is used to keep fluids from leaking out the back of the plunger bore
on the HT-400.

7. The protective front covers allow quick replacement of the cover if it fails instead of the
________________ ________________ itself.

8. Protective covers should not be used with ________________ or when pumping

_________________ __________________..

Now, look up the suggested answer in the Answer Keys.

© 2013 Halliburton 4•9 Stimulation I

 High Pressure Pumping Equipment

Unit B – HQ-2000 Pumps

Figure 4.13 - Model FPR-SJ HQ-2000 Trailer Pumping Unit

The HQ-2000 (grizzly) pump is Halliburton’s 6.313:1. This steel gear set allows the pump to
quintiplex (5 cylinder) pump. The HQ-2000 is be operated at higher temperatures and at a
capable of putting out 2000 hydraulic higher rate of efficiency. The pump’s parallel
horsepower (HHP) at maximum RPM and can drive design uses the existing main structure of
put out 1600 HHP at peak torque. The HQ-2000 the gear housing to firmly support both ends of
pump is an HT-400 pump that has been the pinion.
modified into a five-plunger pump. The HQ- All Halliburton downhole pumps are positive-
2000 pump uses a large number of the same displacement pumps. For a positive-
parts as the HT-400 pump which has nominal displacement pump to perform efficiently, the
rating of 625 HHP. For two pumps (1 truck) the pump suction should be supercharged or
nominal rating is 1,250 HHP. boosted. Boost pressure must be high enough to
fill the fluid end as the plunger recedes on its
suction stroke. Proper maintenance and planning
is critical to the accurate performance of this
kind of high-pressure pumping equipment.
Insufficient pump suction pressure causes torque
spikes that exceed the safe operating limits of
the 9800-series Allison transmission used on the
HQ-2000 (Grizzly) pump. The HQ-2000 pump
has a pump gear ratio of 6.3:1, whereas the HT-
400 pump has a pump gear ration of 8.4:1. This
means the Grizzly pump has two more plungers
than the HT-400 pump, and it also turns much
Figure 4.14 - HQ-2000 faster or has a higher crankshaft rev/min,
making it more sensitive to low suction pressure.
For high-pressure pumping equipment to operate
The gear reducer on the HQ-2000 pump is a properly and efficiently, the following items
single helical gear set with case-carburized and must apply:
ground gear teeth, and a gear reduction ratio of

© 2013 Halliburton 4 • 10 Stimulation I

 High Pressure Pumping Equipment

• The operator must understand hydraulic Plungers are available in five sizes (3-3/8, 4, 4-
pump horsepower (HHP) and how pump 1/2, 5, 6 in.) and are flame-sprayed with an
performance is affected through pressure- extremely hard coating for wear resistance.
volumetric rate output of a pumping unit. The valves on the HQ-2000 pump are double-
• High-pressure pump valves, valve guides, guided frac valves. Both valves and seats are
and valve seats must be in good condition. case-carburized to enhance wear and erosion
protection.
• The correct type and number of frac hoses
should be used (Table 4.1). The power end (gear portion) requires an
external lube pump with a flow capacity of 50
• The fluid being pumped must be free of gal/min at 100 to 120 psi. An external lube oil
entrained air. tank is not required; all oil flows through an
• The blender must be operated properly. externally mounted filter before it enters the
pump.
Volume
(bbl/min) Number of Hosesb

5 2
10 3
30 5
40 to 50 6
Table 3.1 - 4 in. ID Blender Suction Hosesa

The capacity for pumping water or moderate

gels is 10 bbl\min per 20 ft of hose. For high-
viscosity fluids or fluids with high vapor Figure 4.15 - Power End Lube Pump
pressure, multiply the number of hoses by 1.5.
The HT-400 and HQ-2000 have numerous
common component parts. These common parts Pinion bearings are force lubricated. The gear
include almost all fluid-end expendable parts, mesh is force-lubricated and incorporates a
such as fluid-end sections, valves, valve inserts, diverter that captures oil after it enters the main
valve seats, plungers, and packing. Common gear and slings it into the gear mesh.
power-end parts include connecting rods, The fluid end uses a re-circulating lubrication
connecting rod bearings, crossheads, crosshead system that helps cool and flush the packing
pins, crosshead slides and shoes, pushrods, and gland area. This type of system uses less plunger
main crankshaft bearings. lube oil and is less likely to leak than pneumatic
Despite the increased horsepower placed on the systems.
HQ-2000 pump, any roller bearing used in this
pump can withstand 900 hours of operation at
full load. Under normal loading conditions with
no catastrophic failures, such as sandout of loss
of lube, the life of these bearings should be
greater than or equal to the life of the pump.
The wet weight of the HQ-2000 pump is
approximately 10,600 lb. This weight includes
the companion flange but does not include the
suction manifold.

© 2013 Halliburton 4 • 11 Stimulation I

 High Pressure Pumping Equipment

Because the HQ-2000 pump is a quintiplex

pump, vibration resulting from flow variation
and discharge pulsation is less than in a triplex
pump. The decreased flow variation provides an
advantage when well tubulars have deteriorated
or when tubular stress safety factors are
approaching marginal values. Figure 4.16
compares flow variation of a triplex pump and a
quintuplet pump.
Any of the fluid-end assemblies can be fitted
with protective cylinder-head covers (sandout
caps). These covers shear if there is a sandout or
Figure 4.16 - Comparison of Triplex to accidental overpressure occurs.
Quintiplex

© 2013 Halliburton 4 • 12 Stimulation I

 High Pressure Pumping Equipment

Unit B Quiz

Fill in the blanks with one or more words to check your progress in Unit B.
1. 1. The HQ-2000 (grizzly) pump is Halliburton’s ____________________ pump.

2. The HQ-2000 is capable of putting out ____________________ hydraulic horsepower (HHP) at

_______________ _______________ and can put out 1600 HHP at _______________
_______________.

3. The fluid end uses a ____________________ lubrication system that helps cool and flush the packing
gland area.

4. Any of the fluid-end assemblies can be fitted with protective ____________________

____________________ ____________________.

5. These covers ____________________ if there is a _____________________or an accidental

overpressure occurs.

Now, look up the suggested answers in the Answer Key.

© 2013 Halliburton 4 • 13 Stimulation I

 High Pressure Pumping Equipment

Unit C: HT-2000 Pumps

Figure 4.17 - Model FPR-SI HT-2000 Trailer Pumping Unit

The Halliburton HT-2000 is a high-powered for maintenance information on this particular

crankshaft-type triplex plunger pump for use fluid end.
primarily in well stimulation. Three basic sub-assemblies make up the pump:
1. The planetary speed reducer has a 9.21:1
reduction. Mechanical efficiency is about 98
percent, which significantly reduces energy
costs.
2. The power end design incorporates an offset
crankshaft and a compression-loaded
crosshead structure.
3. The fluid end is a monoblock (one big
chunk) design, machined from an alloy steel
Figure 4.18 - HT-2000 forging.
The pump is particularly suited to high sand
concentration slurries and high-pressure work
Prior to 1994, the HT-2000 was built in two and the unit incorporates many new design
plunger sizes: 5 in. and 6 in. A 4.5 in. fluid end features to insure longer life and safer operation.
is now available which allows pumping at
pressures at 20,000 psi when equipped with Design Features
Halliburton “Big Inch” discharge manifolding.  High efficiency planetary gear train.
The 4.5 in. fluid end is similar in construction to
 Offset crankshaft that distributes crosshead
the 5 in. and 6 in. versions and generally uses
loading and provides a smoother discharge
the same maintenance procedures as described
stroke.
in the HT-2000 pump manual. Please refer to
Halliburton manual 334.16000 for general  Twelve-inch (12 in) stroke, which
information about the HT-2000 pump. Refer to minimizes cycling and prolongs packing
Halliburton “Addendum for 4.5 in. Fluid End” life.

© 2013 Halliburton 4 • 14 Stimulation I

 High Pressure Pumping Equipment

 A Monoblock fluid end for increased fatigue

life.
 Pre-loaded cylinder head covers that A
significantly reduce fatigue loading.
 Recirculating packing lube system that cools B
and cleans the reciprocating plungers and
keeps the job-site clean.
The preloaded covers pressure is 16,500 –
18,000 psi and is controlled from the operator
panel.
Of particular importance, the tie-bolts require
tensioning jacks to remove and install. Do not
attempt to remove a monoblock fluid end C
without proper equipment and knowledge of the
procedure. D

Figure 4.19 - HT-2000 Fluid End

Long-Life Monoblock Fluid End
Section
The 5 in. and 6 in. HT-2000 pumps use a hollow
The 4.5 in, 5 in. and 6 in. fluid end sections are welded plunger design (Figure 4.19 - B). The 4.5
almost identical externally but are quite different in. fluid end uses a solid plunger for higher
in geometry on the inside. To minimize stresses strength and ease of manufacture. An
and to provide longer fatigue life, a specific fluid unfortunate aspect of the 4.5 in. fluid end design
end section is built for each plunger size. The is the plunger adapter which is clamped to the
4.5 in. fluid end section features smaller plunger pushrod will not fit through the plunger bore on
bores and smaller valve bores. These bores are the 4.5 in. fluid end as it does on the 5 in. and 6
“scalloped” (elongated) in some cases to allow in. versions. The 4.5 in. plunger adapter must be
for valve installation and to increase fatigue life. separated before pulling the plunger out of the
front of the fluid end.
On the HT-400 fluid end sections, the suction
Standard HT-400 Valving valve retainer is held in place vertically by
grooves which are machined into the sides of the
The 4.5 in. HT-2000 fluid end uses the #5 suction bore. The retainer is oriented front-to-
valves, seats, and valve trim as used on 5 in. and back, lowered into place, and rotated 90 degrees
6 in. HT-400 fluid ends. into a side-to-side orientation. A hairpin spring
The packing bore is dimensionally the same as a attached to the retainer engages a notch in the
4.5 in. HT-400 fluid end and uses the same fluid end to lock the retainer in place. The 5 in.
packing components. To achieve longer fatigue and 6 in. HT-2000 fluid ends take advantage of
life in the plunger bore, a replaceable packing scalloped suction bores to hold the suction valve
sleeve is not used. retainer in place vertically (Figure 4.19 – C).
The suction bores in these fluid ends are
The 5 inch and 6 inch HT-2000 fluid ends use a elongated side-to-side. The retainer is lowered
packing retainer screw with an adjustable stop into position then rotated 90 degrees into a front-
(Figure 4.19 – A). To simplify construction and to-back alignment. A locking pin is then
assembly, a one-piece non-adjustably screw is installed from the front of the fluid end which
used on the 4.5 in. fluid end. prevents the retainer from rotating out of place
(Figure 4.19 – D).

© 2013 Halliburton 4 • 15 Stimulation I

 High Pressure Pumping Equipment

Unit C Quiz

Fill in the blanks to check your progress in Unit C.

1. The Halliburton HT-2000 in a high powered crankshaft-type ____________________ plunger pump.

2. The HT-2000 fluid end is a ____________________ design.

3. The 4-1/2 inch fluid end allows the HT-2000 to pump up to ____________________ psi when
equipped with Halliburton ____________________ ____________________ discharge manifolding.

4. The HT-2000 has a stroke length of _______________ inches.

5. The tie-bolts on the HT-2000 require ____________________ _____________________ to remove

and install.

Now, look up the suggested answers in the Answer Key.

© 2013 Halliburton 4 • 16 Stimulation I

 High Pressure Pumping Equipment

Unit D: Pressure-Volumetric Rate and Hydraulic

Horsepower
Understanding pump horsepower and drive torque required for a given pump pressure.
requirements will give everyone concerned with While lug-back speed is determined by
maintenance and operation an appreciation of torque conditions, horsepower actually
proper prime mover and transmission selection. increases with speed. Therefore, to get
maximum hydraulic horsepower, engines
In this unit, a review of horsepower concepts should be operated near the maximum rated
and calculations is presented prior to a speed if possible, but definitely above lug-
discussion of pump performance through back conditions.
pressure-volumetric rate output.

W orm
Engine Speed Transmission Gear
Reduction
Horsepower Reduction
0.4 to 1
HT-400
Internal
Horsepower output by a pump, or hydraulic Reduction

horsepower (HHP), is less than input ERPM TR Pump Speed

PRPM
horsepower from the engine (EHP) because of Dat a For: 4 1/2-in. HT-400
mechanical losses. These losses occur in the fan, Cummins VT-12 700 Engine
Allison CLT-6061 Transmission
transmission and pump, and will be in the range Rat io in
of 5% to 20%. The use of 12% for calculations Gear Direct Drive
1 4.0
is reasonable; thus: 2 2.68
3 2.01
4 1.35
Output HP = Input HP - losses 5 1.0

HHP = EHP - 0.12 (EHP) Figure 4.20 - Transmission Ratio/Pump

Therefore, for 600 engine HP, pump output Speed Chart
would be:
HHP = 600 HP - 0.12 (600 HP) The majority of transmissions in use today
HHP = 600 HP - 72 HP = 528 HHP are torque converters. Shifting is
accomplished automatically although
Hydraulic horsepower of the pump can also be manual changing is provided. Because of
calculated from its output conditions of pressure their method of operation, they have no
and volumetric rate. Details of pressure and fixed gear ratios in the converter mode.
volumetric rate, usually designated as P-V data,
However, these transmissions will go into
will be given later in this unit. “lockup” under certain conditions. At this
point, there is a fixed gear ratio. We will
use these “lockup” ratios in the following
Torque Speed Characteristics example.
Diesel engines are used to drive the majority of Torque and speed are changed in the pump
HT-400 pumps. Others are powered by electric since there is an internal reduction (IR) in
motors. The torque output of a diesel engine the worm-gear drive of 8.4 to 1 for standard
gradually increases from its top speed to a stimulation HT-400’s. Therefore, torque is
maximum at the lug-back speed, at which point increased and speed decreased 8.4 times
it drops sharply. At this lug-back speed, from the values supplied the pump through
transmission range must be lowered to match the the transmission. An example would be: An

© 2013 Halliburton 4 • 17 Stimulation I

 High Pressure Pumping Equipment

HT-400 frac pump is being operated in 4th gear,

and the engine speed (ERPM) is 1800 RPM.
What is the pump speed?
Use the chart in Figure 4.21 to look up the
transmission ratio (TR) for 4th gear. Then plug
the known values in these formulas to obtain
transmission speed and pump speed:
ERPM
Transmission Speed (TS) =
TR
1800RPM
=
1.35
= 1333.3333 RPM Figure 4.21 - Pressure Volume Curves

TS
Pump Speed (RPM) =
IR • Volume = (Plunger Area) × (Stroke
1333.33 Length)
=
8.4 • Volume per Pump Revolution =
= 158.73015 RPM (Plunger Area) × (Stroke Length) ×
(Number of Plungers) × (Volumetric
Combining both calculations, pump speed can Efficiency)
be found directly:
• Volumetric Rate = (Volume per
ERPM Pump Revolution) × (Pump Speed)
Pump Speed =
TR × IR NOTE: One pump revolution refers to one
1800RPM complete turn of the crankshaft.
= = 158.73015 RPM
1.35 × 8.4 Example:
Other worm gear reductions have been used also What is the volume per pump revolution
(e.g., 7.2 to 1 and 8.6 to 1). Other pumps (T-10, under these conditions?
HT-200, HT-150) have various internal
reductions; therefore, use appropriate IR value, 5 in. HT-400 Triplex
regardless of which type (worm gear, planetary 8 in. Stroke Length
gear, chain drive, etc.) is used.
220 RPM Pump Speed
Assume 97% volumetric efficiency.
Volumetric Rate
Solution
Volume per pump revolution equals plunger Volume per revolution equals the
area times stroke length, but we also multiply by multiplication of plunger area (PA),
the number of plungers as well as volumetric stroke length (SL), number of plungers
efficiency. The number of plungers for a HT- (N) and volumetric efficiency (VE).
400 is always three since it is a triplex pump. VPR = PA × SL × N × VE
Volumetric efficiency is in the range of 94 to
98%. If you know the volume displaced during PA = 5in × 5in × .7854 = 19.635 in 2
one pump revolution, you can calculate the total
in 3
volumetric rate by multiplying this value by VPR = 19.635 in 2 × 8 in × 3 × 0.97 = 457.1028
pump speed. The following formulas show how rev
this works:

© 2013 Halliburton 4 • 18 Stimulation I

 High Pressure Pumping Equipment

Notice that the unit for VPR is cubic inches. curves. Most of the curves for torque
Since we are familiar with volumes expressed converter transmissions are computer
in gallons, we can convert to gallons. One calculated.
gallon equals 231 cubic inches. Therefore,
An enlarged section of a P-V curve is
in 3
1 gal gal shown in Figure 4.22. The main points of
VPR = 457.1028 × 3
= 1.9788 interest have been labeled on the 7th gear
rev 231 in rev curve. These points are typical of all gears.
Point A is on the lug-back speed line. Point
Example: B is at full load speed. Point C shows that
at lug-back speed in 8th gear, you can
What is the volumetric rate under the same
downshift to 7th gear and increase the HHP
conditions? output of the pump. Maximum
Volumetric Rate is obtained by multiplying performance is at Point B while minimum
the volume per revolution by pump speed. volume is at Point A. Pressure increases
can cause engine lug-back. This causes the
VR = VPR × PRPM pump to turn more slowly and decreases
gal rev gal HHP output.
VR = 1.9788 × 220 = 435.336
rev min min Figure 4.22 is the P-V curve of the power
As discussed at the beginning of this section, the train listed in Figure 4.22. It is similar to
power train (pump, transmission, and engine) most P-V curves in use. However, note that
can affect HHP because of energy losses. The there are several lug-back speed lines. This
performance (rate vs. pressure) of a given set of is necessary because the transmission can
components can be plotted on logarithmic paper. operate in the two regions explained earlier.
Since there are many combinations of different In the converter mode, not all engine output
components, each combination requires a may be transmitted to the pump. That is
separate graph. Each curve can be determined why the graph shows lines for 70% and
experimentally. However, enough accurate data 80% of full load in the converter mode.
exists to allow for computer simulation of P-V

© 2013 Halliburton 4 • 19 Stimulation I

 High Pressure Pumping Equipment

Figure 4.22 - Performance Curve

© 2013 Halliburton 4 • 20 Stimulation I

 High Pressure Pumping Equipment

Unit D Quiz

Fill in the blanks to check your progress in Unit B.

1. Horsepower output by a pump is called ____________________ horsepower.

2. The mechanical losses from the input horsepower, which occur in the fan, transmission and pump
itself, will normally be in the range of 5% to _____%. For the purpose of calculating, _____% will be
used.

3. To get maximum hydraulic horsepower, engines powering the HT-400 pump should be operating
near the maximum rated speed and definitely above ____________________ conditions.

4. Torque and speed are changed in the pump since there is an interval reduction in the worm-gear drive
of _______________ to 1 for standard stimulation HT-400’s.

5. Pump speed (PRPM) can be calculated by dividing ____________________ ____________________

by the HT-400’s ____________________ .

6. Volume per pump revolution = plunger area x stroke length × ____________________ of

____________________ x the volumetric efficiency.

7. To calculate volumetric rate, multiply the volume per revolution (VPR) by

______________________ and by ____________________.

Now, look up the suggested answers in the Answer Key.

© 2013 Halliburton 4 • 21 Stimulation I

 High Pressure Pumping Equipment

Self Check Test

Mark the best answer(s) to the following questions.
1. Which of the following is not a characteristic of the HT-400 pump?
_____ A) capable of extremely high pressure, up to 20,000 psi
_____ B) heavy weight
_____ C) compact
_____ D) precision built to give high performance and long life
2. On the HT-400 pump, what component converts rotary input power into reciprocating power applied
to the plungers?
_____ A) fluid end
_____ B) spacer
_____ C) power end
_____ D) none of the above
3. A 4 ½” HT-400 pump has how many plungers?
_____ A) 3
_____ B) 5
_____ C) 7
4. What is used to separate the fluid end from the power end, and prevent the plungers and contaminates
they carry from entering the power end?
_____ A) straight flange
_____ B) auto-klean filter
_____ C) blank flange
_____ D) spacer
5. Because of losses, horsepower output by a pump (hydraulic horsepower / HHP) is less than input
horsepower from what?
_____ A) the fan
_____ B) the engine
_____ C) the transmission
_____ D) the pump
6. Which of the following is/are being used to drive HT-400 pumps?
_____ A) diesel engines
_____ B) gas turbines
_____ C) diesel engines and electric motors
_____ D) none of those listed

© 2013 Halliburton 4 • 22 Stimulation I

 High Pressure Pumping Equipment

7. Plunger area times stroke length times number of plungers times volumetric efficiency equals what?
_____ A) area per pump revolution
_____ B) volume per pump revolution
_____ C) pump speed
_____ D) plunger length
8. One pump revolution refers to how much of a turn of the pump crankshaft?
_____ A) one complete turn
_____ B) ½ of a turn
_____ C) ¼ of a turn
_____ D) one and a half turns

© 2013 Halliburton 4 • 23 Stimulation I

 High Pressure Pumping Equipment

Answer Keys
Items from Unit A Quiz
1. 38/2000
2. power/fluid
3. Left
4. Outside \ inside
5. Plungers
6. Pressure
7. Fluid End
8. CO2 / Corrosive Materials acid/CO2

Items from Unit B Quiz

1. Quitiplex
2. 2000 / maximum rpm / peak torque
3. recirculating
4. cylinder-head covers
5. shear / sandout

Items from Unit C Quiz

1. Triplex
2. monablock
3. 20,000 / Big Inch
4. 12
5. Tensioning jacks

Items from Unit D Quiz

1. hydraulic
2. 20/12
3. lug-back
4. 8.4
5. Engine RPM/internal reduction
6. number / plungers
7. pump speed / volumetric efficiency

© 2013 Halliburton 4 • 24 Stimulation I

 High Pressure Pumping Equipment

Self Check Test

1. B
2. C
3. A
4. D
5. B
6. C
7. B
8. A

© 2013 Halliburton 4 • 25 Stimulation I

 Section 5

Manifold Equipment

Table of Contents
Introduction................................................................................................................................................5-3
Topic Areas ............................................................................................................................................5-3
Learning Objectives ...............................................................................................................................5-3
Unit A: Manifolding and End Connections ...............................................................................................5-4
Manifolding............................................................................................................................................5-4
End Connections ....................................................................................................................................5-5
Unit A Quiz ............................................................................................................................................5-6
Unit B: Discharge and Swivel Joints .........................................................................................................5-7
Discharge Joints .....................................................................................................................................5-7
Swivel Joints ..........................................................................................................................................5-7
Additional References ............................................................................................................................5-8
Unit B Quiz ..........................................................................................................................................5-10
®
Unit C: Lo Torc Plug Valves ................................................................................................................5-11
Construction of the Lo Torc® Plug Valve ...........................................................................................5-11
®
Maintenance of the Lo Torc Plug Valves..........................................................................................5-13
Valve Adjustment at Zero Pressure......................................................................................................5-14
Pressure Testing ...................................................................................................................................5-14
Additional References ..........................................................................................................................5-14
Unit C Quiz ..........................................................................................................................................5-15
Unit D: Check Valves ..............................................................................................................................5-16
Check Valve Installation ......................................................................................................................5-16
Check Valve Types ..............................................................................................................................5-16
Unit D Quiz ..........................................................................................................................................5-17
Unit E: Shur-Shot Ball Injector and Ball Sealers.....................................................................................5-18
Perfpac Balls ........................................................................................................................................5-18
BioBalls................................................................................................................................................5-18
Additional References ..........................................................................................................................5-20
Unit E Quiz...........................................................................................................................................5-21
Self Check Test for Section 5 ..................................................................................................................5-22
Answer Key .............................................................................................................................................5-24

© 2005, Halliburton 5•1 Stimulation I

 Manifolding and End Connections

Use for Section notes…

© 2005, Halliburton 5•2 Stimulation I

 Manifolding and End Connections

Introduction
Manifold components used by Halliburton • Check Valves
Services in stimulation work include plumbing
required to join fluid passages of various • Shur ShotTM Ball Injector
pumping equipment together and conduct fluid • Safety Restraint Equipment
to the well. The manifold components discussed
in this section are for high-pressure operations
(6000 psi or above). Learning Objectives

Upon completion of this section, you will be

Topic Areas familiar with:

The section units are: • placement of manifold equipment

• Manifolding and End Connections • functions of the equipment

• Discharge and Swivel Joints • maintenance of equipment

• Lo Torc® Plug Valves

© 2005, Halliburton 5•3 Stimulation I

 Manifolding and End Connections

Unit A: Manifolding and End Connections

Correct selection and use of manifolding are pumped. The types of materials (corrosives,
systems and components supplied to Halliburton abrasives, etc.) are normally predetermined by
field operations are critical to the success of the customer or by Halliburton personnel in
stimulation jobs. This unit discusses important order to obtain specific results from the well. On
points about the most efficient use of the other hand, the user of discharge lines can
manifolding. help minimize erosion from abrasive fluids by
“rigging up” properly. The size and number of
Pressure and type of service play important roles lines “rigged up” should be adequate to keep
in the selection of pipe connections. All abrasive fluid velocities from exceeding 35 feet
manifold components used in well stimulation per second. A convenient rule of thumb to
have something in common – they are all determine the flow rate in barrels per minute that
equipped with end connections. Also discussed corresponds to a fluid velocity of 35 feet per
in this unit are the two end connections most second is:
frequently used by Halliburton.
Max Flow Rate (BPM) = 2 × ID × ID
where ID = Inside Diameter of the dishcharge lines.
Manifolding For example,

Manifolding systems and components supplied Flow rate for a 2 inch discharge line:
to Halliburton’s field operations are designed to Max Flow Rate (BPM) = 2 × 2in × 2in = 8 BPM
convey abrasive fluids up to 35 feet per second.
Since abrasive fluid velocities above 35 feet per
second accelerate erosion, they should be Flow rate for a 3 inch discharge line:
avoided whenever possible. This will help to Max Flow Rate (BPM) = 2 × 3in × 3in = 18 BPM
obtain maximum service life from manifolding
equipment. Standard manifold components are
designed to handle moderately corrosive Example:
materials. Special manifolding is required to
Which of the following valves would be the
convey severe corrosives such as sour gas.
desired choice for handling a sand-laden fluid at:
Severe acid service (frequent pumping of large
volumes of acid on a regular basis, especially if 11,500 psi and 15 BPM?
the acid is heated and/or poorly inhibited) also
requires that special manifold components be A. 11.5153 Lo Torc® plug valve - 2.56
used. inches inside diameter, 20,000 psi
working pressure.
Manifold components are normally designed for
standard service only. Special service B. 11.5028 Lo Torc® plug valve - 3.06
components are designated by Catalog Part inches inside diameter, 15,000 psi
Number, Catalog Description, and/or by working pressure.
permanent markings on the components in A = 2.56in × 2.56in × 2 = 13.1072 BPM
question. Standard service manifolding should
never be used in sour gas service. Velocity will be too high.
Corrosion, erosion or “wash out” usually B = 3.06in × 3.06in × 2 = 18.7272 BPM
determine the lives of most manifold
components. Operators using the manifolding The 11.5028 Lo Torc® can be used for
seldom have strict control over which materials the job.

© 2005, Halliburton 5•4 Stimulation I

 Manifolding and End Connections

End Connections Big Inch® Connections

Designed by Halliburton, Big Inch®

Wing Unions Connections use a hub with a clamp
arrangement combined with elastomeric seals
The most common types of connections used in backed up by metallic rings. Big Inch®
the oil field are Wing Unions. They are light- connections are normally used for severe
weight, rugged and dependable with no loose applications involving the following pumping
parts. A hammer is the only tool used to “make” circumstances:
or “break” wing unions on a job.
• hazardous materials
Other key points about wing unions are:
• extreme pressures
• The pressure rating is marked on the wing
nut and/or sub. • severe corrosives
• There is a wide span of sizes and pressure • extremely long job durations
ranges available. • high proppant concentrations
• They may be attached to tubing by pipe • high material volumes
threads, special tubing threads, or by
closely controlled machine welding Even though Big Inch® connections are heavy
(inertia welding, which is generally the and expensive, they are very reliable. The
most reliable method). rugged construction uses mostly static seals for
added reliability. This gives long service life
• Plug valves, swivels, tees, crosses, ells,
with low maintenance. Most types of manifold
blanks, check valves, ball injectors,
straight joints, manifolds, frac heads, flow components are available with Big Inch®
meters, densometers, and pressure connections.
monitoring devices are available with
integral, “hammer” union connections.

Figure 5.1 – 2” Wing

Figure 5.2 – Big Inch

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 Manifolding and End Connections

Unit A Quiz

Fill in the blanks with one or more words to check your progress in Unit A.
1. Erosion increases when fluid velocity of abrasive fluids exceeds _______________ feet per
second.

2. Special manifolding is required when severe ____________________ such as sour gas or large
volumes of ____________________ are frequently pumped.

3. Special service components are designated by ____________________ _______________

____________________, ____________________ ____________________, and/or
____________________ ____________________ on the components.

4. Standard service manifolding should never be used in ____________________

____________________ service.

5. Users of manifolding can help minimize erosion from abrasive fluids by ____________________
_____________________ properly.

6. Maximum flow rate in BPM = (2) × ____________________ _____________________.

7. Maximum recommended flow rate through a 4 inch ID line is ________________ BPM.

8. List four of the applications for Big Inch® end connections:

_____________________________________________________

_____________________________________________________

_____________________________________________________

_____________________________________________________

Now, look up the suggested answers in the Answer Key.

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Unit B: Discharge and Swivel Joints

Some type of piping system is necessary to Answer:
connect pumping equipment to the well. This
2.87 in. × 2.87 in. × 2 = 16.47 BPM through
unit discusses two major parts of any pipe laid to
one line
a wellhead:
40 BPM ÷ 16.47 BPM = 2.42 or 3 lines will be
• discharge joints
required
• swivel joints

Swivel Joints
Discharge Joints
Swivel Styles
Straight discharge joints (Figure 5.3) are used to Swivel joints are used to change direction with
conduct stimulation fluids from high-pressure discharge lines, provide flexibility for hooking
pumps to the well head. The wide range of flow up and for pump movement, and for attaching
rates and treating pressures makes it necessary to lines to the well head. When properly installed
have a large selection of joint size, pressure in the discharge line, seven swivel joints will
rating, and end connections available. provide complete flexibility in the line. There
are two basic designs for swivel joints—cast and
long sweep. Swivel joints may be assembled
with one, two, three or more swivels per unit.
Cast style swivel joints change direction in sharp
90° turns and are usually rated at 6000 psi
working pressure. The sharp angle of change
contributes to erosion from abrasive fluids. This
style joint requires regular disassembly and
inspection for excessive wear.
Figure 5.3 - Straight Discharge Joint—
15,000 psi with 1502 Wing Union End The long sweep swivel joints are usually rated at
Connections 15,000 psi working pressure. However, some
designs are rated at 20,000 psi. Their design
reduces the amount of erosion resulting from
Use the rule of thumb given earlier when fluid velocity and abrasion. When calculating
determining the number of discharge lines to lay the pump rate through swivel joints, limit the
from the pumping units to the well head. The fluid velocity to 35 feet per second.
following is an example for determining Swivel joints are expensive. Proper and frequent
discharge lines. maintenance will extend the lives of swivel
A three inch OD discharge line is being used to joints. If a swivel joint leaks, immediately take it
treat a well. The ID of the joints is 2.87 inches, out of service until repairs can be made.
and pressure rating is 6000 psi. An injection rate Lubricate swivel joints regularly with a hand
of 40 BPM is required for the job. How many held grease gun. A power grease gun may build
discharge lines should be installed? up excess pressure and cause failure of the
grease seal, which reduces the life of the swivel
joint.

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 Manifolding and End Connections

Additional References

Halliburton Services Surface Manifold

Equipment Catalog, P.N. 439.01699
Halliburton Services Personnel Training Video
“Care and Maintenance of Swivel Joints”—18
minutes.

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 Manifolding and End Connections

Chicksan Continental
Long Sweep Cast
Style EMSCO Style

Style 10 Style 7

Style 20 Style 1

Style 30 Style 2

Style 40 Style 3

Style 50 Style 5

Style 60 Style 4

Style 80 Style 8

Style 100 __________

Table 5.1 -

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Unit B Quiz

Fill in the blanks with one or more words to check your progress in Unit B.

1. Straight discharge joints are used to conduct stimulation fluids from ____________________
_______________________ ______________________ to the well head.

2. The discharge joints are subject to ____________________ from abrasive fluids and must be
inspected at regular intervals.

3. Two basic designs for swivel joints are ____________________ and ____________________
____________________.

4. Swivel joints may be manufactured with one, ____________________,

_____________________ or ______________________ swivels per unit.

5. _____________________ swivel joints are required in a discharge line to have complete

flexibility.

6. Swivel joints should be lubricated using a __________________ __________________ grease

gun.

Now, look up the suggested answers in the Answer Key.

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 Manifolding and End Connections

Unit C: Lo Torc® Plug Valves

The Lo Torc® plug valve is manufactured by

Halliburton for a wide variety of applications. Grease Fi tting
O-ring Seal
The Lo Torc® plug valve is used in all of the Body
services Halliburton provides or wherever Plug
or Core
manifolding and controlling extremely high
pressures is necessary in flow lines.
Com mon
End
It is a quick opening valve that has several Connection

advantages in oil field operations:

• light weight construction Valve Insert

• simple maintenance Packing Ring

• fast sure ease of operation

Adjusting Nut

• reliability Figure 5.4 – Cutaway View of a 2” Lo

Torc® Plug Valve
This unit discusses the component parts of the
Lo Torc® plug valve (Figure 5.4) and a method
for disassembling and reassembling the valve.
Pay attention to pressure requirements when
selecting end connections for the Lo Torc® plug
valve. The Big Inch® connection is
Construction of the Lo Torc® recommended for high-pressure applications.
Plug Valve Two-inch threaded pipe ends normally work
very well for pressure ranges below 10,000 psi.
The body1 and adjusting nut5 of the Lo Torc® Inspect end connections frequently.
plug valve (refer to Figure 5.5) are heat-treated The plug or core2 is a balanced cylindrical
alloy steel forgings. This process allows: design that eliminates loading forces on the
• greater dependability stem. There is no jamming or wedging induced
by pressure acting against the sealing areas as
• minimum weight with a tapered plug. The plug is made from
• maximum strength stainless steel to resist normal corrosion and the
identical stem seal is further pressure balanced
A special coating of the steel parts is applied for by identical stem seals at each end. A plug made
corrosion protection. Common end connections4 from a nickel alloy is recommended for severely
provided on the body are threaded, ring-joint corrosive applications such as acid service.
flanges, or wing unions. Flanged connections are
made to ANSI and/or API dimensional The valve inserts3 are tapered on the OD to
standards. Wing unions are the most common match the body cavity while the inner surfaces
types of end connection. However, Big Inch® are precision ground to exactly the same
hubs and other custom end connections are diameter as the plug. These inserts are machined
available. with a raised surface surrounding the O-ring
groove. This base is the only portion of the
insert that contacts the valve body and serves as
the bearing area of each insert. This
considerably reduces the overall bearing area on

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 Manifolding and End Connections

the plug. Therefore, torque requirements to inserts are used in other valves and provide
operate the valve are reduced. The inserts are excellent corrosion resistance.
parted into identical halves and should remain
A second type of insert is Teflon-lined for gas
together as a matched set when the inserts in the
service where non-lubricated valves are desired.
valve are replaced.
This insert is equipped with an inner liner of
reinforced Teflon. The Teflon completely covers
the entire inner surface of each insert and is
bonded to it. The lubricating action of the Teflon
liner furnishes adequate lubrication for valves in
both gas and fluid applications. These inserts are
limited to a maximum working pressure of 5000
psi and are not recommended for abrasives of
any type.
The plug and inserts are free to “float”
downstream to compensate for temporary body
deflection. As pressure is increased, the seal
between plug and downstream insert half is
made more effective. Since the raised surface
surrounding the O-ring groove is under direct
load, the operating torque does not become
excessive. This is not the case with most valves
where the entire plug surface contacts the body
and is subjected to frictional forces. These forces
are also reduced by the design of the stationary
O-ring seal6 between inserts and body cavity.
Pressure acts upon the section of the insert
sealed by the O-ring and transmits a force
against the plug. Since the seal area is smaller
than the bearing area, this force is considerably
less than similar forces encountered in valves
that don’t have this feature.
O-ring seals for standard service are 90
durometer Nitrile O-rings. They are recessed
into grooves in each insert and below the
Figure 5.5 - Exploded View of a 2” Lo Torc® adjusting nut threads. Teflon or fluoroelastomer
Plug Valve O-rings are available for corrosive applications
and extreme temperatures.
The plug stem at top and bottom of the plug are
Two types of inserts are available. One type is sealed by specially designed packing rings7
an all metal insert recommended for general made of Nitrile rubber bonded to brass
fluid service applications. The sealing effect is reinforcing washers. For applications involving
derived from the metal-to-metal contact between extreme temperatures or the handling of highly
insert and plug. A special lubricant is used to corrosive media, a Teflon seal ring energized by
reduce the effort required to operate the plug. an inconel spring can be provided. Depending
Three materials are used for the all metal insert: upon applications and working pressures,
(1) Ductile iron type inserts are used for general maximum service temperatures are 250°F for
service, including cementing. (2) Nickel plated Nitrile and 300°F for Teflon.
steel inserts are used in some valves for
corrosion protection. (3) Aluminum-bronze

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 Manifolding and End Connections

® • Install plug stem seals9-10 in recesses in the

Maintenance of the Lo Torc
top of the valve body and in the adjusting
Plug Valves nut. The seal-backing ring is to be
positioned away from pressure.
The Lo Torc® plug valve has the advantage of
being simple to operate. It can be serviced or • On all valves, coat the mating surfaces of
repaired without removing the valve body from the plug and inserts with plug valve
its installed position. No specific frequency of lubricant. On lubricated valves, fill spaces
maintenance can be recommended due to inside the body with the same lubricant (Part
varying applications. However, frequent No. 70.31058).
inspection is necessary to help extend the life of • Install the lower end of the plug through the
the valve’s parts. adjusting nut and push down to the shoulder.
Instructions for disassembling and reassembling Use capscrews, flat washer and lock washer
a Lo Torc® plug valve appear below. The to secure the plug to the adjusting nut.
numbers refer to parts found in Figure 5.4: Tighten the cap screw.
• Remove the wrench15 or handle adapter2, • Check for proper positioning of the insert
with stop collars14. retaining pins13 inside the valve body.
• Loosen adjusting nut7 with operating bar or • Place inserts on the adjusting nut around the
hex wrench. Remove adjusting nut, plug12 plug, aligning flow holes in the inserts with
and inserts10. If necessary, place a wood the hole through the plug.
block on top of the plug stem and tap • Place plug, inserts and adjusting nut into the
downward. valve body with insert retaining pins keying
• At this point, the valve body1 should be into slots in the inserts.
inspected for any interior erosion or pitting. • Tighten adjusting nut into the body until the
O-rings11 on the inserts should be replaced operating torque of the plug is within the
if needed. The O-ring8 sealing the adjusting prescribed range given in the Valve
nut should also be replaced if worn. It is Adjustment Chart. Rotate or cycle the plug
usually necessary to replace the plug stem while tightening to distribute excess
packing9-10 at the top and bottom of the lubricant.
plug.
• Install the stop collars and handle adapter
• If the valve shows signs of leakage, or if (or wrench) on top of the valve. Be sure the
inserts show any excessive wear or pitting, flow indicators are in line with the slot in the
replace inserts with standard parts. The top stem of the plug.
inserts are paired so change both at the same
time. DO NOT mix with other inserts. • Lubricate the valve through the grease
fitting3 on top of the valve body to allow
• On lubricated valves, wipe all old lubricant total filling of the void space inside the
from inside valve body. valve. NOTE: It is also helpful to cycle the
• To reassemble, install O-rings in recesses of plug while doing this.
inserts and adjusting nut groove.

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 Manifolding and End Connections

Pressure Testing
Valve Adjustment at Zero
Pressure When repair has been made to a Lo Torc® plug
valve, it should be pressure tested using water as
the fluid for the test. To pressure test using a
To maintain tight sealing under pressure, the Lo
pump truck:
Torc® plug valve must be properly adjusted.
Tightening or loosening the adjusting nut to 1. Place the Lo Torc® valve in the open
produce the following torque on the plug: position and install in the discharge line.
2. Install a needle valve down-stream of the
Valve Adjustment and Torque
plug valve.
Valve Type (Dia.) Torque (ft/lb)
3. With the needle valve in the open position,
1” Valves 30-40 ft-lb pump water through the valve until all air
1 1/2” Valves 30-40 ft-lb is out of the system.
2” Valves 40-60 ft-lb 4. Close the needle valve and pressure test
2 ½” Valves 50-60 ft-lb the body of the Lo Torc® plug valve to
working pressure plus 1000 psi.
3” Valves 60-70 ft-lb
4” Valves 70-80 ft-lb 5. Release the pressure.
Table 5.2 6. Close the valve.
The valve can now be tested to working pressure
of the valve. This test will determine the valve’s
NOTE: Valves with Teflon-lined inserts should ability to hold fluid pressure. You may notice a
be adjusted to about two-thirds the above drip of water coming from the valve at 10 to 15
figures. second intervals. This is acceptable for the
Extremely high working pressures may require valve.
higher torque to properly seal the valve. If so, After completing the test, remove the valve from
this higher torque adjustment should be the line and re-install it from the opposite side.
maintained by checking the adjusting nut at The same test procedure should be repeated for
regular intervals. the valve since the valve seals on the
CAUTION: The fact that a valve has never downstream side. The sealing ability is
leaked in service does not necessarily mean that confirmed for one direction only during each
the inserts do not need replacement. They may test.
wash out and erode the valve body before
leakage is noted. A planned program of
maintenance at specific intervals is the key to Additional References
keeping down time and repair costs to a
minimum. Halliburton Services Personnel Training Video
“The Lo Torc® Plug Valve” 27 minutes.
Halliburton Services, Lo Torc® Plug Valve,
Catalog G, S-8093.

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 Manifolding and End Connections

Unit C Quiz

Fill in the blanks with one or more words to check your progress in Unit C.
1. The Lo Torc® plug valve is used to control ________________ ________________ in
_____________ ________________.

2. The ________________ ________________ connection is recommended for high pressure

applications.

3. While performing maintenance of the Lo Torc® plug valve, replace the ____________________
if the valve has shown any signs of leaking.

4. To maintain a tight seal under pressure, the plug valve’s ________________ ________________
must be tightened or loosened so that the plug has the proper _________________ at zero
pressure.

5. The inserts are parted into identical halves, which should remain as a ________________
________________.

Now, look up the suggested answers in the Answer Key.

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 Manifolding and End Connections

Unit D: Check Valves

Fluid flow and pressure involved in a
stimulation treatment can be hazardous to
personnel and equipment. Check valves are used
to minimize those potential dangers. These
valves have applications at many points in the
flow line. Some of the most important
applications are discussed in this unit.

Check Valve Installation

Check valves used as manifolding components

are one way valves that control direction of fluid
flow (Figure 5.6). By controlling direction of
flow, the check valve provides protection to
equipment and personnel, which is a prime
consideration.
When attaching lines to a well, and more
particularly those wells that have the ability to
flow, install a check valve as close to the
wellhead as practical. This will prevent the well Figure 5.6 - Check Valve Configurations
from flowing out of control in the event
discharge lines, pumps or other manifold
components are damaged. When installing a check valve, install a “bleeder
tee” and a stop between the check valve and
Be careful when installing a check valve in the
master valve. This allows you to relieve trapped
discharge line near the wellhead when treating
pressure between the check valve and master
with energized fluids such as nitrogen and
valve. Failure to do this results in having to take
carbon dioxide foam. Tremendous amounts of
the line apart under pressure.
energy are stored in a well when using these gas
systems. It is critical that this energy be
contained if there is a break in the treating lines. Check Valve Types
Check valves may be placed in stream to protect
various pieces of equipment from exposure to Check valves have two basic configurations. The
corrosive fluids or invasion by gas. An example first, the dart type, has a spring-loaded poppet
would be installing check valves ahead of the valve. Fluid causes the poppet valve to move off
nitrogen pumping equipment in order to protect of its seat to allow the fluid to pass in one
the stainless steel pumps and other components direction. If direction of flow is reversed, the
of the nitrogen pumping units. poppet valve will close and shut off flow. Most
stimulation fluids and proppants can be pumped
and placed through the poppet type check valve.
The second is a flapper-type of check valve very
much like the dart type. The main difference is
that the valve has a flapper, instead of a dart,

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 Manifolding and End Connections

that provides a wider opening for fluid passage. importance, a good maintenance program should
The opening allows Perfpac balls to be carried in be established. Since check valves are designed
the flow stream without plugging the line. to meet different working pressure requirements,
a wide choice of end connections is available for
Check valves are an integral part of frac heads
compatibility with other manifold components.
and ground manifolds. Because of their

Unit D Quiz

Fill in the blanks with one or more words to check your progress in Unit D.
1. Check valves are ____________________ ____________________ valves.

2. Check valves control ____________________ of fluid flow.

3. Check valves should be installed as ____________________ to the master valve as practical.

4. Check valves provide ____________________ for personnel and equipment.

5. There are two basic types of check valves. They are the ____________________ and
____________________.

Now, look up the suggested answers in the Answer Key.

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 Manifolding and End Connections

Unit E: Shur-Shot Ball Injector and Ball Sealers

Mechanical diverters are frequently needed to recovered mechanically. Perfpac balls can be
help clean up a well for evaluation. used with all fracturing or acidizing methods.
Design considerations include:
ƒ the volume of treating fluid to be
pumped
ƒ the pump rate
ƒ the number of perforations
ƒ the number of balls to be dropped
ƒ the fluid density
ƒ the ball density
When balls are used, an appropriate pump rate
must be maintained. If the pump rate is too slow,
and the ball density is greater than the fluid
density, the balls will fall faster than the fluid
can be displaced. If the ball density is less than
the fluid density, then, at a low pump rate, the
Figure 5.7 – Ball out job balls could float to the surface. After the
treatment, the balls either float to the surface or
fall into the rathole. If the balls float to the
The most widely used type are solid rubber- surface, they should be removed from the fluid
coated balls (Perfpac balls) and the newer stream before they hit the flowback valve or
BioBalls. choke. If the well has to be swabbed, the balls
should be allowed to fall to the bottom to
prevent sticking the swabbing tools. Recovering
Perfpac Balls stuck swabbing tools could be very expensive.

Perfpac balls are widely used in acidizing as

well as in fracturing. In fact, many wells are BioBalls
“balled out” with acid to establish that all
perforations are open and to determine what BioBalls are made by a company called Santrol.
productivity can be expected. This is done prior BioBalls are aqueous-soluble, biodegradable ball
to any other treatments. sealers. These hard, resilient balls are available
in two versions. The MR (mid-range) BioBall is
Perfpac balls divert fluid flow and pressure from
made for use in lower temperatures, whereas the
one perforation to another. Perfpac balls are
HR (high-range) BioBalls are made for use in
transported in the treating fluid to those
higher temperatures.
perforations taking fluid, seating and sealing off
the perforation. This action diverts the flow and BioBalls can be a replacement for conventional
pressure of the treating fluid to another ball sealers. They are made of a collagen
perforation so that it will also take fluid. When material (an organic, fibrous protein) that
pumping stops and/or the flow reverses, the balls dissolves in water-based fluids. These ball
are disengaged from the perforations; they then sealers are not oil-soluble. They will only
either fall to the bottom of the well or are dissolve in water-based fluids. They have been

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 Manifolding and End Connections

used for diversion of both acidizing and ƒ • Coiled tubing impediments are
fracturing treatments, including those with gases eliminated.
and foam. When used appropriately, they will
ƒ • Perforation diversion in low-pressure
effectively disappear from the wellbore and
wells can be achieved.
perforations. Because they do not have to be
drilled out or removed, BioBalls offer the ƒ • Injection well perforation diversion
following unique advantages over conventional can be attained.
ball sealers: The HR BioBalls are very stable at low
ƒ • Scraper runs can be eliminated. temperatures, and should not be used below
approximately 185°F because they do not
ƒ • Retrievable tools can be used below
dissolve at those temperatures and would require
perforations.
removal by conventional means. The HR ball
ƒ • Drillable bridge plugs can be used has a more resilient compound as an outer layer,
below perforations. with an inner core of another, non-dissolving
material. It is a harder ball than the MR at room
ƒ • The use of ball catchers is
temperature.
unnecessary.

Figure 5.8 - Shur Shot™ Ball Injectors

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 Manifolding and End Connections

The Shur Shot™ ball injector is presently being Perfpac balls from 5/8 inch OD to 1 ¼ inch OD
used to inject balls at a predetermined rate may be injected from the Shur Shot™ ball
(Figure 5.7). It provides for positive mechanical injector. All injectors are equipped to inject ¾
injection of Perfpac balls against pressure and inch or 7/8 inch diameter balls. Additional
into viscous fluids. By using positive components can be furnished to inject 5/8 inch,
mechanical injection, the Shur Shot™ ball 15/16 inch, 1 inch and 1 ¼ inch balls (Table
injector does not depend on gravity and is not 5.2). The ball injector may be operated manually
affected by pressure. or by remote control. It can range from one ball
to as many as 250 from a single unit.
Screw-Sleeve Combinations Required for Injecting Various Ball Sizes
Ball Dia. Short Parts Long Parts
(In.) (21.37 Long) (42.37 Long)
Screw Sleeve Screw Sleeve
5/8 281.86833 281.86802 --- ---
¾ 281.86801 281.86802 281.86861 281.86862
7/8 281.86801 281.86802 281.86861 281.86862
15/16 281.86829 281.86802 --- ---
1 281.86829 281.86802 --- ---
1¼ 281.86826 281.86827 281.86871 281.86872
Table 5.3

Additional References
Confidential Field Bulletin No. 8-11 (Chemical
Tech Data Sheet F-3136 Service Manual)
Surface Manifold Equipment Manual No. Surface Manifold Equipment Manual No.
439.01699 439.01699

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 Manifold Equipment

Unit E Quiz

Fill in the blanks with one or more words to check your progress in Unit E.
1. Perfpac balls are solid, ___________________ ___________________ balls.

2. Bioballs are made from ___________________, an organic, fibrous protein.

3. The Shur Shot™ ball injector provides ____________________ mechanical injection of Perfpac
ball sealers.

4. The Shur Shot™ ball injector does not depend on ____________________ and is not affected by
pressure.

5. Perfpac balls from 5/8 inch to __________ inch OD may be injected from the Shur Shot™ ball
injector.

6. The ball injector may be operated ____________________ or by ____________________

__________________.

7. Ball injection can range from ____________________ ball to as many as

____________________ from a single unit.

Now, look up the suggested answers in the Answer Key.

© 2005, Halliburton 5 • 21 Stimulation I

 Manifold Equipment

Self Check Test for Section 5

Mark the single best answer to the following questions.
1. What is the maximum rate that should be pumped through a 3” line.
_____ A) 6
_____ B) 12
_____ C) 18
_____ D) 24
2. To achieve complete flexibility in a line, how many swivel joints must be used?
_____ A) seven
_____ B) three
_____ C) twelve
_____ D) eight.
3. How do you tell if there is excessive wear in cast style swivel joints?
_____ A) check the calendar
_____ B) check for leaks
_____ C) check for rust, periodically
_____ D) disassemble and inspect.
4. What can be done to extend the life of swivel joints?
_____ A) lubricate with a power grease gun
_____ B) lubricate yearly with any form of grease
_____ C) lubricate regularly with a hand held grease gun
_____ C) never lubricate, life cannot be extended.
5. What are used to direct and control the flow of fluids?
_____ A) joints
_____ B) valves
_____ C) switches
_____ D) cranks
6. Which of these valves is a quick opening valve for controlling sustained high pressures in oil field
operations?
_____ A) check valves
_____ B) Shur Shot™ valves
_____ C) swivel valves

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 Manifold Equipment

_____ D) Lo Torc® Plug valves

7. What is the recommended in-service inspection schedule for the Lo Torc® Valve?
_____ A) inspect every 3 weeks
_____ B) inspect once a week
_____ C) inspect daily
_____ D) no specific frequency of inspection.
8. After a repair has been made to a Lo Torc® plug valve, what should the next step be?
_____ A) pressure test
_____ B) put back to work
_____ C) lubricate
_____ D) immerse in hot water.
9. Why are check valves such an integral part of frac heads and ground manifolds?
_____ A) They protect from erosion.
_____ B) They protect the well.
_____ C) They protect personnel and equipment.
_____ D) They are only a minor part.
10. How can the Shur Shot™ ball injector be controlled?
_____ A) manually
_____ B) remote control
_____ C) no control necessary
_____ D) manually or by remote control.
Now, look up the suggested answers in the Answer Key.

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 Manifold Equipment

Answer Key
Items from Unit A Quiz
1. 35
2. corrosives / acid
3. Catalog part # / catalog description / permanent markings
4. Sour gas
5. Rigging Up
6. Inside diameter × inside diameter
7. 32 2 × 4 × 4 = 32
8. Hazardous materials, extreme pressure, severe corrosives, extremely long job durations, high
proppant concentrations, high material volumes

Items from Unit B Quiz

1. high pressure pumps
2. erosion
3. cast / long sweep
4. two, three, more
5. seven
6. hand held

Items from Unit C Quiz

1. high pressure / flow lines
2. Big Inch
3. inserts
4. adjusting nut / torque
5. matched setremain

Items from Unit D Quiz

1. One way
2. direction
3. close
4. protection
5. poppet / flapper

© 2005, Halliburton 5 • 24 Stimulation I

 Manifold Equipment

Items from Unit E Quiz

1. rubber coated
2. CollagenPositive
3. Positive
4. Gravity
5. 1- ¼
6. Manually / remote control
7. one / 250

Self-Check Test
1. C
2. A
3. D
4. C
5. B
6. D
7. D
8. A
9. C
10. D

© 2005, Halliburton 5 • 25 Stimulation I

Section 6

Fracturing Fluids and Materials

Table of Contents
Fracturing Fluids and Materials .................................................................................................................6-3
Introduction ............................................................................................................................................6-3
Topic Areas ............................................................................................................................................6-3
Learning Objectives ...............................................................................................................................6-3
Unit A: pH Control Agents ........................................................................................................................6-3
Unit A Quiz ............................................................................................................................................6-4
Unit B: Clay Control..................................................................................................................................6-5
Clay Characteristics................................................................................................................................6-5
Clay Control Additives...........................................................................................................................6-5
Unit B Quiz ............................................................................................................................................6-7
Unit C: Fluid Loss Control Additives ........................................................................................................6-8
Fluid Loss Approaches...........................................................................................................................6-8
Fluid Loss Control Additives .................................................................................................................6-8
Unit C Quiz ..........................................................................................................................................6-10
Unit D: Surfactants ..................................................................................................................................6-11
Surfactant Definition ............................................................................................................................6-11
Surfactant Usage ..................................................................................................................................6-11
Surfactant Composition........................................................................................................................6-12
Surfactant Mechanisms ........................................................................................................................6-13
Blending of Surfactants ........................................................................................................................6-14
Summary ..............................................................................................................................................6-14
Unit D Quiz: Surfactants ......................................................................................................................6-15
Unit E: Gelling Agents.............................................................................................................................6-16
Water-Based Gelling Agents................................................................................................................6-16
Oil Gelling Agents ...............................................................................................................................6-18
Additional References ..........................................................................................................................6-20
Unit E Quiz: Gelling Agents ................................................................................................................6-21
Unit F: Complexors/Crosslinkers.............................................................................................................6-22
Unit F Quiz...........................................................................................................................................6-25
Unit G: Breakers/Stabilizers ....................................................................................................................6-26
Breakers................................................................................................................................................6-26
Breaker Types ......................................................................................................................................6-26
Enzyme Breakers..................................................................................................................................6-26
Oxidizing Breaker ................................................................................................................................6-27
Acid Breakers.......................................................................................................................................6-28
Gelled-Oil Breakers..............................................................................................................................6-30
Breaker Activators................................................................................................................................6-30

6•1 Stimulation I
© 2005, Halliburton
 Fracturing Fluids and Materials

Stabilizers .............................................................................................................................................6-30
Unit G Quiz ..........................................................................................................................................6-32
Unit H: Bactericides/Biocides..................................................................................................................6-33
Bacteria Conditions ..............................................................................................................................6-33
Bacteria Types......................................................................................................................................6-33
Bactericides ..........................................................................................................................................6-33
Additional References ..........................................................................................................................6-34
Unit H Quiz ..........................................................................................................................................6-35
Unit I: Conductivity Enhancers................................................................................................................6-36
SandwedgeXS ......................................................................................................................................6-36
Unit I Quiz............................................................................................................................................6-37
Answer Key .............................................................................................................................................6-38

© 2005, Halliburton 6•2 Stimulation I

 Fracturing Fluids and Materials

Fracturing Fluids and Materials

• pH control agents
Introduction • Clay control agents
• Fluid loss control additives
Fracturing chemicals are used to make up the
fluid systems for stimulation treatments. A great • Surfactants
number of fracturing fluid systems is available
• Gelling agents and friction reducers
to the petroleum industry. The selection of a
fracturing fluid depends upon the particular • Complexors and crosslinkers
formation to be treated and the tubular goods in
the well. Considerations in fluid selection are: • Breakers and stabilizers

• the formation rock properties • Bactericides

• the formation fluid properties • Conductivity Enhancers

• friction properties of the treating fluid

• fluid loss properties of the treating fluid
Learning Objectives
• proppant transport Upon completion of this section, you will be
familiar with:

Topic Areas • Classifications and usage for chemicals

blended into fracturing fluids
Chemical additives generally used in fracturing • Reactions of these chemicals
can be grouped into nine classifications. The
following sections will explain these types and • Actions that each chemical will have in a
their uses: formation

Unit A: pH Control Agents

Most aqueous based stimulation fluids contain a Acidic Neutral Basic
nominal amount of chemicals (common acids 0 7 14
and bases) for the sole purpose of obtaining the
proper fluid pH. These chemicals are referred to
as pH control agents or buffers. Table 6.1 - pH Scale

pH expresses the degree of acidity or basicity of

a solution. The pH scale extends from 0 to 14 The pH scale is useful in evaluating solutions
(Figure 6.1). A pH of 7 is neutral (neither acidic, which are slightly acidic or basic. A 0.1%
nor basic). An acidic solution will have a pH solution of HCL will have a pH of 1, while a 1%
value lower than 7. If it is basic (or alkaline) it solution of caustic soda (NaOH) will have a pH
will have a pH value above 7. of 14. The strength of higher concentrations of

© 2005, Halliburton 6•3 Stimulation I

 Fracturing Fluids and Materials

hydrochloric acid (HCL) or caustic are • sodium hydroxide.

expressed as percent rather than pH. Measuring
pH control agents used to adjust pH are listed
pH is done with narrow range pH paper or pH
along with their values:
meters.
STRONG ACID pH
The pH of a fluid is a significant factor in
stimulation treatments because it controls Hydrochloric Acid 0-2
variables such as crosslinker function, Hydrofloric Acid 0-2
temperature stability, iron control problems, WEAK ACID pH
polymer hydration, clay control, and gel break.
HYG-3 (Furmaric Acid) 3.5-4
Compatibility of stimulation fluids with the
formation is an important consideration since the FE-1A (Acetic Acid) 2-4
effect of fluid pH on clays and the resulting WEAK BASE pH
formation permeability can be significant. Clay
K-34 (Sodium Bicarbonate) 8.5
and shale formations are best protected in a low
pH environment. Rates at which gelling agents K-35 (Sodium Carbonate) 10.5
develop viscosity are a direct function of the pH STRONG BASE pH
of the liquid system. Adjusting the pH of the NaOH (Caustic Soda) 14
liquid system also controls bacteria. Commonly
used pH control additives include: Buffers are mixtures of acids and salts of these
acids and are resistant to pH change. By using a
• sodium bicarbonate buffer listed below, rather than an acid or base,
• fumaric acid the fluid pH can be maintained even though
contaminants from formation water or other
• acetic acid sources tend to try and change it.
• formic acid BUFFER pH

• sodium diacetate BA-2 1.5-3

BA-20 6-8.5
• monosodium phosphate
BA-40 / BA-40L 7-11
• sodium carbonate

Unit A Quiz

Fill in the blanks with one or more words to check your progress in Unit A.
1. Clay and shales can best be protected in a ____________________ pH environment.

2. pH is a means of expressing the degree of ____________________ or ____________________of a

solution.

3. On the pH scale, ____________ is neutral.

4. Buffers are mixtures of ____________________ and _____________________ of these

____________________.

5. To maintain a pH of 10, you could use ________________ as a buffer.

Now, look up the suggested answers in the Answer Key at the back of this section.

© 2005, Halliburton 6•4 Stimulation I

 Fracturing Fluids and Materials

Unit B: Clay Control

Clay Characteristics Clay Control Additives

Clays are present in almost all oil and gas

bearing formations and their presence can cause Acids and Buffers
many problems in the production of
hydrocarbons, particularly where stimulation As discussed in the previous unit, pH can be
processes are employed. The clay composition used to control formation clays. An acid or
and its location in the rock matrix can vary buffering agent can protect clays best at a pH
extensively, thus complicating control and range of 3 to 7.
treatment when clay minerals are present.
Where water-swelling clay is contacted by Potassium Chloride (KCL), Sodium
foreign water in the formation, an increase in Chloride (NaCl) and Clayfix (NH4Cl)
clay swelling can reduce the size of flow
channels and decrease the flow capacity of the The main method of minimizing clay damage
rock. In addition, any appreciable change in the through contact with fracturing fluids is by
swelling characteristic of the clay may cause adding a chemical that will not alter the natural
some of the clay to be detached from its original water retention characteristics of the clay.
position. Fine particles may be released which Cations, such as potassium, sodium and
can migrate with fluid flow, form bridges at flow ammonium, possess the proper ionic size for
restrictions in the formation, and thus decrease absorption onto clay platelets and are compatible
the effective permeability of the producing zone. with most water based fracturing fluid systems.
The clays most commonly found in The salts potassium chloride (KCL), sodium
hydrocarbon-producing formations are smectite, chloride (NaCl) and ammonium chloride
illite, mixed layer, kaolinite and chlorite. Clays (NH4Cl) are used to maintain the “status quo” of
have a negative charge on their surfaces. clays to minimize permeability damage. Recent
studies have indicated that for maximum clay
stability through ion exchange, 7% KCL, 6%
Clay Damage method* NaCl or 5% NH4Cl is needed.
Smectite Swelling
ClayFix II
Mixed Layer Swelling

Illite Migrating CLAYFIX II is a liquid replacement for the

Kaolinite Migrating
various salts used in aqueous fracturing
treatments. It offers an alternative to KCl, NaCl,
Chlorite Migrating and CLAYFIX (NH4Cl) as a temporary clay
* All clays swell to some degree, and they can all break protection additive.
loose and migrate. One of these two processes will usually
be dominant for any given clay. The primary application for CLAYFIX II is in
propped fracturing treatments. CLAYFIX II is
To minimize the possibility of clay crystals or not recommended for matrix treatments. The
packets of crystals breaking loose and migrating, additive can be added to the mixing water while
any water that may contact a clay-bearing batch mixing or it can be metered into the flow
formation should contain a chemical that will stream before the other ingredients are added.
not alter the natural water retention CLAYFIX II is compatible will all present LGC
characteristics of the clay. formulations.

© 2005, Halliburton 6•5 Stimulation I

 Fracturing Fluids and Materials

NOTE: CLAYFIX II cannot be premixed in their dislodgment or movement when exposed to

LGC concentrates. This additive also is not a very high rates of fluid flow. By substantially
substitute for permanent clay control additives, stabilizing mineral fine particles, solids
such as salts. production, and permeability impairment caused
by fines, migration may be greatly reduced. This
®
fines stabilization is long lasting.
Cla-Sta Compounds

The Cla-Sta® compounds are cationic polymers Hydrocarbons

or oligomers that may be used with fracturing
fluids and acids to stabilize clays. They are most One method to effectively control clay problems
effective if used in a “pre-pad” or thin fluid is to not allow the formation to come into
pumped before the main fracture treatment and contact with water. Oil-based fracturing fluids
become much less effective when blended with do not allow water to be introduced into the
other gelling agents. ClaSta Compounds can formation. Hydrocarbons such as diesel can be
even plug pore spaces if used above blended with water based fluids to control leak
recommended concentrations. off into the fracture face and minimize water
contact.
Cla-Sta® XP
Foams and Emulsions
®
Cla-Sta XP clay stabilizing agent is designed to
be resistant to both acid and chemical removal. Foams and emulsions have excellent fluid loss
It is intended for use in formations with properties resulting in the reduction of water
permeability of 30 millidarcies (mD) or less but contact to the natural permeability of the
is not limited to that permeability. Cla-Sta® XP formation. An emulsion is a suspension of small
is an oligomer which provides clay and fines globules of one liquid in a second liquid with
control in most fracturing, acidizing, and gravel- which the first will not mix, like oil and water.
pack operations and is preferred over other Cla- Foam is a suspension of gas bubbles inside a
Sta products for formations with permeability liquid, like shaving cream. Foams and emulsions
less than 30 millidarcies. Cla-Sta® XP is also reduce the total water required to formulate
compatible with many aqueous stimulation a fracturing fluid.
fluids and can be batch mixed into the base fluid
or continuously mixed at the blender. Cla-Sta® Methanol (Methyl Alcohol)
XP is not a substitute for salts, such as KCl or
NaCl and will not provide the immediate clay The addition of methanol to a fracturing fluid
protection needed during treatment. reduces the fluid’s surface tension, thus reducing
the amount of water retained by the formation. It
also absorbs moisture on clay particles and helps
Cla-Sta® FS
protect the clay from the swelling caused by
water base fluids. Both of these result in faster
Cla-Sta® FS mineral fines and clay stabilizing cleanup and retained permeability.
additive is a new polymer designed to stabilize
fines commonly produced from a variety of
formations. Cla-Sta® FS effectively stabilizes
mineral fines that do not respond to treatment
from conventional clay stabilizers. It is readily
adsorbed on the formation surfaces, reducing

© 2005, Halliburton 6•6 Stimulation I

 Fracturing Fluids and Materials

Unit B Quiz

Fill in the blanks with one or more words to check your progress in Unit B.
1. Clays are present in ________________ _______________ oil and gas bearing formations.

2. Clay swelling can reduce the size of ____________________ channels.

3. Released fine particles can reduce effective ____________________.

4. pH ranges at which clays can best be protected are from __________ to ___________.

5. Maximum protection from clay swelling can be achieved when using a concentration of
__________% potassium chloride (KCL), __________% sodium chloride (NaCl) or __________%
ammonium chloride (NH4CL).

6. ClayFix II is a ____________________ clay protection additive.

7. Cla-Sta® materials are most effective when added to a ________________-_________________.

8. Cla-Sta® materials should not be used above recommended concentrations because excess material
can cause ____________________ of the pore spaces.

9. One method to effectively control clay problems is not to let the formation come into contact with
____________________.

10. Foams and emulsions reduce the total ____________________ required to formulate a fracturing
fluid.
Now, look up the suggested answers in the Answer Key at the back of this section.

© 2005, Halliburton 6•7 Stimulation I

 Fracturing Fluids and Materials

Unit C: Fluid Loss Control Additives

In any fracturing operation, a portion of the fluid
in contact with the formation penetrates into the WLC-4
pores and is lost as leak-off. The amount of fluid
lost in this way and the rate at which it is lost WLC-4 is a particulate fluid loss additive
has a pronounced effect on the shape of the developed for use with water-based gelled
fracture. Fluid loss reduces the size of the fracturing fluids at temperatures of 140° to
fracture as well as the fluid pressure inside the 350°F. WLC-4 may be used to control leakoff in
fracture. formations up to around 50 md or with 100-
mesh sand to help control leakoff in natural
fractures. At temperatures above 140°F, the
Fluid Loss Approaches additive degrades to low residue material in an
aqueous environment. The additive should be
Fluid loss additives are required to function applied at 20 to 50 lb/Mgal to aid leakoff
across a wide range of pore size distributions, control.
such as low, medium or high permeability
sections. Another requirement is that a large WLC-5
percentage of formation permeability needs to
be regained after being treated by the additive. WLC-5 is a fluid loss additive for use in aqueous
Different approaches have been taken to fluids. It contains an enzyme breaker that allows
establish fluid loss control. Traditionally, finely it to be more degradable than other starch
powdered solids have been used to control fluid additives such as Adomite Regain and WLC-4 at
loss. As the fluid moves into the pores of the low temperatures. WLC-4 does not contain this
formation, the fluid loss additives build up on enzyme breaker, and the enzyme breaker in
the fracture face and form a filter cake. This Adomite Regain is not as effective as the
reduces fluid loss. Some of the solids are inert breaker in WLC-5. Typical concentrations
while others go into solution and/or degrade. usually range from 20 to 50 lb/Mgal. WLC-5
Another approach to fluid loss control uses can be used at temperatures from 75° to 350°F
liquid additives that deposit droplets along the and permeabilities up to around 50 md.
fracture fact to control the loss of fluid. A major
advantage of this approach is that no solids that WLC-6
might impair productivity are left in the
formation or fracture. WLC-6 is a non-damaging fluid-loss additive
that helps in reducing gel filter cakes, especially
Fluid Loss Control Additives from borate-crosslinked fluids. Ground to an
appropriate particle size for fracturing, it
Water Based Fluids remains solid long enough to function as a fluid-
loss additive, then dissolves in the produced
water to ensure cleanup. As it dissolves, it
WAC-9
reduces the surface tension of the filter-cake
residue, helping to remove the filter cake and
WAC-9 is finely powdered sand. It is an improve fracture conductivity. WLC-6 is slowly
excellent fluid loss additive that can be used soluble in water and should be applied in low-to-
with water, acid or oil based fluids. However, moderate temperature wells up to 150°F. WLC-
since it is silica, it does not dissolve or degrade 6 can also be used with FracPac treatments in
over time.

© 2005, Halliburton 6•8 Stimulation I

 Fracturing Fluids and Materials

formations with up to 300 md of permeability. to 350°F. It can be used in formations up to 10

Use WLC-6 at concentrations of 25 to 50 md.
lb/Mgal of fracturing fluid.
Oil Based Fluids
WLC-7
There are a variety of fluid loss additives
WLC-7 fluid loss additive, an organic solid, is a applicable to oil-based fracturing fluids.
finely ground powder that dissolves slowly in
water as the water temperature rises; therefore, it WAC-9
can be cleaned up as water is produced from the
well. Because of its solubility, WLC-7 is non-
WAC-9 may be used for fluid loss control with
damaging. Laboratory tests indicate that WLC-7
any oil or water base fracturing fluids or acids.
helps reduce the potential damaging effects of
borate crosslinked gel filter cakes. WLC-7 can
be used in wells up to 180° F. It should be used K-34
in concentrations from 25 – 50 lb/Mgal of
fracturing fluid. Laboratory tests show that K-34 (Bicarbonate of Soda) is used in My-T-Oil
WLC-7 is beneficial up to 320 md. IV gels as both a breaker and a fluid loss control
additive. Laboratory tests are required to
Adomite®Aqua determine the concentrations used.

Adomite®Aqua is an older fluid-loss additive for 100 Mesh Sand

use in water-based fracturing fluids and was
originally developed by Continental Oil 100 Mesh Sand may be used in highly
Company. It is currently manufactured by Nalco permeable limestone or dolomite formations to
Chemical Company and is available from all control fluid loss. Pore spaces or “vugs” are
service companies. It is compatible with most usually large enough that the larger particle size
water base gelling agents and testing has shown found in 100 Mesh Sand is required to bridge the
some benefit in formations up to 200 md. openings. The amount of 100 Mesh Sand used
Although it is compatible with most stimulation for fluid loss control depends on formation rock
chemicals, including MY-T-OIL IV, it contains properties. 100 Mesh Sand can be used with
solids that are inert, meaning some residue will other fluid loss additives.
be left after treatment. Adomite®Aqua is not
recommended in hydrochloric acid solutions Foams and Emulsions
stronger than 3%. Normal concentrations used
are from 20-50 lb/Mgal. Gas bubbles present in foams and oil droplets
found in emulsions provide excellent fluid loss
Adomite Regain control. Normally, additional fluid loss control
additives are not required for foam or emulsion
Adomite Regain is a starch-based particulate applications in formations with permeability of
fluid loss additive used for water-based less than 1 md.
fracturing fluids. Designed with an internal
enzyme breaker system, it is active at low
temperatures. Concentrations used are normally
in the 20 to 50 lb/Mgal range, at temperatures up

© 2005, Halliburton 6•9 Stimulation I

 Fracturing Fluids and Materials

Unit C Quiz

Fill in the blanks with one or more words to check your progress in Unit C.
1. Fluid loss reduces the ____________________ of the fracture and the fluid ____________________
inside the fracture.

2. One requirement of fluid loss additives is that a high percentage of formation

____________________ be regained after being treated by the additive.

3. Finely powdered ____________________ have been used to control fluid loss.

4. ____________________ additives deposit droplets along the fracture face to control fluid loss.

5. An advantage of a liquid fluid loss additive is that no ____________________ are left in the
formation or fracture.

6. WAC-9 is a finely powdered ____________________.

7. WAC-9 can be used as a fluid loss additive with ____________________, ____________________

or ____________________ base fluids.

8. WLC-4 can be used at concentrations from __________ to __________ lb/Mgal of fracturing fluid.

9. WLC-5 contains an ____________________ ___________________ that allows it to be more

degradable than other starch additives.

10. 100 Mesh sand is typically used in ____________________ _____________________ limestone or

dolomite formations.

Now, look up the suggested answers in the Answer Key at the back of this section.

© 2005, Halliburton 6 • 10 Stimulation I

 Fracturing Fluids and Materials

Unit D: Surfactants
A major obstacle to oil production is the Figure 6.1 - Liquid with a high surface
infiltration of water into oil-bearing formations. tension
Water can reduce the sand’s effective
permeability to oil, resulting in a partial or
complete block. Many crude oils and waters Water has a strong surface tension and also
form emulsions that are more viscous than crude tends to form balls, especially in contact with
oil. Some emulsions have a fluid viscosity that is oily surfaces. Alcohol and the common liquid
several thousand times that of oil. Both blocking hydrocarbons (xylene, kerosene, diesel oil,
water and water-oil emulsions can be present gasoline) used in fracturing will have low
near the wellbore. Breaking or preventing these surface tensions. They tend to spread out on a
emulsions can be of great benefit in increasing solid surface to form a film (Figure 6.2).
the productive flow of oil to the wellbore.
Surfactants (“surface active agents”) have been
developed to reduce fluid retention in a
formation. Through the wise use of surfactants, Figure 6.2 - Liquid with a low surface
these chemicals can aid in stimulation fluid tension
recovery and reduce the possibility of emulsions
forming in the formation.
The surface tension of most liquids can be
changed by the addition of surfactants.
Surfactant Definition

A surfactant is defined as a “surface active Surfactant Usage

agent.” This means a chemical which, when
added to a liquid, changes the surface tension of Surfactants have been used in conjunction with
the liquid. Emulsifiers, non-emulsifiers, and fracturing treatments for several years. There are
anti-foaming agents are all examples of four important effects of these chemicals in
surfactants. In a practical sense, the term is fracturing:
limited to those chemicals that lower the surface
• helps prevent water blocks
tension of liquids. Surface tension is composed
of the forces present in the surface film of all • helps prevent the creation of emulsions
liquids. It tries to pull the fluid into a form with between the injected fluid and the formation
the least surface area. This would be a sphere or fluid
a round droplet The particles in the surface film
are attracted inwardly, causing tension. • helps stabilize emulsions when using an
emulsified treatment fluid
Mercury has a very strong surface tension, so it
always tends to form itself into balls (Figure 6.1) • aids in fluid recovery
Emulsions that are accidentally created in the
formation and do not break spontaneously may
. reduce the flow of fluid into the fracture.
Emulsions in the fracture may limit the flow of
fluid through the fracture itself. If properly used,
a surfactant incorporated in the injected fluid can
help prevent the formation of emulsions during

© 2005, Halliburton 6 • 11 Stimulation I

 Fracturing Fluids and Materials

the treatment. The selection of the most effective

type and concentration of surfactants for the
prevention of emulsions or fluid blocks can be
determined by emulsion and flow tests.
Surfactants vary in chemical composition and
the effects they have on oil-water mixtures.
Some cause the formation of oil-water Figure 6.3 - Surfactant Molecule
emulsions. Surfactants of this type exist
naturally in some crude oils. They are the cause
of common oil field emulsions. These emulsions Anionic surfactants (Figure 6.4) are organic
may be very thick and, when formed in a molecules whose water-soluble group is
formation, will block the flow of well fluids negatively charged.
more so than water.
Although emulsions formed in a formation may
block the flow of oil, certain surfactants can be
used to develop emulsions that can be used to
fracture oil-bearing formations. Acidfrac is an
acid-in-oil emulsion prepared with a specific Figure 6.4 - Anionic Surfactant
type of surfactant. It has been successfully used
in many fracture treatments.
Cationic surfactants (Figure 6.5) are organic
molecules whose water-soluble group is
Surfactant Composition positively charged.

Surfactants are composed of an oil soluble group

(lipophilic group) and a water-soluble group
(hydrophilic group). These chemicals have the
ability to lower the surface tension of a liquid by
adsorbing at the interface between the liquid and Figure 6.5 - Cationic Surfactant
a gas. Surfactants lower the interfacial tension
by adsorbing at interfaces between two
immiscible (unmixable) liquids. They also Nonionic surfactants are (Figure 6.6) organic
reduce contact angles by adsorbing at interfaces molecules that do not ionize and therefore
between a liquid and a solid. Surfactants are remain uncharged.
classified into four major groups, depending
upon the nature of the water-soluble group.
These divisions are:
• Anionic
• Cationic Figure 6.6 - Nonionic Surfactant
• Nonionic
• Amphoteric Amphoteric surfactants (Figure 6.7) are organic
The following model (Figure 6.3) will be used molecules whose water-soluble group can be
to simplify this discussion. positively charged, negatively charged, or
uncharged. The actual charge of an amphoteric
surfactant is dependent upon the pH of the
system.

© 2005, Halliburton 6 • 12 Stimulation I

 Fracturing Fluids and Materials

Surface Tension
Water 71.97 dynes/cm
Octane 21.77 dynes/cm
Figure 6.7 - Amphoteric Surfactant Benzene 28.90 dynes/cm
Carbon Tetrachloride 26 0.66 dynes/cm
Table 6.1 – Surface tension of various
liquids
Surfactant Mechanisms

Some effective hydrocarbon surfactants will

Surface Tension reduce the surface tension of distilled water to
about 27 dynes/cm when used in relatively low
Because surfactants are composed of water- concentrations. Another type has been used as
soluble and oil soluble groups, they will absorb an aid for stimulating tight gas wells. This type
at interfaces between a liquid and a gas, or two of surfactant is based on an oil soluble group
immiscible liquids. Figure 6.8 illustrates how composed of a fluorocarbon chain. Using this
surfactants function to lower surface tension. type, it is possible to get surface tensions below
20 dynes/cm.
Surfactants will also lower the interfacial tension
that develops between two immiscible liquids by
absorption of the surfactants at the oil-water
interface.

Wettability
Figure 6.8 - Surfactant Interaction
The ability of a surfactant to adsorb at interfaces
between liquids and solids and to alter the
The “water-loving” group is more soluble in wettability of solids is usually explained by an
water than the “oil-loving” group. Therefore, a electrochemical approach. Wettability indicates
surfactant molecule orients itself at the air-water whether a solid is coated with oil or water. Most
interface with the oil soluble group in the air and formations are composed primarily of mixtures
the water-soluble group in the water. This alters containing sand, clay, limestone and dolomite.
the nature of the air-water interface. Depending
on the effectiveness of the surfactant, the Sand and clay usually have a negative surface
interface now is a combination of an “air-water- charge. With cationic surfactants, the positive
oil” interface. Oil has a much lower surface water-soluble group is adsorbed by the negative
tension than water (Table 6.1). Therefore, the silica particle, leaving the oil soluble group to
surface tension of a water/surfactant mixture influence wettability. Therefore, cationics
will be lower than the surface tension of pure generally oil wet sand. With anionic surfactants,
water, perhaps as low as oil. the negative silicate electrically repulses the
negative water-soluble group. Thus the
surfactant is not usually absorbed by sand.
Therefore, anionics generally leave silica
minerals in a natural water wet state.

© 2005, Halliburton 6 • 13 Stimulation I

 Fracturing Fluids and Materials

Table 6.2 lists a number of surfactants

commonly used by Halliburton and their
charges.

Composition
LoSurf – 259
Non-Ionic Surfactant for LoSurf – 300
Figure 6.9 - Wettability Characteristics Water and Acid Systems LoSurf – 357
LoSurf – 396
Cationic Non-Emulsifiers 17N
Limestone has a positive surface charge at a pH
19N
below 8 and a negative surface charge at pH
20N
values above 9.5. Under oil field conditions
LoSurf – 400
most limestone and dolomite formations will
have a positive surface charge. Since anionic Anionic Non-Emulsifiers LoSurf – 2000S
surfactants have a negative charge, the water NEA-96M
soluble group will be adsorbed by the positive Amphoteric Non-Emulsifier HC-2 (AQF-4)
carbonate particle leaving the oil soluble group Table 6.2 – Charges for commonly used
to influence wettability. Because of this, surfactants
anionics usually oil wet limestone and dolomite
formations.
Carbonates do not adsorb cationics; therefore,
most cationics will leave limestone and dolomite Summary
naturally water wet. An illustration of the
mechanism governing wettability characteristics
exhibited by anionic and cationic surfactants on In summary, selection of the most effective type
silicates and carbonates is shown in Figure 6.9. and concentration of surfactants for the
prevention of emulsions or fluid blocks should
In the case of nonionic surfactants, the be determined by emulsion and flow tests.
wettability of silicates and carbonates depends Having made these tests and selected the correct
primarily on the weight ratio of the water- type and concentration for the surfactant, it is the
soluble group to the oil soluble group. responsibility of the frac operator not to
substitute for the type or change the
concentration of surfactant. If the selected type
Blending of Surfactants surfactant is not available, additional tests will
be required to determine a second choice for the
Most surfactants used by the petroleum industry surfactant.
are blends of several surfactants with a solvent
There are many surfactants available for oil field
present. By selectively blending surfactants, it is
work. Great care should always be observed in
possible to obtain a mixture with more universal
their selection and use for particular conditions.
properties. This is very important since there are
Check with the engineering staff in your district
no two producing formations exactly alike.
for help in making selections.
Therefore, no single surfactant is universally
applicable. Even by blending surfactants, it is
not yet possible to have one surfactant that will
always satisfactorily perform in every field.

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 Fracturing Fluids and Materials

Unit D Quiz: Surfactants

Fill in the blanks with one or more words to check your progress in Unit D.
1. Surfactants can be defined as ____________________ ____________________ agents.

2. Surface tension is ____________________ for water than surface tension is for oil.

3. Four important effects of chemicals used as surfactants in fracturing fluids are:

1.__________________________________________________________________________

2.__________________________________________________________________________

3.__________________________________________________________________________

4.__________________________________________________________________________

4. Emulsions that are accidentally created in the formation may __________ the flow of fluids.

5. Surfactants incorporated in the injected fluid can __________________ the formation of emulsions if
____________________ selected.

6. Selection of the most effective type and concentration of surfactant can be determined by
____________________ and flow tests.

7. Surfactants can be classified into four major groups, depending upon the nature of the
____________________ ____________________ group.
Now, look up the suggested answers in the Answer Key at the back of this section.

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 Fracturing Fluids and Materials

Unit E: Gelling Agents

Gelling agents are divided into two categories: • xanthan
those for water base fluids and those for oil or
hydrocarbon base fluids. The two categories will • polyacrylamides.
be discussed separately in this unit.
Guar
Gelling agents are used for increasing viscosity,
reducing friction, controlling fluid loss, etc.
Viscosity (resistance to motion) is the most Guar and its derivatives are the most extensively
important condition derived from the use of used polymers in fracturing fluids. The guar
gelling agents. bean, which is grown primarily on the
Indo-Pakistan subcontinent, is a polysaccharide
with one of the highest molecular weights of all
Water-Based Gelling Agents naturally occurring water-soluble polymers. The
average molecular weight is believed to be in the
range of 1 to 2 million. The guar bean's hull is
Gelling agents are generally high molecular
removed and the endosperm (inside portion) is
weight polymers. Polymers contain functional
ground into a fine powder, which is used as a
groups that interact with water and each other.
viscosifier. The guar molecule is in a coiled state
When dry, polymers are twisted into coils, but
in the powder form. Guar molecules absorb
swell or hydrate in water and develop a more
water (a process referred to as hydration) upon
relaxed configuration (Figure 6.10). Hydration
being placed in an aqueous media and uncoil,
of polymers reduces available water in the
elongate, and become linear.
solution. Some entanglement of the hydrated
polymers occurs and reduces freedom of motion. Several factors will affect the hydration rate of
Gelled fluids are classified as semi-solids. polymers:
• pH of the system
• amount of mechanical shear applied in the
initial mixing phase
• polymer concentration
• salt concentration of the solution
• particle size and chemical treatment of
polymer
• presence of special additives
Figure 6.10 - Polymer Configurations Some of the general properties for guar gums
include:
• Contains 10 to 13% residue by weight
A number of water-based gelling agents have
been developed for use in the fracturing process • Easy to crosslink
(Table 6.3). Water-soluble polymers commonly • Yields 40 lb gel viscosities of 32 to 36
used in oilfield applications are: centapoise (cp) at 511 sec-1 (reciprocal
• guar and its derivatives seconds)

• cellulose and its derivatives • Can be used with brines

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 Fracturing Fluids and Materials

• Has low methanol tolerance Cellulose

• Least expensive gelling agents
All cellulose compounds used as fracturing fluid
gelling agents are derivatized forms of cellulose.
Derivatized Guars Cellulose derivatives are polymers made from
cotton. They are chemically modified natural
Derivatized (modified) guar gelling agents are products designed for applications that require a
also manufactured from the guar bean. These highly efficient gelling agent that contains no
agents are subjected to additional chemical solids and leaves no residue when broken
processing, which adds to its cost. This properly.
processing reduces the residue that remains after
the gelled fracturing fluid is broken and Hydroxyethel cellulose is currently the most
improves dispersion to enhance mixing commonly used form of derivatized cellulose
characteristics. Derivatized guars, such as products in the oil field. Unlike guar and its
hydroxypropyl guar (HPG) are commonly used derivatives, HEC only hydrates rapidly at a pH
in the oilfield. The characteristics of HPG are: of over 7.0. HEC is most commonly used for
sand control operations.
• Contains 1 to 3% residue by weight
General properties of HEC include the following
• Higher crosslink viscosities than guar
• May be used with brines
• Fewer crosslink sites
• Stable at high temperatures
• Yields 40 lb gel viscosities of 32 to 36 cp at
511 sec-1 • Residue-free

• Can tolerate 80% by volume methanol with • Yields high viscosity gels – 40 lb gel
some HPG derivatives viscosities of 45 to 50 cp at 511 sec-1

• More expensive than guar. • Expensive

Carboxymethyl hydroxypropyl guar (CMHPG) The primary advantage of HEC and the other
is another commonly used guar derivative in the derivatized celluloses is that they are residue
oilfield. It is similar to HPG with some free after degradation.
additional versatility in crosslinking via the Carboxymethyl cellulose (CMC) is a
carboxyl groups. CMHPG is a double residue-free polymer that can be crosslinked;
derivatized material. Some characteristics of however, CMC is extremely salt sensitive,
CMHPG include the following which limits its application
• More sensitive than guar and HPG to brines Characteristics of CMC include:
and electrolyte solutions
• Maximum viscosity and stability with CMC
• Hydrates well in cold or warm water occurs at pH 7 to 9 with fresh water
• Yields 40 lb gel viscosities of 30 to 32 cps at • Extremely sensitive to divalent metal salts
500 sec-1 in 2% KCl such as CA+2, Zn+2
• Anionic derivative • Low salt tolerance
• 1 to 2% residue by weight • Relatively expensive
• Easy to crosslink The double derivatized carboxymethyl
hydroxyethyl cellulose (CMHEC) has found
• Equivalent in cost to HPG
acceptance as a gelling agent in stimulation
fluids. CMHEC has both nonionic and anionic
substituent groups.

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Characteristics of CMHEC include: Acid Gelling Agents

• Residue free
Gelling agents are normally found in fracture
• Can be used with brines acidizing treatments where viscosity is used to
• Can be crosslinked help achieve deeper acid penetration. However,
in a matrix treatment, while deep penetration is
• Relatively expensive not the objective, viscosity can be an advantage
in fines removal. If used for this purpose, the
Xanthan concentration of the acid gelling agent will be
much less than a similar application in fracture
Biopolymers have been used in drilling fluids acidizing. In addition, viscosity derived from a
surfactant rather than a polymer will minimize
for a number of years. Recently, xanthan has
the potential for additional damage.
been introduced in fracturing and sand control
applications. Xanthan yields much less Although the fluid systems using the same base
viscosity per pound of polymer when polymers are composed of the same base
compared to guar and cellulose; however, it materials, each one is specially formulated to
does have excellent proppant transport tailor its performance to meet particular needs.
characteristics. Maximum freshwater solution Water Base
Chemica l Name Gel System
viscosity occurs at a pH of 5.5. At pH values Polymers
of less than 7, chrome or aluminum will WG-19 FracGel
crosslink xanthan gum solutions. WG-22 BoraGel
Properties of xanthan include: Guar WG-26 Hybor-G
WG-31 DeltaFrac
• Residue 3% by weight WG-35 WaterFrac-G
Hybor-H
• Expensive Hydroxypropyl Delta-H
WG-11
Guar (HPG) WaterFrac-H
• Can crosslink SeaQuest
PurGel III
• Excellent proppant transport. Carboxymethyl
ThermaGel
Hydroxypropyl WG-18
Sirocco
Guar (CMHPG)
Polyacrylamides SilverStim
Hydroxyethyl
WG-17 HEC
Cellulose (HEC)
Polyacrylamides (PAM) are used in fracturing
fluids as friction reducers. In the dry form Xanthan WG-24 Liquid Sand
these are used at concentrations of 2 to 5 lb per Chemically
1,000 gal fluid. PAM's can be cationic or anionic modified natural AlcoGel III
WG-20
and are residue free. Properties of polymer for AlcoFoam
methanol.
polyacrylamides include:
Anionic Friction
Non-acid
• Relatively expensive Reducing FR-26LC
WaterFrac
Polyacrylamide
• Hard to mix without creating gel balls Cationic Friction FR-28LC
Acids
• Extremely high molecular weight – 1 to 20 Reducing FR-38
WaterFrac
Polyacrylamide FR-48
million.
SGA-HT
Sand Stone
• Produce the greatest friction reduction Liquid SGA-I
2000
(anionic polymers) viscosifier for SGA-II
Carbonate
acid SGA-III
20/20
• Used in low concentration. SGA-IV
Table 6.3 – Gel names and their uses

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 Fracturing Fluids and Materials

Oil Gelling Agents MY-T-OIL V

In the fracturing of certain extremely water- A recent extension of the MY-T-OIL series,
sensitive formations, even the use of potassium MY-T-OIL V is a crosslinked, anionic
chloride, calcium chloride and sodium chloride surfactant, oil-gellant system. It uses MO-85
solutions may not be effective in reducing clay anionic surfactant and MO-86 crosslinker. The
swelling or formation particle migration. This use of surfactant chemistry prevents damage by
can usually be determined from laboratory tests polymer residue. The chemicals are added at a
on formation cores or from field treating results. 1:1 ratio with the normal usage concentration
In such cases, an oil base fluid should be being 4 to 9 gal/Mgal, depending on
considered. However, when using a temperature. My-T-Oil V is capable of
hydrocarbon-based fluid system, safety to viscosities over 600 cp at 170 sec-1 depending on
prevent fires on location is a main concern and temperature, additive concentration and
good fire fighting equipment is a must. hydrocarbon used. The system is designed for
continuous-mix stimulation of oil reservoirs over
To meet the needs of treating water sensitive a wide temperature range up to 275 degrees.
formations, gelling agents have been developed Crude oils that gel easily may be effectively
to give structure to oil base fluids. The four used in this application to reduce costs, but the
basic fluid systems below are available for oil MY-T-OIL V system will gel a wide range of
base fracturing fluids and are a culmination of crude oils. However, the risk of paraffin and/or
years of research. asphaltene precipitation in the formation is
greater than with refined fluids such as diesel.
MY-T-OIL IV
MISCO2 FRAC
Earlier gelled oil systems had to be batch mixed
prior to pumping the fracture treatment. MY-T-OIL V’s counterpart, MISCO2 FRAC
Extensive laboratory research and field-testing fracturing system, provides similar benefits for
have resulted in the development of a gas reservoirs, including those which are low
continuously mixed gelled oil system. This pressured and/or water sensitive. MISCO2
system can reduce the time on location caused FRAC is used with up to 50% CO2 by total
by batch mixing, as well as eliminate waste and volume. In this application, the system provides
disposal problems caused by leftover gelled excellent fracture and formation conductivity
fluid in the storage tanks. with rapid load fluid recovery. MISCO2 FRAC
The My-T-Oil IV system uses a two-component employs the same gelling system used in MY-T-
system. The components are MO-75 gelling OIL V.
agent and MO-76 activator. The chemicals are
added at a 1:1 ratio with the normal usage Super Emulsifrac (Oil Internal Gelled
concentration being 4 to 6 gal/Mgal. The final Water External Emulsion Fracturing
viscosity of this system will vary greatly Fluid)
depending on the type of hydrocarbon used and
the chemical concentrations. For refined
Super Emulsifrac is the Halliburton name for a
hydrocarbons such as diesel or kerosene, the
fracturing process developed by Exxon
viscosity should be in the range of 100 – 400 cp
Production Research Company (EPR). This
at 170 sec-1. MY-T-OIL IV is effective at
process uses an emulsion composed of an
temperatures up to 200 degrees.
internal hydrocarbon phase (such as diesel,
kerosene, condensate, or crude oil) and an
external water phase containing a gelling agent
such as WG-22, WG-31 or WG-11. The
emulsion is stabilized with an emulsifier such as

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 Fracturing Fluids and Materials

SEM-5, SEM-6, or SEM-7 that is contained in constant internal phase principles to emulsion
the gelled water phase. The internal hydrocarbon fluids, friction pressures can be controlled
phase is between 50 and 80% of the total resulting higher sand concentrations.
volume, and the remaining volume is composed Super Emulsifrac can be used up to 300 degrees
of the gelled water, emulsifier, and other with the proper emulsifier concentrations.
additives.
Super Emulsifrac fluids are similar to N2, or Additional References
CO2, foams, except that a hydrocarbon
constitutes the internal phase of the two-phase
fluid rather than gas. With the application of Fracturing Service Manual – HalWorld.

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 Fracturing Fluids and Materials

Unit E Quiz: Gelling Agents

Fill in the blanks with one or more words to check your progress in Unit E.
1. Gelling agents are used for increasing viscosity, reducing friction, controlling fluid loss, etc.
___________________ is the most important condition derived from using gelling agents.

2. Gelling agents are generally high molecular weight ____________________.

3. Gelled fluids are classified as ____________________ - ____________________.

4. The amount of residue resulting from the use of guar gelling agents is __________ to __________%.

5. The guar bean’s hull is removed and the ____________________ is ground into a fine powder which
is used to create viscosity.

6. Carboxymethyl Cellulose (CMC) is extremely ____________________ ____________________,

which limits its application.

7. Derivitized guar gelling agents will give __________ to __________% residue after break of the
gelled fluids.

8. Polyacrylamides are mainly used in fracturing as ____________________ ___________________.

9. Cellulose derivatives are chemically modified ____________________ and contain

________________ solids and leave no ________________ upon breaking.

10. Xanthan yields much less ____________________ per pound of polymer when compared to guar
and cellulose; however, it does have excellent ___________________ ____________________
characteristics.

11. MY-T-OIL V uses ________________ surfactant and ________________crosslinker in a

_____:_____ ratio.

12. SUPEREMULSIFRAC is composed of an internal ____________________ phase and and external

____________________ phase.
Now, look up the suggested answers in the Answer Key at the back of this section.

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 Fracturing Fluids and Materials

Unit F: Complexors and Crosslinkers

Complexors or crosslinkers can provide
additional viscosity in a fracturing fluid system. K-38
They are added to the base gel fluid. Small
amounts of these crosslinkers chemically link K-38 is a white powdered borate crosslinker,
two or more polymer chains, thus increasing the also called Polybor. It was developed to give the
effective molecular weight and viscosity. highest concentration of borate ions in solution
Crosslinking agents commonly used in per weight of borate source and is highly
stimulation fluids are metals (antimony, effective as the primary crosslinker in BoraGel
zirconium, aluminum, chromium, titanium) and or as a crosslink accelerator in the Hybor and
boron. Variables such as pH, polymer type, DeltaFrac fluid systems. K-38 is usually
pump time, and fluid temperature will dictate to dissolved in water at a 1 lb/gal concentration for
a large extent, the crosslinker used (Figure ease of mixing and metering.
6.??).
A major concern with crosslinked fluids is their CL-11
shear stability (ability to resist a decrease in
viscosity under shear) while pumping down the CL-11 is a light yellow, water-sensitive, alkaline
tubular goods and through perforations. This liquid. It contains a titanium-ion complex in an
concern led to the development of delayed alcoholic solution. CL-11 can be added to
crosslinkers that are designed to inhibit Thermagel or VersaGel HT or it can be mixed
crosslinking in the tubulars. with the primary crosslinkers in these systems
(CL-24 and CL-18) to achieve accelerated
Factors which influence crosslinking
crosslink times. Crosslink time testing should be
• Polymer concentration - generally, the conducted with actual source water before
greater the concentration, the higher the performing the stimulation treatment.
viscosity will be.
• Metal ion type and concentration - an CL-18
optimum crosslinker concentration exists,
above or below which unacceptable CL-18 is an older, titanate complex crosslinker
viscosities or gel stability results for each for use in the VersaGel HT fluid system. It is a
crosslinker and gel concentration. yellow-gold colored liquid and is flammable,
with a flash point of 74°F. It is a delayed
• pH - Some crosslinker systems are highly crosslinker which can be accelerated with
pH sensitive, for example borate (requires temperature or the addition of CL-11.
pH > 8), whereas others, like titanium,
tolerate a wide range in pH.
CL-22
• Shear - The amount of shear a gelled fluid is
subjected to during mixing will influence the CL-22 is an oil-base slurry of borate minerals
viscosity of the system. High shear generally used in Hybor fluid systems. CL-28M is a water-
degrades viscosity; low shear mixing based slurry of borate minerals. Both CL-22 and
generally yields more viscous gelled fluids. CL-28M provide delayed crosslink to borate
crosslinked fluids, similar in apparent viscosity
to the non-delayed borate crosslinked BoraGel
fluid.

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CL-23
Titanium (IV)
The crosslinking agent, CL-23 is used in the
PurGel III fluid systems. CL-23 is a delayed- Antimony (III)
crosslinking agent that is compatible with CO2.
Chromium (N)
It is an aqueous, colorless liquid containing a
zirconium complex. It may be diluted with fresh Boron (III)
water for convenience of metering. Crosslinker
Antimony (V)
concentration used depends upon the buffering
system employed.
100 150 200 250 300

CL-24 Figure 6.11 – Upper Limit Temperature

Ranges for Specific Crosslinking Agents in
CL-24 is a pale yellow, liquid zirconium-ion their Usable pH and Concentrations Range.
complex that is used as a delayed temperature-
activated crosslinker in the Thermagel fluid
system. The crosslinker begins activation at
100° to 110°F. The base gel fluid will crosslink CL-29
rapidly at 140°F. Each drum of CL-24 is dated
and the oldest stock should always be used first. CL-29 is a fast acting zirconium complex that
CL-24 is a flammable liquid. The recommended was introduced as an accessory crosslinker for
concentration of CL-24 is 0.10 gal per 10 lb of the PurGel III fluid system. CL-29 provides a
base gel per 1,000 gal of fluid. more rapid crosslink time when used with CL-
23. It can also be used as a stand-alone
CL-28M crosslinker.

CL-28M is a water-based suspension crosslinker CL-31

of a borate mineral used in Hybor fluid systems
and was developed as a low cost alternative to CL-31 is a concentrated solution of non-delayed
CL-22 (see above). Since CL-28M is water- borate crosslinker originally designed for use in
based, it does not have the flash point concerns BoraGel fluid systems. Also used to control
associated with CL-22. The suspension crosslink time for Hybor fluids, it provides the
properties of CL-28M have been improved to convenience of a concentrated, stable crosslinker
provide better stability. However, containers solution. One gallon of CL-31 contains the
should be inspected for solids settling and equivalent of 2.0 lb of K-38, has a high pH and
remixed if needed. Material loss could occur if is highly caustic. CL-31 has no flash point and
the suspension adheres to the sides of the has a pour point of -5°F. If diluted with water or
container. aqueous sodium hydroxide, CL-31 will freeze
above -5°F. Because of its high pH, CL-31 can
be used as a self-buffering crosslinker.

BC-140 (formerly BC-2)

BC-140 is a dark-colored, specially formulated

crosslinker/buffer system for use in Delta Frac
fluid systems. No additional buffering agents,
acids, or bases are required to adjust the pH of
the fluid system. The concentration range of BC-
140 that provides the best viscosity performance

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 Fracturing Fluids and Materials

for the Delta Frac fluid system is 1.5 to 2 the pH of the fluid out of the proper range will
gal/Mgal for 15 to 25 lb gel loading between 80° ruin the fluid by over-crosslinking, resulting in
and 120°F. Crosslinker concentration is much lower viscosity. The final pH of this
temperature and water dependent. In 2% KCL or system should be approximately 9 to 9.5.
brine waters, BC-140 concentration is decreased Although the crosslink time of the system cannot
while at higher temperatures it is increased. be increased, it can be decreased by adding an
instant borate crosslinker such as K-38, BC-140
BC-200 or CL-31.

BC-200 is a delayed crosslinker and functions as CL-36

both crosslinker and buffer for use in the Delta
Frac fluid systems. It is a dark brown suspension CL-36 is a new mixed metal crosslinker
of fine particles in a hydrocarbon. No additional specifically designed for the Delta 275 fluid
buffering agents, acids, or bases are required to system. It is a yellow, alcohol based system with
adjust the pH of the fluid system. Used at the a flash point of 81°F. The concentration used is
proper concentrations, BC-200 buffers fluids to a function of the temperature and pH of the final
the proper pH. The resulting design raises the fluid system (generally 1 to 2.2 gal/Mgal). CL-
pH of the fluid but does not increase crosslink 36 is a delayed crosslinker that can be
time. In fact, adding caustic or a buffer to raise accelerated with the addition of CL-31.

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Unit F Quiz

Fill in the blanks with one or more words or mark the best answer to check your progress in Unit F.
1. Small amounts of crosslinkers chemically link two or more ___________________
____________________, thus increasing the effective ___________________
____________________ and ___________________.

2. List four factors that influence crosslinking:

_____________________

_____________________

_____________________

_____________________

3. CL-11 is a light yellow, alkaline, ___________________-ion complex that is added to the Thermagel
fluid system to achieve an ____________________ crosslinking time

4. One gallon of CL-31 contains the equivalent of __________ lb of K-38, and it is highly
____________________.

5. BC-140 is a dark-colored, specially formulated ____________________/____________________

system for use in the Delta Frac fluid systems.

6. _____True _____False: The crosslinking time of the BC-200 buffer crosslinker can be increased.

Now, look up the suggested answers in the Answer Key at the back of this section.

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 Fracturing Fluids and Materials

Unit G: Breakers and Stabilizers

Breakers

The viscosity of fracturing fluids is increased

when gelling agents and crosslinkers are used to
aid proppant transport and placement. This
increased viscosity is desirable during pump-in
procedures. However, if this viscosity is not
reduced the treated well may not flow. The
stimulation fluid must have the capability to
decrease in viscosity (break) following proppant
placement. The decrease in fluid viscosity is
necessary to
Figure 6.12
• minimize return of proppant
• maximize return of stimulation fluids to the
surface A breaker should be selected based on its
performance in the temperature, pH, time, and
The decrease in the fluid viscosity is usually desired viscosity profile for each specific
achieved using chemicals referred to as gelling treatment.
agent breakers or gel breakers. The gel breaker
functions by breaking the long chain polymers
into shorter chain segments, allowing the fluid Enzyme Breakers
more mobility with controlled and predictable
viscosity decrease. The degree of reduction in
Enzymes are referred to as Nature's catalysts
viscosity is controlled by the breaker type, pH,
because most biological processes involve an
gel concentration, breaker concentration, time,
enzyme. Enzymes are large protein molecules.
and temperature.
Proteins consist of a chain of building blocks
called amino acids. In Oilfield applications,
Breaker Types breaker enzymes cause hydrolysis, or the
addition of water, to the guar polymer. This
causes viscosity to decrease. However, because
Chemical breakers used to reduce viscosity of of the characteristics of enzymes, they are only
guar and derivatized guar polymers are generally effective in a relatively narrow range of
grouped into three classes: oxidizers, enzymes, temperatures and pH levels.
and acids. All of these materials reduce the
viscosity of the gel by breaking connective
linkages in the guar polymer chain. Once the GBW-3™ / GBW-30™
connective bonds in the polymer are broken, the
resulting pieces of the original polymer chain are GBW-30 is a white powdered enzyme breaker.
the same regardless of the type of breaker used. It is used below 120°F and below pH 8.5. Like
GBW-3, GBW-30 is a water-soluble enzyme
breaker for aqueous-based gelling agents at
temperatures below 120°F (48.8°C). Its reactive

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 Fracturing Fluids and Materials

strength is approximately 10 times that of GBW- transport proppant. The controlled release rate of
3. an encapsulated breaker allows higher
concentrations to be placed throughout the
HPH stimulation treatment.

HPH breaker is an enzyme breaker specifically

designed for borate fracturing fluids up to
approximately 140°F. HPH breaker is a high-
pH, stable enzyme breaker solution that
generally maintains its activity at higher pH than
GBW-30 enzyme breaker; between pH 7 and pH
10. Between 70 and 140°F, HPH breaker’s pH
range of 8.5 to 9.5 is suitable for BoraGel and
Delta FracSM fluids. This pH range contrasts
with the pH range of GBW-30 breaker which
displays its maximum activity below pH 7. Figure 6.13 - Liquid vs encapsulated
Under lower temperature conditions, HPH enzyme breaker.
breaker will function at even higher pH values.

N-Zyme 1 / N-Zyme 3

N-Zyme 1 enzyme breaker and N-Zyme 3

Oxidizing Breaker
enzyme breaker are new breakers for use with
fracturing fluids at temperatures up to 140°F. N- Sodium, potassium, and ammonium persulfate
Zyme 1 and N-Zyme 3 breakers can be used in have been used effectively as breakers for over
place of GBW-3 breaker, GBW-30 breaker, and 30 years. In these types of breakers, oxidation-
HPH breaker. N-Zyme 3, which is three times reduction chemical reactions occur as the
more concentrated than N-Zyme 1, is polymer chain is broken.
specifically formulated for lower-temperature
applications. SP

OptiFlo-HTE SP Breaker is a white granular oxidizing

material used as a breaker at temperatures above
OptiFlo-HTE is an encapsulated, delayed 120°F. It may be used below 120°F in
release, high temperature, enzyme breaker. It is conjunction with an activator. Above 180 deg,
a reddish colored granular solid. OptiFlo-HTE is persulfate breakers become highly unstable and
the direct replacement for the obsolete OptiFlo- create unpredictable breaks.
E. The recommended temperature range for
application is from 75 to 175°F ViCon HT or ViCon NF
The merits of an encapsulated enzyme breaker
are many. The encapsulation of OptiFlo-HTE Powder form ViCon-HT or liquid form ViCon-
allows the enzyme to be shielded from the fluid NF is a powerful oxidizing breaker for use with
environment and can delay denaturization due to GEL-STA in fracturing fluids, and is the
temperature exposure when compared to a liquid premiere breaker at temperatures above 200°F.
enzyme breaker as shown in Figure 6.13. Liquid Vicon can also be run below 200°F with an
enzyme or solid un-encapsulated enzyme activator. Although ViCon-NF is compatible
breakers cause an almost immediate reduction in with GEL-STA in dilute fluids, such as
viscosity when added to stimulation fluids; this fracturing fluids, ViCon-NF should not be
can lower the ability of the fracturing fluid to mixed with GEL-STA or GEL-STA L liquid

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 Fracturing Fluids and Materials

concentrate. The required concentration of • The breaker is a solid and cannot be lost to
ViCon-NF depends on the temperature, GEL- the formation during fluid leak off.
STA concentration, and required break time.
Fann Model 50 viscometer data can be generated Optiflo III
in the desired temperature range for varying
amounts of GEL-STA and ViCon-NF. A high
OptiFlo III is a delayed release breaker that has
retained viscosity is maintained at the cool down
improved performance as a result of a new,
temperature, but complete breaks occur as the
innovative coating technology that provides less
fluids reach formation temperature.
early time release of the breaker than previous
delayed release breakers. OptiFlo III improves
Optiflo II gel breaking technology by limiting the contact
time of the breaker with the fracturing fluid and
In low temperature, high pH fluids, enzyme concentrating the breaker in the fracture.
breakers are not effective; therefore, there is a Limiting the breaker contact with the fracturing
need for a delayed release, low temperature fluid allows increased breaker concentration
oxidizing breaker. OptiFlo II delayed breaker is without sacrificing fluid performance. Higher
coated ammonium persulfate that is designed to breaker concentrations, as well as concentration
be used in low temperature applications. The of the breaker in the fracture, improves proppant
coating on OptiFlo II allows the breaker to be pack cleanup and results in improved proppant
released slowly by diffusion across the slightly conductivity of the created fracture. OptiFlo III
permeable coating. The release profile of contains ammonium persulfate (AP breaker) as
OptiFlo II at 80°, 100°, and 120°F show less the active component. This breaker is designed
than 10% of the breaker is released in 1 hour, to be used in actual fluid temperatures of 130°F
but at least 70% of breaker is released in 24 to 200°F.
hours. This product is not designed to be used in
applications where the actual fluid temperature
is above 125°F. However, the application of OptiFlo II @ 120°F
100
OptiFlo II can be extended to jobs with
OptiFlo III @ 175°F
bottomhole static temperatures (BHST) above 80
Released (%)

125°F using formation cool down. Field 60

experience and temperature programs can aid in 40
the prediction of downhole fluid temperatures OptiFlo HTE @ 75°F
during the job. The addition of OptiFlo II to the 20
pad is not recommended, but OptiFlo II can be 0
added to the pad fluid in jobs where static break 0 1 2 3 4 5 6 7 8
tests, data, and fluid rheology data support its Time (hr)
use.
Deposition of filter cake during a job can Figure 6.14 - Release Profile of
decrease the conductivity of the generated Encapsulated Breakers
fracture. Delayed release breakers help improve
fracture conductivity by cleaning up the filter
cake and proppant pack. This cleanup is
accomplished by two beneficial features of
delayed release breakers. Acid Breakers
• The capability of adding higher breaker Acid also provides the same break via hydrolysis
concentrations allows enough to be added to as an enzyme. Acid, however, poses various
break the filter cake and gel remaining in the difficulties for practical applications. Acid is not
proppant pack. used as a guar polymer breaker very often
because of cost, poor break rate control,

© 2005, Halliburton 6 • 28 Stimulation I

 Fracturing Fluids and Materials

chemical compatibility difficulties, and developed to be used in conjunction with

corrosion of metal goods. Another difficulty enzyme breakers at temperatures below 120°F.
with acid breakers is that the formation may act
OptiFlo LT is designed to lower the pH value of
as a buffer. A small amount of acid introduced
borate crosslinked fracturing fluid. It can be
as a breaker may be totally consumed by the
used in other fluids where a delayed decreased
formation water and minerals. This absorption
in fluid pH is desired. Unlike previous delayed
could quickly change the pH of the fracturing
release additives, OptiFlo LT has a fast release
fluid to a point where breaking may not occur.
mechanism. In general, OptiFlo LT itself will
Most formation brines have a pH between 6 and
not break the gel polymer of a borate crosslinked
8.
fluid, but when used in conjunction with OptiFlo
The applications for acid breakers are limited, HTE (encapsulated enzyme), a broken gel will
with two exceptions that involve delayed-release result. The combination of OptiFlo LT and
type acids. First, a delayed-release acid may be OptiFlo HTE offers an alternative to the use of
used to un-crosslink a borate. Second, oxidizing breakers.
delayed-release acid may also be useful with
enzyme breakers. Especially at low OptiKleen and OptiKleen LT
temperatures, the use of enzymes in borate
crosslinked fluids is often effective. To allow the
Gel filter cake that forms on the fracture face
enzyme to be effective in the pH 9 to 11 borate
provides desirable fluid loss control; however,
fluid, delayed-release acids can be used to lower
this filter cake also can impair conductivity by
the fluid pH value to a range where the enzymes
causing loss of effective width on both sides of
are effective.
the fracture. This impairment is most
pronounced at low proppant concentrations.
MatrixFlo II Simple breakers in the usual amounts are
sometimes not effective in breaking such a gel.
MatrixFlo II is a liquid, delayed release acid Moreover, filter cakes containing titanate or
breaker that deeply penetrates a formation zirconate crosslinkers especially resist removal.
matrix to provide a more complete break and For this reason, the breakers OptiKleen and
enhanced fracture conductivity. When used in OptiKleen LT have been developed for post-
Delta Frac, BoraGel, and Hybor fracturing fluids treatment filter cake removal. OptiKleen is
MatrixFlo II breaker can controllably decrease recommended for wells with greater than 130°F
fluid viscosity by lowering the pH and bottomhole static temperature (BHST). At
uncrosslinking a crosslinked gel network. When 120°F, it becomes only half as efficient in
MatrixFlo II breaker is used with enzymes, it dissolving filter cake. At 100°F it is ineffective.
will also lower the pH of the system and initiate A low temperature version, OptiKleen-LT, has
enzyme breaker activity to degrade the polymer been developed for use in wells with bottomhole
backbone further. MatrixFlo II breaker can be temperatures below 130°F. The minimum
used effectively at temperatures up to 180°F. recommended volume of fluid with which to
MatrixFlo II breaker significantly improves the treat a fractured well is the void volume of the
regained permeability of the fluid system. proppant bed. This volume can be estimated
using the following formula:
OptiFlo-LT Minimum volume (gal) = 3/7 (PWT × ABV)
Where
OptiFlo LT is a delayed release acid additive
that decreases the pH of fracturing fluids. PWT = total proppant weight (lb)
OptiFlo LT can be used in BoraGel and Hybor ABV = absolute volume of proppant
fluids to decrease fluid pH to initiate enzyme (gal/lb),
breaker activity (to degrade gel polymer) and to 3/7 = the ratio of void volume to
reverse the borate crosslink. OptiFlo LT was proppant volume based on an

© 2005, Halliburton 6 • 29 Stimulation I

 Fracturing Fluids and Materials

estimate that the void is about 30% ViCon-NF Breaker (or ViCon-HT Breaker) has
of the total proppant bed volume. been very successful as a high temperature
breaker, but below 200°F it reacts too slowly to
be useful in the time period desired. By using a
Gelled-Oil Breakers catalyst to “activate” the Vicon, its lower
temperature limit can be reduced. Due to the
high reactivity and thermal instability of
K-34 persulfates, the activated ViCon systems are the
breakers of choice for fluids at 170 to 200°F.
K-34 is used as the breaker for MY-T-OIL IV They can also be used as low as 150°F, but the
gels. Concentration range is 20 to 50 lb/Mgal persulfate systems may be as effective and more
based on fluid temperature. K-34 is a finely economical. The other oxidizing breakers can
divided, white, free-flowing powder. It is not also be activated to function below their lower
considered dangerous; however, it should be temperature limits.
handled as a dusting material. It also possesses
fluid loss control properties and can contribute
fluid loss control in the MY-T-OIL IV fluid. Stabilizers

HL Breaker Gel breakers historically have been used to

accelerate gel degradation. However, at
HL Breaker is used as a breaker for the MY-T- sufficiently high temperatures, either pH or
OIL IV fluid where there are bottomhole temperature may break the viscosity of the gel
temperatures less than 120°F and/or the need for prematurely. At high temperatures, gel extenders
short gel break times. Concentrations range from may be needed to increase the temperature
5 to 10 lb/Mgal, based on the gel concentration stability of gelled fluids, which results in a
and bottom hole temperature. higher retained viscosity at temperature for a
longer period of time. There three ways to
stabilize gels; methanol, Gel Sta, and pH
MO-IV
control.
MO-IV is a white powder breaker developed for
the MY-T-OIL V fluid system. This process is Methanol (Methyl Alcohol)
currently proprietary information. It is effective
from 70° to 200°F. Methanol has found wide spread use in various
fracturing fluids and additives. Occasionally,
methanol has been used to form a slurry of
MO-V
gelling agent for easier introduction into a fluid
while reducing the tendency for the gelling agent
MO-V is a white powder breaker developed for to form lumps. However, its largest use has been
the MY-T-OIL V fluid system. This breaker’s to extend the upper temperature limit of some
makeup is currently proprietary information. It is gel systems to more effectively maintain
used from 201° to 275°F. downhole fluid viscosity for treatment of wells
with high bottomhole temperature.
Breaker Activators The safety precautions required for the usage of
methanol based fracturing fluids are similar to
Just as there is a need to add activators to speed those followed for handling high gravity crude
up crosslink times, there is also a need for oils and condensates. When the flash point of a
activators to better control break times. CAT methanol/water mixture is reached, the mixture
(catalyst) LT, CAT-3, and CAT-4 are chemicals becomes highly flammable due to the high
that are used for this purpose. concentrations of methanol vapors above the
fluid. Unfortunately, unlike high gravity crudes

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 Fracturing Fluids and Materials

and condensates, the methanol flame is not and it is more economical than 5% methanol,
visible and no smoke is produced as the material although it can be added with methanol for
burns. The heat from the flame will be the first increased stability. GEL-STA is not compatible
sign of a methanol fire. with oxidizing breakers such as SP. It is
compatible with Vicon-NF and Vicon-HT, but
GEL-STA and GEL-STA L the ViCons should not be mixed with or even
placed closely to GEL-STA or GEL-STA L
liquid concentrate.
The solid, GEL-STA, and the liquid, GEL-STA
L, are high-temperature gel stabilizers for use in pH control
aqueous fracturing fluid processes. GEL-STA L
contains the equivalent of 3.5 lbs of GEL-STA Maintaining a pH above 7 will also help
per gallon of water. GEL-STA functions by stabilize water base gels.
scavenging oxygen from the fracturing fluid’s
environment. There is no premixing required

© 2005, Halliburton 6 • 31 Stimulation I

 Fracturing Fluids and Materials

Unit G Quiz

Fill in the blanks with one or more words or mark the best answer to check your progress in Unit
G.
1. A decrease in fluid viscosity is necessary to ____________________ return of proppant
____________________ return of stimulation fluids to the surface.

2. Chemical breakers used to reduce viscosity of guar and derivatized guar polymers are generally
grouped into three classes: ____________________, ____________________, and
____________________.

3. N-Zyme 1 enzyme breaker and N-Zyme 3 enzyme breaker are new breakers for use with fracturing
fluids at temperatures up to __________°F.

4. OptiFlo II delayed breaker is coated ____________________ ____________________ that is

designed to be used in low temperature applications.

5. When used in Delta Frac and Hybor fluids, MatrixFlo II breaker can controllably decrease fluid
____________________ by lowering the pH and ____________________ a crosslinked gel network.

6. If 100,000 lbs of proppant with an absolute volume of .0452 gal/lb is pumped into a formation, what
is the minimum recommended volume of OptiKleen needed for removing filter cake? ____________

7. ______ True _____ False: HL Breaker is used from 120-200°F.

8. K-34 is not only a breaker but also a

_____ A) fluid loss additive

_____ B) liquid

_____ C) gelling agent

_____ D) surfactant

9. List three ways to stabilize a water base gel:

__________________________________________

__________________________________________

__________________________________________

10. _____True _____ False: Breakers and stabilizers can be run together on a job.
Now, look up the suggested answers in the Answer Key at the back of this section.

© 2005, Halliburton 6 • 32 Stimulation I

 Fracturing Fluids and Materials

Unit H: Bactericides/Biocides
Bactericides are used to destroy or control Many thousands have not. They are among the
bacteria. Bacteria can cause viscosity instability simplest forms of non-vegetative organisms.
in batch mixed gels. When conditions are Because they are living, they have the same
favorable, sufficient numbers of bacteria can be needs as other forms of life: a source of energy,
the chief cause of gel degradation. carbon, nitrogen, sulfur and phosphorus,
metallic elements, vitamins and water. They can
also adapt to changing environments.
Enzyme
Bacteria can be classified by their environmental
needs:
• Aerobic bacteria grow in the presence of
Microorganism Polymer oxygen
• Anaerobic bacteria grow in the absence of
oxygen

Sugar • Some bacteria thrive in very low

temperatures, while others do not
Figure 6.15 - Degradation of Polymer by
Microorganisms • Various bacteria may thrive in a variety of
pH ranges.

Bactericides
Bacteria Conditions
Bactericides should be handled with care.
Some of the most favorable environments for Anything that can destroy bacteria may be
bacteria are dirty frac tanks and mixing water. dangerous to handlers.
Dirty frac tanks often contain several gallons of
bacteria-ridden decomposed gel from previous Caustic
jobs. When new gel is added, the bacteria have a
new food source. When the conditions are
Caustic is used to adjust the treating water pH
favorable, some species may even attain
upward and can be an effective bactericide if
maximum concentrations within twenty-four
done properly. Add the caustic to each tank of
hours.
water to be treated until the pH of the water is
Bacteria feed on gel by releasing enzymes. The greater than 11.0 throughout the tank. This will
enzymes degrade the gel to sugar, and the control bacteria over extended periods of time
bacteria absorb the sugar through their cell and can also be used as an effective quick-kill
walls. The enzymes released are very similar to technique.
the low temperature breaker GBW-3. A
simplified cycle for the degrading of the BE-3
polymer by bacteria is shown in Figure 6.15.
BE-3 is a biocide that should be handled in a
very safe and careful manner. BE-3 is an
Bacteria Types
effective, extremely fast-killing biocide at low
concentrations (0.1 gal/Mgal). Maximum
There are thousands of different kinds, or effectiveness of BE-3 will be attained if the
strains, of bacteria that have been classified. entire volume of the biocide is placed in the frac

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 Fracturing Fluids and Materials

tank with the first load of water as the tank is BE-6

being filled. This procedure places a high
enough concentration of biocide in the bottom of BE-6 is a new bactericide that addresses the
the tank where bacteria and a large portion of issue of packaging and persistence of kill. This
their enzymes can be destroyed. Addition of the material is nonionic and provides a broad-
biocide to a full tank will result in killing the spectrum control of bacteria. BE-6 functions
bacteria but not affecting the enzymes. BE-3 similar to BE-5; it has a slow rate of kill (6 to 10
degrades rapidly at pH levels greater than 7.0. hours) and controls growth by inhibiting the
Therefore, its use should be restricted to fluid metabolic pathway of the bacteria. BE-6 is a
with pH’s less than 7.0. white, solid powder placed in a water-soluble
bag to improve handling and ease of addition.
BE-3S The water-soluble bag is contained in a
protective outer bag that must be removed prior
BE-3S biocide is a rapid killing, board-spectrum to addition to the frac tank. Three of the 1-lb
biocide packaged in water-soluble bags for water-soluble bags provide the normal dosage
safety and ease of use. A powdered version of for a single 20,000-gal frac tank.
BE-3, BE-3S provides all the treatment benefits
of BE-3 while helping to eliminate handling and CAT-1
disposal problems associated with liquids.
The use of biocides to treat tanks of fluid for
BE-5 bacteria control has been used to control active
bacteria particularly during warm weather.
BE-5 is a broad spectrum biocide. It is used to However, it has recently been determined that
control the growth of microorganism even during winter months bacteria can assume
populations commonly found in source waters a sporulated form that resists the action of
for fracturing and stimulation processes. BE-5 is biocides such as BE-5. Although these particular
effective against most types of bacteria, fungi, bacteria may not prematurely break the gel, our
and algae. It controls population growth by customers have expressed a desire to kill these
acting as a metabolic inhibitor. Although slower bacteria if found during bacteria counts. CAT-1
acting than other biocides, it has proven to be is available as sodium hypochlorite (household
reliable. bleach) from most chemical suppliers in major
cities. Usually found in concentrations of 10 or
BE-5 is a nonionic, nonfoaming, degradable 15% sodium hypochlorite, it is normally used at
biocide with a broad pH stability range. The 0.5 gallons of a 10% solution or 0.33 gallons of
active ingredient is absorbed into Fullers earth, a 15% solution per 1,000 gallons of water to be
which renders the solid product as a nondusting treated. The disadvantage of CAT-1 is that
material that is much safer for handling than because it is an excellent oxidizer, GEL-STA
other solid or liquid biocides. It is conveniently must be added to the treated water to neutralize
packaged in a 6 lb plastic bottle containing a it prior to adding a gelling agent.
sufficient dosage for one 20,000 gal frac tank.
One container of BE-5 biocide (6 lb) should be
added to each 20,000 gal frac tank with the first Additional References
load of water. BE-5 may not be premixed in
LGC concentrates. The oil phase in the LGC
Chemical Stimulation Manual
will inhibit the release of the biocide from the
Sales and Service Catalog
Fullers earth.
Chemical Services Technical Data Sheets
Halliburton Services Personnel Training Video
Hal World

© 2005, Halliburton 6 • 34 Stimulation I

 Fracturing Fluids and Materials

Unit H Quiz

Fill in the blanks with one or more words to check your progress in Unit I.
1. Bacteria cause viscosity ____________________ in batch mixed gels.

2. The most favorable environment for bacteria are ___________________ frac tanks and
____________________ water.

3. Bacteria feed on gel by releasing ____________________.

4. BE-3 degrades at pH’s greater than __________.

5. BE-3 should be added to the ________________ load of water in the tank.

6. _____ BE-5 container(s) should be added to each 20,000 gal frac tank with the ________________
load of water.

7. BE-6 has a ___________________ rate of kill and controls growth by inhibiting the
____________________ pathway of the bacteria.

8. To kill bacteria, caustic should be added until pH of the water is above __________ throughout the
tank.

9. After treating a frac tank with CAT-1, ____________________ must be added to

____________________ the treated water prior to gelling.

Now, look up the suggested answers in the Answer Key at the back of this section.

© 2005, Halliburton 6 • 35 Stimulation I

 Fracturing Fluids and Materials

Unit I: Conductivity Enhancers

SandWedgeTM SandWedgeTM NT

The conductivity enhancement additives came as SandWedgeTM NT, which uses the dry proppant
a direct result of research to find a liquid coating method, was designed to make
proppant flowback control additive. The SandWedgeTM compatible with most frac fluids
SandWedge materials that were produced and and surfactants. Dry coating means that instead
are continuously being improved were found to of adding the material to a fracturing fluid with
have the unique property of improving the flow proppant already in it, SandWedgeTM NT is
of fluids through proppant. There are three allowed to coat the proppant before being
mechanisms that allow this to happen: introduced to the fluid. It greatly reduces the
sensitivity to high pH fluids and high salt
• Coating each grain improves breaker
concentrations. While the core of SandWedgeTM
efficiency. When the proppant is coated with
remains the same, NT uses a safer and more
SandWedge, gel cannot coat the proppant.
environmentally friendly solvent than the
This property increases proppant
previous version. SandWedgeTM NT can thus be
conductivity in two ways. First the breakers
used in many more frac fluids because
are more efficient as they are able to break
incompatibility issues have been greatly
gels by having more “break” sites available
reduced.
to them and secondly, the proppant pack
itself is not susceptible to gel damage.
• Porosity improvement in low stress
environments. In closure stresses less than
4,000 psi, the porosity of the proppant pack, 5000
4500
when treated with SandWedge, retains its
Conductivity (md-ft)

4000
cubic porosity pattern. At this pattern, the 3500
3000
pack has about 48% porosity. At 4,000 psi 2500
2000 Fibrous Strips
closure, the majority of the pack is in a 1500
1000 20/40 Sand—No
rhombohedral packing and the pack porosity 500 Treatment
is reduced to 26%. In proppant packs, 0
2000
SandWedge
Treatment
3000 4000
porosity is directly related to permeability; Closure Stress, psi
6000
therefore, the higher the porosity the higher
the permeability of the pack.
Figure 6.16 -
• SandWedge alters vertical proppant
distribution during the settling process. A
further benefit of SandWedge’s tackiness is
that proppant tends to form in clumps or
bundles. This has the effect of causing the SandwedgeTMXS
proppant mass to maintain its cubic porosity
shape until acted on by closure forces SandWedgeTM XS is designed for wells in which
greater than 4,000 psi. This occurrence proppant flow back is identified as the primary
requires that frac fluid flow through the source for declines in production. The addition
mass rather than around it during settling. of 5% ER-1 will make SandWedgeTM NT 10-20
That impacts proppant settling in a positive times more sticky and greatly increase the
way. proppant packs resistance to flow back. If XS is

© 2005, Halliburton 6 • 36 Stimulation I

 Fracturing Fluids and Materials

run, a reduction in conductivity can be expected, added on-the-fly into the blender tub during a
in the range of 10-15%. SandWedge™ NT dry-coat treatment. The resin
additive increases the molecular weight of
Note SandWedgeTM XS is a conductivity
SandWedge™ polymer by partially crosslinking
enhancer, NOT a proppant flowback additive. It
it, greatly increasing its viscosity, tackiness, and
will not stop proppant flowback under harsh
resistance to high-velocity flow. Typically, ER-1
conditions of high flowback rates or high
resin is used at a concentration of 5%, based on
temperatures.
the SandWedge™NT volume. If high
concentrations of ER-1 resin are used with
ER-1 SandWedge™ polymer (>25%), a high-strength
thermoplastic polymer can result from the high
degree of crosslinking.
ER-1 resin is a clear, viscous liquid that is mixed
with SandWedge™ polymer before the job, or

Unit I Quiz

Fill in the blanks with one or more words to check your progress in Unit I.
1. What are three ways SandWedgeTM improves fluid flow through proppant?

_____________________________

_____________________________

_____________________________

2. The porosity of a proppant pack may be improved at closure stresses below __________ psi.

3. SandWedgeTM NT is an improvement over SandWedgeTM because it uses a ____________________

_____________________ method and because it has a safer, more environmentally friendly
____________________.

4. SandwedgeTM XS is designed for wells in which ____________________ ____________________ is

identified as the primary source for declines in production.

5. SandwedgeTM XS will not stop proppant flowback under harsh conditions of high
____________________ rates or high ____________________.

Now, look up the suggested answers in the Answer Key at the back of this section.

© 2005, Halliburton 6 • 37 Stimulation I

 Fracturing Fluids and Materials

Self-Check Test for Section 6

Mark the single best answer to the following questions.
1. A buffer is a mixture of ____________________ and ____________________ of these

____________________.

2. List a swelling clay. ____________________

3. Cla-Sta compounds are most effective in a __________ - __________.

4. Fluid loss additives are used to slow down the ____________________ of the fracturing fluid into the

formation.

5. Surfactants are ____________________ ____________________ agents. Surfactants have been

developed to ____________________ fluid retention in a formation.

6. Surfactants are classified into four major groups depending upon the nature of the water-soluble

group. What are they?

____________________

____________________

____________________

____________________

7. Wettability indicates whether a solid is coated with ____________________ or

___________________.

8. Sandstone is negatively charged and water wet. Which surfactant group will leave sandstone in a

water wet condition? ___________________

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 Fracturing Fluids and Materials

9. Name 2 factors that will affect the hydration rate of polymers.

___________________________________________

___________________________________________

10. What does a crosslinker do?

_____________________________________________________________________________

_____________________________________________________________________________

11. Name two variables dictate which crosslinker to use?

________________________________________

________________________________________

12. Name the 3 classes of chemical breaker we use

________________________

________________________

________________________

13. Enzyme breakers are only effective in a relatively narrow range of ____________________ and

________________ levels.

14. ViCon HT is of the group of ____________________ type breakers.

15. CAT-3 can be used to ________________ __________ break times.

16. What are 3 ways to stabilize gels?

____________________________________

____________________________________

____________________________________

17. Bacteria feeds on gel by releasing ____________________.

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 Fracturing Fluids and Materials

18. Which Halliburton product should be chosen if a “quick kill” biocide is needed? ________________

19. SandWedgeTM is sold as a ____________________ ____________________, not for

____________________ ____________________.

20. Which SandWedgeTM product is for dry coating proppant? ____________________

© 2005, Halliburton 6 • 40 Stimulation I

 Fracturing Fluids and Materials

Answer Key

Items from Unit A Quiz

1. low
2. acidity / basicity
3. 7
4. acids/salts/acids
5. BA-40

Items from Unit B Quiz

1. almost all
2. flow
3. permeability
4. 3 / 7
5. 7 / 6 / 5
6. temporary
7. pre / pad
8. plugging
9. water
10. water

Items from Unit C Quiz

1. sizereduces / pressure
2. permeability
3. Solids
4. Liquid
5. Solids
6. Sand
7. water\oil\acid
8. 20.40
9. enzyme breaker
10. highly permeable

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 Fracturing Fluids and Materials

Items from Unit D Quiz

1. surface active
2. higher
3. help prevent water blocks
help prevent the creation of emulsions between the injected fluid and the formation fluid
help stabilize emulsions when using an emulsified treatment fluid
aid in fluid recovery
4. Block (limit)
5. prevent / properly
6. Emulsion
7. Water soluble

Items from Unit E Quiz

1. Viscosity
2. Polymers
3. Semi – solids
4. 10 / 13
5. endosperm
6. salt sensitive
7. 1 / 3
8. friction reducers
9. natural products (cotton) / no / residue
10. viscosity / proppant transport
11. MO-85 / MO-86 / 1:1
12. Hydrocarbon / water

Items from Unit F Quiz

1. Polymer chains / molecular weight / viscosity
2. Polymer concentration
Metal ion type and concentration
pH
Shear
3. titaniumThermagel / accelerated
4. 2.0 / caustic
5. crosslinker / buffer
6. False

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 Fracturing Fluids and Materials

Items from Unit G Quiz

1. Minimize / maximize
2. Oxidizers / enzymes / acids
3. 140
4. ammonium persulfate
5. viscosity / uncrosslinking
6. Minimum volume (gal) =
3/7 (PWT x ABV)

= 3/7 (100,00 x .0452) = 1,937 gal

7. F < 120° F
8. A
9. Gel-Sta
Methanol
pH
10. TF

Items from Unit H Quiz

1. instability
2. dirty / mixing
3. enzymes
4. 7
5. first
6. One / first
7. Slow / metabolic
8. 11
9. Gel-Sta / neturalize

Items from Unit I Quiz

1. improves break efficiency
increases porosity
improves vertical distribution
2. 4,000
3. dry coating / solvent
4. proppant flowback
5. flowback / temperatures

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 Fracturing Fluids and Materials

Self-Check Test
1. acids / salts / acidsMixture of acids and salts of these acids and are resistant to pH changes
2. Smectite – Illite – Chlorite – Kaolinite – Mixed Layer
3. pre-pad
4. leakdoff
5. surface active / reduce
6. Anionic
Cationic
Nonionic
Amphoteric
7. oil / water
8. anionic
9. pH of the system,
amount of mechanical shear applied in the initial mixing phase
polymer concentration
salt concentration of the solution
10. Chemically links two or more polymer chains, increasing the effective molecular weight and viscosity
11. pH
polymer type
pump time
fluid temperature
12. Oxidizer
Enzyme
Acid
13. temperature / pH
14. oxidizers
15. speed up
16. Methanol
Gel Sta,
pH control
17. enzymes
18. BE-3 or BE-3S5 (or CAT-1)
19. conductivity enhancer / proppant flowback
20. SandWedgeTM NT

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Section 7

Nitrogen/Carbon Dioxide and

Foam Fracturing

Table of Contents
Introduction ................................................................................................................................................ 7-5
Topic Areas ............................................................................................................................................ 7-5
Learning Objectives ............................................................................................................................... 7-5
Unit A: Physical Properties of Nitrogen (N2) ............................................................................................ 7-6
Nitrogen Properties................................................................................................................................. 7-6
Nitrogen Factors ..................................................................................................................................... 7-7
Additional Reference.............................................................................................................................. 7-7
Unit A Quiz ............................................................................................................................................ 7-8
Unit B: Nitrogen (N2) Services .................................................................................................................. 7-8
Applications for Nitrogen....................................................................................................................... 7-9
Foam Frac Services .............................................................................................................................. 7-10
Pumping Units ...................................................................................................................................... 7-11

.............................................................................................................................................................. 7-11
Additional References .......................................................................................................................... 7-12
Unit B Quiz .......................................................................................................................................... 7-13
Unit C: Safety with Nitrogen ................................................................................................................... 7-14
Safety Precautions for Handling Nitrogen ........................................................................................... 7-14
Liquid Air Hazard ................................................................................................................................ 7-14
Symptoms of Oxygen Deficiency ........................................................................................................ 7-15
Effect of Trapping Liquid Nitrogen ..................................................................................................... 7-15
Nitrogen Rig-Up and Test Procedure ................................................................................................... 7-16
Pressure Test ........................................................................................................................................ 7-16

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 Nitrogen/Carbon Dioxide and Foam Fracturing

Pumping Procedure / Treating Iron Low Temperature Limits ............................................................. 7-16

Emergency Shut Down Procedures ...................................................................................................... 7-17
Shutdown Procedure............................................................................................................................. 7-17
Unit C Quiz .......................................................................................................................................... 7-18
Unit D: Material and Components Used in Handling Nitrogen ............................................................... 7-19
Non-Cryogenic Materials ..................................................................................................................... 7-19
Cryogenic Materials ............................................................................................................................. 7-19
Unit D Quiz .......................................................................................................................................... 7-20
Unit E: Sample Nitrogen Problems .......................................................................................................... 7-21
Definitions ............................................................................................................................................ 7-21
Thermal Gradients ................................................................................................................................ 7-21
Example Problems................................................................................................................................ 7-22
Unit E Quiz........................................................................................................................................... 7-24
Unit F: Physical Properties of Carbon Dioxide (CO2) ............................................................................. 7-25
Applications of Carbon Dioxide........................................................................................................... 7-25
Carbon Dioxide Factors........................................................................................................................ 7-25
Additional References .......................................................................................................................... 7-26
Unit F Quiz ........................................................................................................................................... 7-27
Unit G: Chemical Properties of Carbon Dioxide (CO2)........................................................................... 7-28
Carbonic Acid ...................................................................................................................................... 7-28
Designing CO2 Well Treatments .......................................................................................................... 7-28
Additional References .......................................................................................................................... 7-29
Unit G Quiz .......................................................................................................................................... 7-29
Unit H: Safe Handling and Pumping of CO2 ........................................................................................... 7-30
CO2 Injection ........................................................................................................................................ 7-30
Pretreatment Meeting ........................................................................................................................... 7-30
Spotting Equipment .............................................................................................................................. 7-31
CO2 Rig-Up .......................................................................................................................................... 7-31
Purging the CO2 System ....................................................................................................................... 7-32
Pressure Test and Cool Down .............................................................................................................. 7-33
Pumping Procedure .............................................................................................................................. 7-34
Shutdown.............................................................................................................................................. 7-34
Controlling the Separator ..................................................................................................................... 7-34
Starting and Stopping Boost Pumps during Operation......................................................................... 7-35
Shutting Down CO2 Boost Operations ................................................................................................. 7-36
Unit H Quiz .......................................................................................................................................... 7-37
Unit I: Sample CO2 Problems .................................................................................................................. 7-38
Additional References .......................................................................................................................... 7-39
Unit I Quiz ............................................................................................................................................ 7-42
Unit J: Foam Fracturing ........................................................................................................................... 7-43
Foam ..................................................................................................................................................... 7-43
Foam Quality ........................................................................................................................................ 7-43
Foam Stability ...................................................................................................................................... 7-44
Low Liquid Content ............................................................................................................................. 7-44
Fluid Loss ............................................................................................................................................. 7-44
Proppant Transport ............................................................................................................................... 7-44
Built-In Gas Assist ............................................................................................................................... 7-44
Minimum Well Clean Up Time ............................................................................................................ 7-44
Foam Types .......................................................................................................................................... 7-44
Proppant Concentration ........................................................................................................................ 7-45
Breakers in Liquid Phase...................................................................................................................... 7-45

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 Nitrogen/Carbon Dioxide and Foam Fracturing

Foaming Agents ................................................................................................................................... 7-45

Foamed Acid ........................................................................................................................................ 7-45
Unit J Quiz ........................................................................................................................................... 7-47
Unit K: Flow back of Energized Fluids ................................................................................................... 7-48
Procedures ............................................................................................................................................ 7-48
Unit K Quiz .......................................................................................................................................... 7-49
Self Check Test for Section 7 .................................................................................................................. 7-50
Answer Keys ........................................................................................................................................ 7-54
Self-Check Test .................................................................................................................................... 7-57

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 Nitrogen/Carbon Dioxide and Foam Fracturing

Use for Section notes…

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 Nitrogen/Carbon Dioxide and Foam Fracturing

Introduction
Nitrogen (N2) or carbon dioxide (CO2) is often
injected along with other fluids during the Learning Objectives
stimulation treatment to help remove silt,
reaction products, and formation fines from the
well bore. Their uses frequently result in greater After completing this section, students will be
fracture flow capacity, higher well productivity, able to:
and quicker clean ups after treatment. Describe types of service operations for
nitrogen
Topic Areas Describe major safety considerations in
using nitrogen
The section units are: Describe major safety considerations in
1. Physical Properties of Nitrogen using liquid carbon dioxide

2. Nitrogen Services Match the physical properties of CO2 and

N2 from a list of fluid physical properties
3. Safety with Nitrogen
Identify pumping operations that apply to
4. Material and Components Used in pumping CO2 and N2
Handling Nitrogen
Calculate the following:
5. Sample Nitrogen Problems
a) Pipe displacement, nitrogen
6. Physical Properties of Carbon Dioxide requirement
7. Chemical Properties of CO2 b) Concentration of sand in the
8. Safe Handling & Pumping of CO2 blender tub when you know the
sand concentration in the foam
9. Sample CO2 Problems system
10. Foam Fracturing c) Bottom hole treating pressure
11. Flow back of Energized Fluids (BHTP) with commingled CO2
fluid columns given the
instantaneous shut-in and
temperature gradient.

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 Nitrogen/Carbon Dioxide and Foam Fracturing

Unit A: Physical Properties of Nitrogen (N2)

The use of nitrogen gas in the oilfield began in
1956. Its initial use was as a gas cushion to
control well-flowing pressures during drill stem
tests. Although quantities and pressures were
limited, this service did allow control of well
liquids and pressures by use of an inert gas.
With the introduction in 1959 of cryogenic
transports and pumps that could pump and
transport nitrogen in the liquid state, service was
expanded. Nitrogen helps speed treating fluid
recovery, reducing rig time and improving
results. It can also be used in generating
fracturing foam, especially valuable for low
permeability, low pressure, and water sensitive
formations.

Nitrogen Properties

Nitrogen is a valuable aid in almost all types of

oil and gas well service procedures. It has
several unique properties since it: Figure 7.1 - Equilibrium Curve for Nitrogen
is an inert gas (does not readily react with
other elements)
The vapor density of nitrogen at 70°F and 14.7
does not react adversely with treating or psi is .0724 lbs. per cubic foot. The solubility of
formation fluids N2 in various treating fluids is extremely low.
is slightly soluble in water, oil and most For oil field work, N2 is liquefied (LN2) and
other liquids transported in insulated transports at
approximately –320°F and 15 psi. Since N2 is
remains in bubble form to help lift fluids
non-flammable, there is no danger of fire or
from the well bore when commingled with
explosion.
liquids
You might have LN2 stored in your field
is colorless and is brought to location in
location. Insulated LN2 containers work just
liquid form
like a thermos bottle. A small amount of LN2
is converted to gas at controlled rates, converts to gas continuously. A Road Relief
pressures and temperatures valve, installed on each unit, keeps the tank
pressure below 15 psi. It is normal for these
tanks to vent excess pressure automatically.

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 Nitrogen/Carbon Dioxide and Foam Fracturing

Molecular Symbol ...................................... N2

100 212 Water Boils (Steam) Molecular Weight ................................ 28.016
Normal Boiling Point...................... -320.36°F
Critical Temperature (Tc)............... - 232.85°F
Critical Pressure ................................ 492.3 psi
20 70 Room Temperature
Density Gas @ 70°F, 1 atm ........ 0.0724 lb/ft3
0 32 Water Fr eezes (Ice) Density Liquid @ Boiling Point
.................................. 50.45 lb/ft3, 6.74 lb/gal
Density Vapor @ Boiling Point
................................ 0.280 lb/ft3, .0374 lb/gal
Cryogenic Range
Expansion Ratio
-78.4 -109.3 CO2 Subli mes (Dry Ice)
............................ 696 : 1 (SCF : ft3 of liquid)
Critical temperature is –232.4°F and critical
pressure is 492.9 psi (Figure 7.1). Normal
boiling point is –320.36°F. The cryogenic
thermometer (Figure 7.2) shows the
-161.5 -258.7 Methane extraordinarily cold nature of liquid nitrogen.
-183.0 -297.3 Oxygen Note that a difference in temperature of 180°F
-185.9 -302.6 Argon
-195.8 -320.4 Nitrogen
exists between ice and boiling water. The 390°F
temperature difference between liquid nitrogen
and 70°F room temperature is more than twice
as great.
-246.1 -410.9 Neon
-252.8 -423.0 Hydrogen Halliburton has developed original data tables
-268.9 -410.9 Helium for designing and planning well servicing
-273.16 -459.7 Absolute Zero
procedures using nitrogen. The data produced
Figure 7.2 - Cryogenic Thermometer are based on actual downhole conditions. For
instance, instead of using average temperatures,
the tables permit treatment design with actual
temperature gradients (see Figure 7.8.) This
technique can often make a substantial
Nitrogen Factors difference in job design and results.

Each gallon of liquid nitrogen weighs 6.74

pounds and is equivalent to 93.11 standard cubic Additional Reference
feet of gas. One cubic foot of liquid nitrogen
contains 7.48 gallons and weighs 50.42 pounds. Halliburton Services Personnel Training Video
It is equal to 696.46 standard cubic feet of gas. ―Cryogenic Safety‖ 30 minutes.
That is, it will equal 696.46 cubic feet at 1 I Learn Module ―Basic Nitrogen Safety‖ 2 hours
atmosphere of pressure at 70°F. Standard refers Nitrogen WiSER – Virtual equipment Simulator
to using a standard of measurement. So for gas, for the TPU – 660 unit.
the standard is 1 atmosphere pressure (14.7 psi
at sea level) and 70°F. In liquid form, it is myhalliburton.com – PE equipment Portal
convenient and economical to increase pressure
of the liquid by using positive displacement
pumps. Other nitrogen factors are listed below:

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 Nitrogen/Carbon Dioxide and Foam Fracturing

Unit A Quiz

Fill in the blanks with one or more words to check your progress in Unit A.
1. List six of the unique properties of nitrogen:

_________________________________________________

_________________________________________________

_________________________________________________

_________________________________________________

_________________________________________________

_________________________________________________

2. Nitrogen is delivered to location in ___________________________ form and converted to a

________________________ under controlled rates, pressure and temperature.

3. What is the weight of one gallon of liquid nitrogen?

_____ a) 6 lb/gal

_____ b) 10 lb/gal

_____ c) 6.74 lb/gal

_____ d) 8.33 lb/gal

4. One U.S. Standard gallon of liquid nitrogen will yield

_____ a) 7.48 standard cu. ft. of gas

_____ b) 69.61 standard cu. ft. of gas

_____ c) 178.12 standard cu. ft. of gas

_____ d) 6.74 standard cu. ft. of gas

_____ e) 93.11 standard cu. ft. of gas.

5. The normal boiling point of nitrogen is _______ °F.

Now, look up the suggested answers in the Answer Key.

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 Nitrogen/Carbon Dioxide and Foam Fracturing

Unit B: Nitrogen (N2) Services

Nitrogen used with fracturing and acidizing
services gives more complete treatment fluid Density Control
recovery without swabbing. In most cases, even
in low-pressure reservoirs, N2 use eliminates the Nitrogen can be used in density controlled
need for time-consuming and sometimes acidizing or fracturing services to reduce the
dangerous swabbing to recover treatment fluid. density of the stimulation fluids. Since the
Nitrogen gas used as the spearhead, or in the created fracture may extend below the
breakdown fluid in fracturing, helps push the productive zone, commingled nitrogen in the
treatment fluid back out of the formation. appropriate liquid phase can effectively lighten
the fluid to enable its placement in the upper
portion of the fracture or productive zone.
Applications for Nitrogen
Workover Services
Cushion for Drill Stem Testing
Jetting with nitrogen can greatly aid treating
fluid recovery and reduce costs. Jetting can be
Even when nitrogen is not needed to prevent done either down the tubing and out the annulus
collapse of drill pipe, it can help improve the or down the annulus and out the tubing. Usually,
accuracy of drill stem test results. With nitrogen maximum recovery results from pumping
in the drill pipe, there is no question that any nitrogen down the tubing at a constant rate while
recovered fluid came from the formation. Also, maintaining back pressure on the annulus. This
recovered fluids are not diluted as with a water process causes high fluid velocities by making
cushion. Nitrogen can play a vital role more efficient use of the expansion properties of
throughout the test by: nitrogen. Jetting advantages are:
Pressuring the test string from the surface reduced rig time
to check for leaks before the tester is
opened improved wellbore conductivity
Preventing a sudden release of pressure at reduced danger of sticking swab cups
the formation face when the tester is quicker return on investment
opened. This helps reduce sloughing of
the formation. lower returning fluid cost
The combination of nitrogen and coiled tubing
Leak Testing services allows many completion, workover and
remedial services to be performed faster and at
Nitrogen leak testing can be a valuable less cost than previously possible. These
supplement to conventional hydrostatic tests, combinations of nitrogen and coiled tubing
especially in tubular goods intended for critical services may eliminate the need for a costly
applications. After the string or wellhead is workover unit to swab the well and the need to
hydrostatically tested, all couplings and joints pull tubing. Nitrogen circulation through
are leak tested with nitrogen. If the joints do not continuous tubing will:
leak nitrogen, they can usually be counted on not
clean out well bore debris
to leak oil or natural gas.
unload low pressure gas wells

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 Nitrogen/Carbon Dioxide and Foam Fracturing

circulate fluid from the well prior to Well Fire Control

perforating
remove sand remaining in the well bore Nitrogen can be used to extinguish certain well
after fracturing fires. If an oil or gas well catches fire,
noncombustible nitrogen gas can be pumped
gas lift fluids during testing into and around the flame to produce a
displace chemicals into the formation noncombustible mixture by lowering the oxygen
content of the air to less than 10 percent.
By reducing workover fluid density, nitrogen Nitrogen can also put out a natural gas blaze
helps reduce fluid loss to formations. This is when the concentration of nitrogen in the natural
especially helpful in low pressure wells. gas is increased above 30 percent.
Nitrogen-laden workover fluids retain high
lifting capabilities at minimum circulating Annulus Insulation
pressures.
With the use of nitrogen and a lubricator, the Paraffin precipitation and deposits in the
pressure within the wellbore can be controlled production string can be caused by heat loss
while perforating. Correct application can from the production fluid to the cooler
virtually eliminate the chance of perforation formations. Fluids in the tubing casing annulus
debris entering the formation by excess provide very little insulation to prevent heat loss.
hydrostatic pressure. Nitrogen in the annulus can help reduce or
Nitrogen is used to displace the well fluid from eliminate paraffin deposits. In steam injection
the tubing when a well is ready to be perforated. and geothermal wells, energy can be conserved
The packer is set, the gun positioned, and the and condensation reduced by using nitrogen as
well pressured with nitrogen. After firing, the insulation in the annulus.
gun is removed through a lubricator. The
nitrogen is slowly bled to the atmosphere to help Freeing Differentially Stuck Drill Pipe
bring in the well. Swabbing is not usually
required. Nitrogen, when commingled with drilling mud,
temporarily reduces fluid density, which reduces
Placing Corrosion Inhibitors the hydrostatic pressure against the pipe and
allows it to pull free. Another technique is to
There are two effective methods of placing spot nitrogen gas over the zone where the pipe is
corrosion inhibitors with nitrogen. First, stuck. The low viscosity of the gas causes the
nitrogen is used to create an inhibitor mixture or pressure to equalize around the pipe, allowing it
foam. Tubing fluid is displaced into the to pull free. Nitrogen quickly dissipates from
formation by the inhibitor mixture, resulting in drilling mud on return to the surface, allowing
the tubing being filled with the nitrogen. quick return to heavier weights.
Pressure is maintained to allow the inhibitor
time to deposit on the tubing wall. The nitrogen
is then bled off and the well put back on
Foam Frac Services
production. Shut-in time is held to a minimum.
The inhibitor is much more likely to stick on the In the Foam-Frac service, nitrogen gas is
tubing because swabbing and displacement are injected downstream of the pumps into a water-
eliminated. base fluid containing a foaming agent. In most
jobs, nitrogen volume ranges between 65 and 85
By the second method, the inhibitor is displaced percent of the total volume. The proppant
into the formation with nitrogen gas. The transport and rheological characteristics of the
nitrogen allows the well to be placed on foam are excellent. However, because the low-
production faster by eliminating or reducing density foam produces less hydrostatic pressure
swabbing time.

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 Nitrogen/Carbon Dioxide and Foam Fracturing

and because foams have a high amount of capabilities. The model designation used is
friction, the wellhead pressure will be higher. primarily for U. S. service under the authority of
This can increase the HHP requirements. Since the joint Halliburton / Praxair venture company
the foam bubbles help block small pore spaces, of Wellnite Services. The first three letters are a
fluid loss control is obtained without the use of prefix that states the type of unit. For instance,
fluid loss additives. This helps reduce formation TPU stands for trailer pumping unit while SPU
damage that could be caused by the fluid loss stands for skid pumping unit. The numbers
additive. Also, because of its lighter density and usually stand for the maximum amount of
expansion properties, cleanup after the nitrogen the unit can pump in one hour. For
stimulation treatment is much faster and more instance, the MPU 90A should be able to pump
fluid can be recovered. 90,000 SCF of Nitrogen in one hour if the
pressure is low enough for it to maintain it’s
maximum rate. Any letter after the numbers
Pumping Units signifies a model of that unit, except for the
letter ―F‖ which indicates that the unit is
Table 7.1 lists some of the currently used ―flameless‖ or carries a non-open-flame heater.
Halliburton nitrogen pumping units and their

Normal
Deliverable Maximum Maximum
Volume of N2 Designation Rate Minimum Rate Pressure
160,000 SCF MPU 60 1000 SCF/min 100 SCF/min 10,000 psi
250,000 SCF MPU 90A 1500 SCF/min 100 SCF/min 10,000 psi
250,000 SCF TPU 300A 5000 SCF/min 300 SCF/min 15,000 psi
250,000 SCF TPU 340F A 5666 SCF/min 300 SCF/min 15,000 psi
* S120-15F 1666 SCF/min 100 SCF/min 15,000 psi
* SPU 180 3000 SCF/min 100 SCF/min 15,000 psi
250,000 SCF TPU 660 11,000 SCF/min 800 SCF/min 10,000 psi
Table 7.1- Nitrogen Pumping Equipment
* Skid tanks can be several sizes.

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 Nitrogen/Carbon Dioxide and Foam Fracturing

Figure 7.3 – TPU-340A nitrogen pumper

Figure 7.4 - SPU-60B nitrogen pumper

Additional References
Halliburton Foam Stimulation, NS 113

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 Nitrogen/Carbon Dioxide and Foam Fracturing

Unit B Quiz

Answer the following questions to check your progress in Unit B.

1. List seven applications for nitrogen services.
__________________________________________________________________________
__________________________________________________________________________
_________________________________________________________________________
_________________________________________________________________________
__________________________________________________________________________
_________________________________________________________________________
__________________________________________________________________________
2. What are five advantages of jetting with nitrogen in workover service?
_________________________________________________________________
_________________________________________________________________
_________________________________________________________________
_________________________________________________________________
_________________________________________________________________

Now, look up the suggested answers in the Answer Key.

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 Nitrogen/Carbon Dioxide and Foam Fracturing

Unit C: Safety with Nitrogen

Nitrogen is a colorless, odorless and tasteless long sleeve shirts
gas that makes up 78% of the air we breathe. In
liquid form, it is extremely cold and is cuffless trousers
―cryogenic,‖ which refers to its very cold nature. Avoid Skin Contact
Liquid nitrogen under normal atmospheric
pressure is 320°F below zero. This can freeze liquid leaking from equipment
flesh instantly upon contact. Even though cold equipment surfaces
nitrogen and cryogenic equipment are different
from other service equipment, their use is not Protect Your Eyes
considered dangerous if handled and operated liquid nitrogen causes immediate damage
properly. Safety should always be first priority
and this unit discusses safety measures involved eye damage is usually beyond repair and can
in nitrogen service procedures. cause permanent blindness
First Aid Procedures for Freeze Burns
Safety Precautions for Handling A freeze burn should be treated as follows:
Nitrogen 1. Remove clothing that may constrict
blood circulation to affected body area.
2. Immediately flood or submerge the
Skin and Eye Protection affected body area with large quantities
of clean, unheated water.
Liquid nitrogen is hazardous. If contact is made
with human tissue, its severely cold properties 3. Apply cold compresses.
will destroy skin in a manner similar to high heat 4. Get patient to a physician for treatment.
temperature burns. Burns will also result when
contact is made with the cold surfaces of piping
and other equipment containing the liquid. This Liquid Air Hazard
danger increases when liquid nitrogen is under
pressure. These facts emphasize the need for Nitrogen jobs may present some unusual
protective clothing and a good safety attitude on conditions you should learn to recognize. The
the part of the nitrogen operator. Wearing safety boiling point of nitrogen is lower than the
goggles or a face shield can protect you if the boiling point of oxygen. Liquid air will rapidly
liquid sprays or splashes and from the cold gas become oxygen enriched. This condensed liquid
that may be discharged under pressure from air forming on pumps and manifolds may
equipment. Wearing clean, insulated gloves that contain approximately 52% oxygen. This
can be easily removed and long sleeves are oxygen-enriched air causes normally non-
recommended for hand and arm protection. combustible material to become flammable and
Pants with no cuffs should be worn outside normally flammable material to burn at an
boots or over shoes to shed spilled liquid. The increased rate. A dangerous situation to watch
key safety measures are: for on a nitrogen job is when, under extremely
Wear Protective Clothing dry air conditions, suction lines may appear wet
instead of frosted. This is formed by liquid
safety goggles oxygen condensing from the surrounding air.
insulated gloves Also, keep cigarettes or other flammable

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 Nitrogen/Carbon Dioxide and Foam Fracturing

materials away from lines wet with liquid As seen above, a slight oxygen deficiency
oxygen. results in deeper respiration, faster pulse and
poor coordination. As the oxygen deficiency
increases, judgment becomes so poor that an
Symptoms of Oxygen individual may not know to move to a well-
Deficiency ventilated area. One full breath of pure nitrogen
can strip blood of necessary oxygen and cause
Oxygen is necessary for us to function. immediate loss of consciousness.
Expanding nitrogen displaces normal air without Be very careful when checking levels in a frac
warning. Although nitrogen is a nontoxic, tank on flow back. Nitrogen returning with the
nonflammable gas, it can cause asphyxiation in frac fluid will displace the oxygen from the tank.
an area without adequate ventilation. All liquid If you breathe air with less than 6% oxygen your
containers should be stored outdoors in well- body will react almost instantaneously and cause
ventilated areas. The normal oxygen amount in you to lose consciousness. Do not think you can
air at sea level is 21%. Table 7.2 shows what hold your breath or that only a breath or two will
happens when certain percentages of oxygen are not matter! Immediate asphyxiation may result.
remaining in the air at 14.7 psi total pressure. If someone should fall into the tank, do not try to
rescue him without first taking some
Oxygen Content Effects and Symptoms of acute
exposure (at Atmospheric Pressure) precautions. Before entering the tank, stop the
gas and allow the tank to refill with air, or use an
% by Effects and Symptoms air pack. Tie a safety rope to the waist of any
Volume operator checking fluid levels on a tank.
15-19% Decreased ability to perform tasks. May
impair coordination and may induce early
symptoms in persons with head, lung, or
Effect of Trapping Liquid
circulatory problems. Nitrogen
12-15% Breathing increases, especially in
exertion. Pulse up. Impaired coordination, Trapped liquid nitrogen absorbs heat and can
perception, and judgment. exert pressure in excess of 20 tons per square
inch. This fact explains why Halliburton’s
10-12% Breathing further increases in rate and pumping systems are designed to use a safety
depth, poor coordination and judgment,
lips slightly blue.
relief valve any place where nitrogen can be
trapped.
8-10% Mental failure, fainting, unconsciousness,
ashen face, blueness of lips, nausea
(upset stomach), and vomiting.

50.46 lb 50.46 lb
6-8% 8 minutes, may be fatal in 50 to 100% of of Liquid Nitrogen of Nitrogen
cases; 6 minutes, may be fatal in 25 to -320ºF, 0 psi 70ºF, 42,500 psi
1 ft3 1 ft3
50% of cases; 4-5 minutes, recovery with
treatment.

4-6% Coma in 40 seconds followed by Figure 7.5 - Nitrogen Liquid to Gas

convulsions, breathing failure, death.
Expansion Rate Example
Exposure to atmospheres containing 8-10% or
less oxygen will bring about unconsciousness
without warning and so quickly that the If liquid nitrogen is trapped between two valves
individuals cannot help or protect themselves.
in a manifold or hose, the effect of liquid turning
Table 7.2 – Oxygen Deficiency Symptoms to vapor may cause pressure over 42,000 psi
(Figure 7.5)

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 Nitrogen/Carbon Dioxide and Foam Fracturing

Nitrogen Rig-Up and Test

Procedure

Job Set-Up

Perform proper risk assessment.

Spot trucks upwind from well, if possible
and note wind direction..
Figure 7.7 - Nitrogen Rig-Up Procedure —
Connect the discharge manifold as Two N2 Pumper
illustrated in Figures 7.6 and 7.7. The two
check valves in series in the nitrogen line
are to prevent water or acid from flowing
back to the nitrogen pump. The bleed valve
must be downstream of both check valves Pressure Test
to prevent trapped pressure. A stop valve
should always be placed between the Nitrogen treating lines and manifolding should
nitrogen manifold and the fluid line or be pressure tested with nitrogen, not exceeding
wellhead. the working pressure of the lines. The
preference is to pressure test other surface
If the nitrogen is being mixed with fluid,
treating lines and manifolds first with a non-
then tee the two together as close to the
compressible fluid as opposed to nitrogen. This
wellhead as possible. A check valve should
will help minimize potential risks due to a line
be used in the fluid line just upstream of the
failure with a compressible gas. Only
nitrogen connection.
designated personnel are to inspect the N2 lines.
If the nitrogen is connected directly to the Never use your hand to check for a leak. Use a
wellhead, inspect all wellhead connections rag or soapy water to find leaks in N2 lines.
to ensure their pressure rating/integrity.
This inspection is extremely important if
the wellhead has pipe thread type Pumping Procedure / Treating
connections. Iron Low Temperature Limits
Have one person check to make sure all valves
are in the correct position before the pumping
starts. There should also be one person chosen
to observe all manifolding during the pumping
operation. The temperature of nitrogen
discharged into the treating lines should be
around 70-100°F. However, if a heater on a
nitrogen pump fails, this temperature can
quickly drop. At -40°F, a sudden impact or
pressure pulse could cause a minor crack to turn
Figure 7.6 - Nitrogen Rig-Up Procedure — into a major failure. If the discharge lines frost
One N2 Pumper up on a nitrogen pumping job at any time,
execute an emergency shut-down and exit the
area immediately. After the carbon steel has
warmed up, it will return to its previous state.

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 Nitrogen/Carbon Dioxide and Foam Fracturing

However, all iron that has been frosted up There are many other steps which must be taken
should be inspected for damage. care of at some point, depending upon the
severity of the emergency. Refer back to the
Unit Operator’s manual for your specific unit for
Emergency Shut Down exact procedure.
Procedures

In the event of an emergency, be prepared to

Shutdown Procedure
shut the equipment down fast. Many N2 units
come equipped with an Emergency Kill button. At the end of the job, close the stop valve
The main objective is to bring the unit off-line, between the nitrogen manifold and the wellhead
isolate it from the wellhead and leave the tank, or fluid lines. This prevents fluid from entering
pump and lines in a safe condition. the nitrogen iron. Then bleed the pressure off the
nitrogen manifold with the bleeder tee.
There are five major steps to be followed in
order: Remember: treated iron or carbon steel will not
withstand cryogenic temperatures. Even a slight
disengage the pump drip can be enough to damage steel permanently
close the discharge valve if it is cracked while frozen. If you think liquid
nitrogen has been pumped into the lines or
open the prime up valve manifolds then disassemble and inspect for
turn off the vaporizer cracks. If you need to X-ray and do not have
access to the proper equipment, call Duncan
close the suction valve Engineering.

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 Nitrogen/Carbon Dioxide and Foam Fracturing

Unit C Quiz

Fill in the blanks with one or more words or answer the following questions to check your progress
in Unit C.
1. ____________________ _____________________ will result from contact with the actual liquid
nitrogen; eye damage is usually beyond repair.

2. 50.46 lbs. of trapped N2 liquid at –320°F psi will take on heat and can build pressures in excess of
________________ psi at 70°F.

3. The normal amount of oxygen in the air at sea level is

_______ a) 10%
_______ b) 90%
_______ c) 25%
_______ d) 21%

4. At an oxygen concentration of 6-8%, how long does it take for a person to die? __________

5. What five steps should be taken if a nitrogen pump must be shut down during an emergency?

__________________________ __________________________ _____________________

____________________________________ ___________________________________

6. If you think liquid N2 has been pumped into discharge lines, what should be done?

_______________________________________________

Now, look up the suggested answers in the Answer Key.

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 Nitrogen/Carbon Dioxide and Foam Fracturing

Unit D: Material and Components Used in Handling

Nitrogen
Extreme low temperatures adversely affect most Non-Cryogenic Non-Cryogenic
construction materials. Since a liquid nitrogen Materials Components
spill on a storage tank or any regular steel could carbon steels treating iron
cause the tank or steel to fracture and fail if cryogenic tank casing
stressed while frozen, components engineered low alloy steels
trailer frame
for use in cryogenic service must be chosen most rubber materials trailer frame
from approved materials.
most plastics power train

structural components
Non-Cryogenic Materials hydraulic lines
Table 7.3 - Non-Cryogenic Materials and
At cryogenic temperature, regular steel becomes Components
as brittle as glass and can easily be shattered.
Keep leaking liquid nitrogen away from truck
tires, chassis, boat decks and offshore platforms.
Allowing liquid nitrogen in the carbon steel
The extreme cold temperatures could weaken
treating iron is one of the most dangerous
and fracture any of these structures. Because of
mistakes an operator can make. Carbon steel
this, be extremely cautious when working with
becomes brittle at around –40°F. When this
discharge lines. Constantly monitor and
occurs, any shock could cause treating iron to
maintain discharge temperatures between 70°
break like glass.
and 100°F. If these lines frost up, either stop
pumping or increase heat. If the vaporizer stops
working, do not continue pumping. Introduction Cryogenic Materials
of liquid nitrogen into discharge lines can cause
a failure due to differential contraction. The cold
liquid nitrogen causes the inner wall of the pipe Pumps and manifolds are made from materials
to shrink. This action within a pipe could result such as copper, brass, bronze and non-magnetic
in an explosion if the pipe is under pressure. stainless steel, which are materials that can
Another possible hazard is that the pipe could withstand cryogenic temperatures (Table 7.4).
fracture at a later time. Materials Components

Know where your bleed-off valves are. If the inner tank of nitrogen
copper and its alloys
tank
pressure rises above safe levels, release the
pressure immediately. Do not rely upon the non magnetic stainless nitrogen low pressure
steels piping
safety pop-offs. If a gauge indicates that
pressure is rising at an unusually high rate of aluminum nitrogen fluid ends
speed, vent off immediately and then check the high pressure piping
reason. Do not try to find the problem until the high nickel steels up to the vaporizer
outlet
pressure has been bled-off. Most of the
components of nitrogen pumping units are made brass
up of materials that cannot withstand cryogenic bronze
temperatures (Table 7.3). Do not expose these Table 7.4 - Cryogenic Materials and
components to extreme cold. Components

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 Nitrogen/Carbon Dioxide and Foam Fracturing

Unit D Quiz

Fill in the blanks or select the correct answer to check your progress in Unit D.
1. Carbon steel becomes brittle at approximately ________________. When this occurs, any shock such
as hitting the treating iron could cause the iron to break like glass.

2. From the list below, make a check mark to identify the cryogenic material(s).

________a) Copper
________b) Carbon steel
________c) Non magnetic stainless steel
________d) Aluminum
________e) Rubber

3. N2 discharge temperature should be kept between __________°F and __________°F.

4. Cold liquid nitrogen can cause the inner wall of a pipe to ____________________ and cause the pipe
to _______________________.

Now, look up the suggested answers in the Answer Key.

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 Nitrogen/Carbon Dioxide and Foam Fracturing

Unit E: Sample Nitrogen Problems

Calculating the amount of nitrogen necessary for run StimWin - N2calcs subpackage. For these
various treatments requires some complicated problems we are referring to the tables.
equations. There are two ways to make these
calculations. ―Nitrogen Data for Oil Well
Servicing‖ is a set of tables for figuring nitrogen Definitions
requirements for commingled fluids and straight
nitrogen displacement. The second method is to Below are definitions of many of the values used
in calculating nitrogen requirements.
Symbol Typical Units
Q -Quality- Volumegas = Volumegas %
Volumefoam Volumegas + Volumeliquid
VLR - Volume Liquid Ratio- Actual Volume Mix none
Actual Volume Liquid
GLR - Gas Liquid Ratio Standard Volume Gas SCF/BBL
Volume Liquid
V’/V - Volume Factor- Standard Volume Gas SCF/BBL
Actual Volume Gas
WHP - Well Head Pressure- psi
BHP - Bottom Hole Pressure- psi
BHTP - Bottom Hole Treating Pressure- psi
BHFP - Bottom Hole Flowing Pressure- psi
ISIP - Instantaneous Shut-in Pressure- psi
BHST 80 F
Thermal Gradients F
Form Depth ft Thermal Grad
100ft
Because temperature has such a great effect on
nitrogen and CO2 calculations, the bottom hole Example:
temperature must be known. Most formations in You are going to treat a well with a thermal
an area have thermal gradients associated with gradient of 1.5°F/100 ft. The middle of the
them. These gradients are expressed as degrees formation is 5500 ft. What is BHST?
Fahrenheit per one hundred feet of depth
(°F/100 ft). The following equation can be used Solution:
to calculate the bottom hole static temperature 1.5 F
(BHST) if the thermal gradient is known: BHST 80 F 5500ft
100ft
80 F 82.5 F
162.5 F

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 Nitrogen/Carbon Dioxide and Foam Fracturing

Example Problems gradient of 1.6°F/100 ft. If the wellhead ISIP is

1500 psi, find the bottom hole treating pressure.
Procedure:
Problem 1
Look at data for 500 SCF/bbl nitrogen with a
thermal gradient of 1.6°F/100 ft.
Calculate the volume of nitrogen and final WHP
to displace a foam frac down 2 7/8‖ 6.5 lb/ft Solution:
tubing. The well is 5000 ft. deep with a frac
On Figure 7.7, with a WHP of 1500 psi and
gradient of 0.6 psi/ft. The thermal gradient is
depth of 6000 ft we find a bottom hole pressure
1.1°F/100 ft.
= 3266 psi.
Procedure:
1. Calculate BHTP. Problem 3
2. Calculate tubing capacity.
In this example, calculate the total foam volume
3. Look up data. when we know the liquid and foam quality.
4. Calculate nitrogen volume. Quality of Foam = Q
(75 Quality = 0.75)
Solution:
Volume of Water/Acid = W
1.
W
BHTP F.G. depth Total Volume of Foam = (1 Q)
psi
0.6 5000ft
ft Example
3000psi
W = 95 bbl Acid
2. From the Cementer’s Handbook, the Q = 0.80 (80 Quality)
capacity of 2 7/8‖ tubing is found to be
0.00579 bbl/ft. 95 bbl
Total Foamed Acid Vol
bbl 1 - 0.80
Tubing Volume 0.00579 5000ft 95bbl
ft
28.95 bbl 0.2
3. In Figure 7.6 locate 5000 ft. under the
depth column. Read across the page until
you reach the 3000 psi BHP column. The Problem 4
well head pressure is 2575 psi and the
volume factor (V’/V) is 949 SCF/bbl. In this example we will calculate the volume of
4. liquid needed for a given volume of foam.
SCF Quality of Foam =Q
N 2 Volume 28.95 bbl 949
bbl Volume of Foam =V
Volume Water Needed = (V) × (1 – Q)
Example:
Problem 2 V = 600 bbl Foam
Q = 0.75 (75 Quality)
An instantaneous shut-in pressure is taken on a
frac job. The fluid pumped is 2% KCL water Water Volume Needed 600 bbl 1 - 0.75
with 40 lb/Mgal of gel and 500 SCF/bbl 600 bbl 0.25
nitrogen. The well is 6000 ft deep with a thermal

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 Nitrogen/Carbon Dioxide and Foam Fracturing

Figure 7.8 -

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 Nitrogen/Carbon Dioxide and Foam Fracturing

Unit E Quiz

Answer the following questions to check your progress in Unit E.

1. What do the following symbols stand for? What are the units for each?

Q = ____________________

VLR = ____________________

V’/V = ____________________

WHP = ____________________

BHP = ____________________

BHTP = ____________________

BHST = ____________________

2. If you are working with a formation that has a thermal gradient of 0.7°F/100 ft, what is the BHST if
the formation is 1,455 ft deep?

3. Calculate the volume of nitrogen required to displace casing under the following conditions. How
many standard cubic feet of nitrogen will be used?

4 ½‖ 11.6 lb/ft casing

Perforations at 3,000 ft

BHP is 2,000 psi

Thermal Gradient 1.1°F/100 ft

Now, look up the suggested answers in the Answer Key.

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 Nitrogen/Carbon Dioxide and Foam Fracturing

Unit F: Physical Properties of Carbon Dioxide (CO2)

The physical properties of liquid carbon dioxide
make it easy to handle, and thus ideal for use
with stimulation treatments. With the trend
toward higher fracturing pump rates, the
injection rates of the gases must keep pace.
Pumped as a liquid, carbon dioxide places no
limits on flow rates. Therefore, liquid carbon
dioxide is added to treating fluids to improve
results and eliminate some of the problems
associated with oil and gas well stimulation. It
also promotes fast clean up of wells without the
need of swabbing.

Figure 7.9 - CO2 Booster/HT-400

Applications of Carbon Dioxide
When pressure is released at the well head after In crude oil treatments, the viscosity of low
treatment, CO2 expands and aids in removing gravity oil is reduced considerably by the
the treating fluids from the formation. The addition of CO2. Viscosity of high gravity oils is
presence of gaseous CO2 in these fluids reduces also lowered, but to a lesser degree. The
the weight of the fluid column so normal viscosity of water is only slightly altered by the
reservoir pressure can unload fluids from the addition of CO2.
well. CO2 is injected in the liquid state and forms an
CO2 can help prevent formation damage from emulsion that becomes foam above 88°F. CO2 is
the stimulation fluid and provide better well bore not compatible with all gel systems. The
clean up. Using CO2 often results in recovery of carbonic acid formed by mixing CO2 with water
formation fines, silt, reaction products, and mud can cause a premature break or a failure to
lost during drilling. crosslink in some gel systems.
The solution formed when water is the treating CO2 is pumped by conventional pumping
fluid has an acidic pH. This helps prevent the equipment with the addition of a relatively
swelling of the clays, the precipitation of inexpensive supercharging pump.
hydroxides and gypsum, and eliminates the need
to use expensive acid or calcium chloride
solutions for this same purpose. Carbon Dioxide Factors

At atmospheric temperature and pressure carbon

dioxide (Table 7.6) is a colorless, odorless gas
about 1-1/2 times heavier than air. For oil field
work, CO2 is liquefied and transported in
insulated transports at approx. 0°F and 300 psi.
In this state it is handled in much the same
manner as liquefied petroleum gas. CO2 is non-
combustible, so there is no danger of fire or
explosion. It can also be used as an auxiliary

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 Nitrogen/Carbon Dioxide and Foam Fracturing

fire-fighting medium in well stimulation work if Below 75.1 psia, CO2 can exist only as a solid
desired. (dry ice) or a gas. At atmospheric pressure, solid
CO2 vaporizes when it reaches a temperature of
Molecular symbol ...................................CO2
–109.3°F.
Molecular weight ...................................... 44
The critical temperature and pressure of carbon
Critical temperature ............................87.8°F dioxide are 87.8°F and 1071 psia. At these
Critical pressure ..... 1057.4 psig or 1071 psia conditions the liquid and vapor states of CO2
become indistinguishable. Above these
Liquid density at 2°F……..63.3 lb per cu. ft. conditions the fluid state that exists is a gas.
or 8.46 lb per gallon
Some conversion factors useful in well
stimulation work are:
One ton of liquid CO2 yields 17,198 SCF
of gaseous CO2
One gallon of liquid CO2 @ 10°F yields
73 SCF of gaseous CO2
The solubility of CO2 (std. cu. ft./bbl.) at 100°F
in various treating fluids is listed in Table 7.5.
100 1000 2000 4000
psi psi psi psi

Fresh Water 20 152 174 191

Salt Water
(100,000 13 108 127 139
ppm)
Salt Water
(260,000 6 53 63 69
ppm) Figure 7.10 - Carbon Dioxide Equilibrium
Crude Oil Curve
45 1025 1075 1075
38° API (85°)
Crude Oil
20° API 35 415 700 700
(120°)
Table 7.5 - CO2 Solubility
Additional References

Halliburton Services Personnel Training Videos,

Physically, all three states of carbon dioxide— ―Cryogenic Safety,‖ 30 minutes, and ―CO2
Services,‖ 5 ½ minutes.
solid, liquid and gas—are familiar (Figure 7.10).
They can exist simultaneously at –69.9°F and
75.1 psia, the triple point of carbon dioxide.

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 Nitrogen/Carbon Dioxide and Foam Fracturing

Unit F Quiz

Fill in the blanks or mark the correct answer to check your progress in Unit F.
1. The critical temperature and pressure of CO2 are __________°F and __________ psia.

2. Physically, all three states of carbon dioxide (____________________, ____________________, and

____________________) can exist simultaneously at –69.9°F and 75.1 psia.

3. For field services, CO2 is liquid and delivered to location in insulated transports at approximately
__________ °F and __________ psi.

4. In low gravity crude oil treatments the viscosity of the oil is often ____________________ by the
addition of CO2.

5. CO2 injected in the liquid state forms an ____________________ that becomes a

____________________ above 88°F.

6. One gallon of liquid CO2 at 10°F yields:

_______ a) 152 standard cu. ft. of gaseous CO2

_______ b) 73 standard cu. ft. of gaseous CO2

_______ c) 63.3 standard cu. ft. of gaseous CO2

_______ d) 88.6 standard cu. ft. of gaseous CO2.

Now, look up the suggested answers in the Answer Key.

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 Nitrogen/Carbon Dioxide and Foam Fracturing

Unit G: Chemical Properties of Carbon Dioxide (CO2)

The use of carbon dioxide as a well servicing fluid does not stay at a low pH, insoluble
medium grew rapidly upon its introduction as an compounds such as calcium sulfate
additive to acid and fracture jobs in 1962. (gypsum) may precipitate and restrict flow.
Today, specially insulated high-pressure The presence of CO2 in the solution helps
transports normally carry carbon dioxide to the prevent such a precipitation.
wellsite as a 0°F, 300 psi liquid. Liquid CO2, at Dolomites, limestone, and silicates are
the wellsite, is commingled with various treating soluble in carbonated water to varying
fluids and pumped downhole while still in its extents. Under well treatment conditions,
liquid state. By pumping CO2 as a liquid, greater 2625 pounds of magnesium carbonate will
flow rates can be achieved than if it were dissolve in 100 barrels of water saturated
gaseous. It remains liquid until reaching with CO2. Calcite will dissolve to the
temperature and pressure conditions downhole extent of 80 pounds per 100 barrels.
that allow it to vaporize. Silicates such as calcium silicate, strontium
silicate, and barium silicate are soluble in
ranges of from 100 to 200 pounds per 100
Carbonic Acid barrels. The removal from the formation of
such materials by the treating fluid can
As with any well servicing medium, the uses of result in increased permeability of the
carbon dioxide depend upon its physical and formation.
chemical properties. One of the most useful
chemical applications with carbon dioxide is Fluid retention by a formation is related to
what can be accomplished when water is capillary pressure, which is important in
saturated with CO2. Carbonic acid is formed. low porosity and low permeability
This acid, with a stable pH of 3.3 to 3.7, is reservoirs. CO2 lowers the interfacial
relatively non-corrosive and requires no tension of water and helps prevent water
inhibition for short term well treating blocks due to high capillary pressures.
applications. Some benefits of well stimulation
that work from this chemical effect are:
Designing CO2 Well Treatments
The low pH of carbonic acid will tend to
shrink and stabilize clay particles. This With proper design, in which the many well
control of swelling is especially important variables are taken into consideration, a treating
in formations containing large amounts of fluid can be provided with the proper level of
swelling clays. carbonation. This quantity of CO2 is injected
Most sandstone formations and many simultaneously with the treating fluids and
carbonate formations contain iron and normally remains in the liquid state until after
aluminum that can be dissolved during the fluid injection ceases. Heat transfer from the
acidizing. If the pH rises to five or above formation then causes vaporization of the CO2.
during a treatment, iron and aluminum The vapor expands, imparting a gas lift effect to
could precipitate as gelatinous hydroxides the well. Rapid, high rate flow back of
which can effectively block flow channels. carbonated treating fluids increases well
The low pH treating fluids help keep this productivity by taking advantage of the CO2 gas
from happening. expansion to provide energy for the formation
clean up.
Gypsum and anhydrite can be dissolved
with aqueous treating fluids. If the treating

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 Nitrogen/Carbon Dioxide and Foam Fracturing

Additional References

Halliburton Services Personnel Training Video, ―Pumping CO2 Safely,‖ 23 minutes.

Unit G Quiz

Fill in the blanks with one or more words to check your progress in Unit G.
1. ____________________ acid is formed when water is saturated with CO2.

2. The low pH carbonated treating fluids will help prevent ____________________ and
____________________ from precipitating after a treatment.

3. Under normal well conditions ________________ pounds of magnesium carbonate will dissolve in
100 barrels of carbonated water.

4. CO2 lowers the ____________________ ____________________ of water and helps prevent

____________________ ____________________.

Now, look up the suggested answers in the Answer Key.

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 Nitrogen/Carbon Dioxide and Foam Fracturing

Unit H: Safe Handling and Pumping of CO2

CO2 can present problems if not handled and open the vent valve on the discharge line.
correctly. Knowing how CO2 reacts in each of Vapor is allowed to pass out the bleeder vent
its three forms – solid, liquid and gas – and how until a continuous, heavy cloud of dry ice
it changes in job situations will allow you to particles is blowing. This confirms presence of
safely control CO2. liquid CO2 through the system. By this time all
CO2 suction and injection lines and the injection
This unit discusses: pump fluid end manifold should be completely
proper set-up procedures for a job frosted over. When many pumps are used, they
may be primed individually by having a separate
purging the system prime-up valve on the discharge of each pump.
priming and testing the system Rotary gauges are provided on all of the CO2
starting injection transports and field storage facilities to indicate
the amount of liquid CO2 present as a percent of
controlling the separator total tank capacity. These gauges can be used to
check on the CO2 injection rates during a
starting and stopping boost pump during
treatment. The total CO2 tank capacity is
operation
indicated on each piece of equipment.
shutting down
Gauge readings for these purposes are:
Transport Capacity ................... 5335 gallons
CO2 Injection Initial Reading – 90% ................. 4800 gal or
.................................................360,000 SCF
Liquid carbon dioxide is injected into the other
treating fluids near the well head through a Check Reading – 70% ................ 3735 gal or
separate treating line. To prevent vaporization .................................................280,000 SCF
and eliminate gas locking in the injection Liquid CO2 Used – 20% ............. 1065 gal or
pumps, a positive super-charge pressure must be ...................................................80,000 SCF
maintained as the liquid CO2 is transferred from
the transport to the injection pump suction. This This quantity divided by the pumping time
is done with a small rotary pump placed as close elapsed from the start of the job gives a check on
as possible to the transport. To cool and prime the actual CO2 pumping rate.
the pumps and to prevent water from entering
the CO2 lines during the job, a block valve, a
back check and a bleeder vent are installed in the Pretreatment Meeting
CO2 injection line. These are placed as near as
possible to the line’s junction with the other A pretreatment safety meeting should be held
injection lines entering the well head. with all personnel to discuss job description,
maximum pressure, pressure testing procedures,
Before starting the injection, the CO2 block job hazards, and emergency procedures. The
valve is closed, the bleeder vent closed, and the emergency procedures should include fire
supercharge pump engaged at idling speed. The fighting equipment, personal safety equipment,
vapor valve on the CO2 transport is then opened, lifeline, and an emergency meeting place.
and the suction manifold is tested for leaks.
Repair leaks by first closing vapor line and Five-minute escape packs are recommended for
releasing pressure. Retest suction until all leaks all personnel on CO2 jobs. During the safety
are repaired. Then open liquid valve on transport meeting one person should be randomly chosen

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 Nitrogen/Carbon Dioxide and Foam Fracturing

to demonstrate the proper use of the escape

packs.
All operators should understand that once liquid
CO2 has been admitted to the system, leaking
unions in the CO2 lines are not to be tightened.

Spotting Equipment

Three important points to consider when

spotting equipment are: Figure 7.11 - Injection Pump Set-Up
The CO2 boost trailer should be as level as
possible. For the separator to work
properly, the left side of the trailer should NOTE: The job set-up shown in Figure 7.11
be no more than six inches above or below works well on fracturing jobs. No matter what
the right side. set-up is used, the following steps should be
implemented if possible:
Park the trailer in relation to the wind so
that a large amount of CO2 vapor does not circulate CO2 through all injection pumps
enter the engine air intake. This can cause and return through separator during pre-job
the engine to stall due to a lack of oxygen. cooling

Place the equipment so that all connections isolate separator from injection pump
can be made with one 100 ft. length of pressure during job
hose. Connecting two or more hoses allows isolate each injection pump in case one
the CO2 to gain more heat. This causes should develop trouble during the job
vapor to form.
CO2 transports should be connected to the trailer
suction header. The trailer discharge should be CO2 Rig-Up
connected to the Halliburton high pressure pump
suction header by using the ten-foot lengths of
four inch CO2 rated hose supplied with the Job Setup
trailer. If possible, connections should be made
so that there is no sag in the hoses. Sags provide 1. In a job setup (Figure 7.12), vapor lines
places for liquid CO2 to accumulate and form should be connected between the liquid
dry ice at the end of the job. This can damage CO2 containers in order to equalize
the hoses. pressure. These allow equal drawdown of
liquid from all containers. Depending upon
IMPORTANT: Never use hoses that are bent
the number of containers, equalization may
so short that they flatten in the bends. Minimum take several hours to a full day.
bend radius is 33 ½ inches.
2. A vapor source to the CO2 booster
A typical job set-up is shown in Figure 7.11. separator is necessary. A separate line may
This set-up allows one HT-400 to be kept cooled
be installed, or the vapor line integral with
and primed while the other is used to inject into receiver discharge piping may be adequate.
the well. CO2 used for cooling is returned to
trailer suction through the separator where the 3. Only use hoses approved for CO2 service.
vapor is vented. Inspect external cover or braid for damage
before using. Do not use hose with visible
damage until it has been pressure tested.
4. Use minimum hose lengths required.

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 Nitrogen/Carbon Dioxide and Foam Fracturing

5. Chain all hose connections securely. water). These contaminants can cause excessive
wear on the pump vanes if not removed.
6. Clean all unions and lubricate them with
diesel oil. Any water in the system will form ice as soon as
it contacts the liquid CO2. Even a small amount
7. Install a bypass line around the flow meter
of ice can:
to prevent over-speeding of turbine with
vapor when priming up or purging system. stop vane pumps from turning
8. Install a check valve in the discharge of restrict circulation and make it difficult to
each Halliburton high pressure pump or use cool the system
a manifold trailer.
stick valves in HT-400’s
9. Install a plug valve and two check valves
on CO2 line upstream of commingling tee. These steps should be followed to purge the
system:
10. Install a plug valve and a check valve on
liquid line upstream of commingling tee. 1. Before starting to purge, make sure the
separator screen has been cleaned.
11. Install a check valve in treating line as
close to the well as possible.
12. Use two plug valves and a choke on release
line with plug valves located upstream of
choke.
13. Erect a lifeline from CO2 equipment to a
clear area a safe distance from the location.

Figure 7.12 - CO2 Rig-Up Procedure

Figure 7.13 - Ball Valve

Purging the CO2 System

Before the system is cooled, it should be purged 2. After all lines have been connected, isolate
(force CO2 vapor through all parts of the the CO2 system by closing the valves at
injection system at as high a velocity as possible trailer suction and discharge manifolds so
in order to remove dirt, sand, rust, trash, and the system can be pressurized.

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 Nitrogen/Carbon Dioxide and Foam Fracturing

3. Connect vapor hose from transport to ball

valve (Figure 7.13) on boost trailer
separator. Most transports carry a rubber
hose about 15 feet long equipped with 1, 1-
¼, or 1-½ inch male pipe fittings. Since the
boost trailer is equipped with 1 inch pipe
fittings, an adapter may be necessary.

Figure 7.15 - Discharge Manifold

CAUTION: Make sure discharge area is clear

before releasing pressure through a valve.
IMPORTANT: Open valves fully as quickly
as possible. This will cause the vapor to
exhaust at a high velocity and give a better
Figure 7.14 - 4 inch Butterfly Valve purge.
NOTE: Dry ice will not form in the pump or
lines as long as pressure is above 100 psi in both
4. Turn vapor into the system; then watch any
the suction and discharge manifolds.
one of three gauges on the manifolding and
allow pressure to build until it stops.
Gauges should show from 200 to 280 psi. Pressure Test and Cool Down
5. After pressure is up, open a 4 inch butterfly
valve (Figure 7.14) at the trailer suction 1. Test CO2 discharge lines to required
manifold. Leave open until system pressure pressure with –50°F anti-freeze mixture
drops to zero. Repeat at least three times. from wellhead to check valves at
6. Allow pressure to build up again and open Halliburton high pressure pumps.
a 4 inch butterfly valve at the trailer 2. Bleed off pressure. Then remove anti-
discharge manifold (Figure 7.15). Close freeze solution from lines by displacing it
after pressure drops to zero. Repeat three with CO2 vapor back into tank through the
times. release line.
7. Follow the same procedure as in Steps 5 3. Close plug valve on CO2 discharge line at
and 6 at the vent line valve located on commingling tee.
injection hose between HT-400’s and
wellhead. 4. Open vapor line valve to CO2 system and
slowly build pressure while testing for
leaks on the CO2 supply manifolding. All
CO2 supply connections are to be checked
for leaks and repaired during this test. Do
not tighten connections after this test.
Leaks should be allowed to leak.
5. Bleed CO2 vapor through release valves on
top of Halliburton high pressure pumps and

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 Nitrogen/Carbon Dioxide and Foam Fracturing

allow CO2 vapor pressure to reach its liquid has been purged, or dry ice will
maximum value. form.
6. Continue to bleed CO2 through system 5. Close plug valve on CO2 discharge at
while waiting for start-up. commingling tee.
6. Put Halliburton high pressure pumps in
Pumping Procedure first gear and let idle to purge system until
only vapor is being discharged.
1. Close release valves located on top of 7. Close the vapor line at supply and allow
Halliburton high pressure pumps and allow time for system pressure to bleed off.
CO2 vapor pressure to reach its maximum 8. Rig down.
value.
2. Close CO2 vapor supply valve completely.
Controlling the Separator
3. Slowly open the main liquid line valve.
4. Start boost pumps. The CO2 separator (Figure 7.16) provides a
means of removing vapor from the circulated
5. Open plug valve at the commingling tee.
liquid CO2. In order to function properly, the
6. Prime one Halliburton high pressure pump separator requires that two conditions be met:
through the release valve located on top of
pump. The pump is primed when a solid The trailer is reasonably level (not more
white stream of gas and dry ice snow is than 6 inch slant side-to-side)
seen blowing continuously from its Liquid CO2 is maintained at the proper
discharge. Slowly close the release valve level in the separator.
and commence pumping CO2.
Figure 7.16 shows three openings used to
7. Prime Halliburton high pressure pumps one indicate and control liquid level:
at a time until CO2 rate is established (2-3
barrels per minute per pump is A. is the point at which vapors are vented away
recommended). B. is the low level indicator
8. For short interruptions in pumping, the C. is the high level indicator
boost pumps and HT-400’s may be put in
The discharge port is on the under side.
neutral. A longer delay may require
repriming.

Shutdown

1. Shut down Halliburton high pressure

pumps.
2. Close all liquid CO2 supply valves at
supply.
3. Open vapor supply valves and admit CO2
vapor into system.
Figure 7.16 - CO2 Separator
4. Slowly open CO2 release valves on CO2
discharge line. Do not allow manifold
pressure to drop below 100 psi until all In order for the separator to work properly, it
must be kept between ½ and ¾ full as shown

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 Nitrogen/Carbon Dioxide and Foam Fracturing

above. The liquid level is determined by

observing the two level-indicating needle valves
(B) and (C).
Both needle valves should be opened slightly
while the boost trailer is being used. If liquid
CO2 is at the correct level, (B) should vent liquid
while (C) vents vapor. Needle valves may
occasionally become clogged with dry ice.
Opening or closing the needle valves slightly
should clear them out.
Figure 7.18 - Liquid Level Too High
If both (B) and (C) begin to spew vapor, the
liquid level is probably too low as shown in
Figure 7.18. In this case some vapor may be
Figure 7.19 shows what can happen if the boost
drawn out with the liquid through the discharge
trailer is not adequately leveled side-to-side. All
port. To remedy this, open ball valve (A) a little
indications may show proper liquid level, but
more. This will allow more vapor to escape and
injection pumps may be getting vapor and may
reduce the size of the vapor space held in the
lose prime.
separator. The liquid level will then rise.
If both (B) and (C) spew liquid, the level is
probably too high as shown in Figure 7.19. In
this case liquid may be drawn off with vapor
through (A).

Figure 7.19 - Boost Trailer out of level

Figure 7.17 - Liquid Level Too Low

Starting and Stopping Boost

To correct this, close ball valve (A) slightly. Pumps during Operation
This will help maintain the volume of vapor held
in the separator and force the liquid level to 1. While pumping CO2 at an injection rate that
drop. is not near the maximum of 15 bbl/min, one
or two of the CO2 boost pumps may stop
turning. This should be considered normal if
proper boost pressure is maintained. Check
the boost pressure and make sure the
discharge manifold reads 50 to 65 psi more
than the gauge on the suction manifold.
Pumps that have stopped turning should be
turned off as follows:

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 Nitrogen/Carbon Dioxide and Foam Fracturing

Close pump discharge valve on stalled 2. Bring boost trailer engine to idle.
pump(s) 3. Close valves on CO2 transports.
Close hydraulic fluid valve to hydraulic 4. Isolate CO2 system from well pressure.
motor(s) on stalled pump(s)
5. Attach CO2 from a transport to the ball
Open needle valve bleeder on stalled valve on the separator and turn vapor into
pump discharge(s) just enough to the CO2 system.
discharge liquid CO2 and maintain a
coating of frost on the pump. This will 6. Bleed off the liquid CO2 at a vacant boost
cause the pump(s) to be kept full of trailer suction valve, discharge valve, the
liquid CO2 , cool during the job and ready vent valve on the injection line and, if
to run at any time. available, a bleeder valve on a 4 inch
connection on the CO2 transport.
2. If one of the stalled pumps must be restarted
during the job: NOTE: Bleed these locations one at a time
repeatedly until only vapor is produced.
Open needle bleeder valve on required
pump until there is a positive flow of 7. After all liquid CO2 is out of the system,
liquid CO2 shut off the vapor supply at the transport.

Fully open hydraulic valve to required 8. Vent the pressure on the boost trailer.
motor 9. Remove vapor hose.
Open pump discharge valve on required 10. Kill engine.
pump only
IMPORTANT: Watch the pressure on the
Close needle bleeder valve on required discharge and suction gauges closely. When
pump only. bleeding off liquid, valves may be opened as
much as desired as long as the pressures shown
NOTE: Using all three of the pumps equally
on the discharge and suction gauges do not fall
will result in fewer pump overhauls. A pump
below 100 psi. Pressures lower than 100 psi can
that stops running on every job should be made
cause liquid in the system to form extremely low
to run by shutting down the pump that is
temperature dry ice. These extremely low
running. Follow the procedures listed above for
temperatures may damage boost trailer
shutting down a pump.
components such as hoses and pumps.
CAUTION: The rubber hoses may be stiff or
Shutting Down CO2 Boost contain dry ice just after they are disconnected.
Operations They should be allowed to warm and become
flexible before loading onto hose racks. Failure
After the HT-400’s have been stopped: to do so can cause damage to the hoses. Also, it
is possible that plugs of dry ice trapped inside
1. Stop CO2 boost pumps by turning the the hose may be violently discharged by
hydraulic pump control lever clockwise as expanding CO2 vapor.
far as possible.

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 Nitrogen/Carbon Dioxide and Foam Fracturing

Unit H Quiz

Fill in the blank or mark the correct answer to check your progress in Unit H.
1. ______ True ______ False When using CO2, the four inch rubber transfer hoses may become
stiff or contain dry ice just after they are disconnected.

2. ______ True ______ False Dry ice plugs trapped inside the transfer hoses may be violently
discharged by the expanding CO2 vapor.

3. ______ True ______ False Dry ice will not form in pumps or lines when handling CO2 as long
as pressure is above 100 psi in both the suction and discharge
manifolds.

4. ______ True ______ False Make sure the discharge area is clear before releasing CO2 pressure
through a valve.

5. ______ True ______ False Five minute escape packs are recommended for all personnel on a
CO2 job.

6. Never use transfer hoses bent so short that they flatten in the bends; minimum recommended bend
radius is ____________________ inches.

Now, look up the suggested answers in the Answer Key.

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 Nitrogen/Carbon Dioxide and Foam Fracturing

Unit I: Sample CO2 Problems

Since CO2 is a compressible gas at certain a near ball-off occurs, increasing the wellhead
conditions, similar equations and definitions that pressure from 1500 psi to 3000 psi. The well is a
are used for nitrogen can be used for CO2. tubing completion 12,000 ft deep, and the tubing
However, graphs are used instead of charts to capacity is 70 bbl. The temperature gradient is
solve CO2 problems. These curves can be found 1.1°F/ft, and the 2% KCL water contains 1500
in the Oilfield Carbon Dioxide Services SCF CO2/bbl.
Handbook. Solution:
1. Use the Commingled Carbon Dioxide Fluid
Problem 1 Curves for 1.1°F/100 ft – 8.5 lb/gal fluid –
1500 SCF CO2/bbl (Figure 7.21).
Determine:
2. On the WHP vs. BHP curve, find 3000 psi
Bottom hole treating pressure with commingled on the horizontal axis. Locate where this
carbon dioxide fluid column. value intersects with the 12,000 ft curve.
Find: Read across to the vertical axis and obtain a
BHP of 8000 psi.
The bottom hole treating pressure (BHTP) in an
8,000 ft well that has just been acidized. Acid 3. Using Equation #1 in the Commingled
was displaced with 2% KCL water containing Carbon Dioxide Fluid Curves explanation
1,000 SCF/bbl CO2. Instantaneous shut-in (Oilfield Carbon Dioxide Services
pressure equals 2,500 psi. Temperature gradient Handbook):
is 1.1°F/100 ft.
I
L
Solution: 359 .0
VLR 0.051948
Since 2% KCL water has a density of about 8.5 BHP WHP
lb/gal, use the Commingled Carbon Dioxide
Fluid Curves for 1.1°F/100 ft – 8.5 lb/gal fluid –
1000 scf CO2/bbl (Figure 7.21). On the WHP vs Where:
BHP curve, find 2500 psi on the horizontal axis L = well depth, ft
and the intersection with the 8000 ft curve. Read
across to the vertical axis and obtain a BHTP of ρ = fluid density, lb/gal
@ 5890 psi. I = carbon dioxide-liquid injection
ratio, scf/bbl
Problem 2 BHP = bottom hole pressure, psi
WHP = wellhead pressure, psi

Determine: SCF
1500
lb bbl
Change in liquid displacement volume of 12,000 ft 8.5
gal 359
commingled carbon dioxide fluid caused by
change in wellhead pressure. VLR 0.05195
8000 psi 3000 psi
Find: bbl mixture
1.5793634
The proper 2% KCL water displacement volume bbl liquid
when flushing an acid breakdown treatment and

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 Nitrogen/Carbon Dioxide and Foam Fracturing

4. Therefore, the corrected 2% KCL water Additional References

displacement volume is
70 bbl mixture Nitrogen Data for Oil Well Servicing
2% KCL Vol
bbl mixture
1.5793634 Halliburton Services Part #252.11115
bbl liquid
Manual N2 ―Oilfield Nitrogen Services
Handbook‖ Third Edition (Copyright,
NOTE: The VLR value before the pressure Halliburton Company, 1981)
increase was 1.2148948 bbl mixture/bbl liquid
providing a liquid displacement volume of Oilfield Carbon Dioxide Services Handbook
(Copyright, Halliburton Company, 1980)
70 bbl mixture
bbl mixture
1.2148948
bbl liquid
57 .618157 bbl liquid

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 Nitrogen/Carbon Dioxide and Foam Fracturing

40

30

20

15

10
9.0
8.0

7.0

6.0

5.0

4.0

3.0

2.0

1.5

1.0
0.9 Commingled Carbon Dioxide Curves 1.1°F/100 ft
0.8 Fluid Density - 8.5 lb/gal
0.7
CO2 Concentration - 1000 SCF/bbl
WHP vs BHP
0.6

0.5
0.5 0.6 0.7 0.8 0.9 1.0 1.5 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10 15
WHP (103 psi)

Figure 7.20- Commingled Carbon Dioxide Curve –1000 SCF CO2/BBL

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 Nitrogen/Carbon Dioxide and Foam Fracturing

40

30

20

15

10
9.0
8.0

7.0

6.0

5.0

4.0

3.0

2.0

1.5

1.0
0.9 Commingled Carbon Dioxide Curves 1.1°F/100 ft
0.8 Fluid Density - 8.5 lb/gal
0.7
CO2 Concentration - 1500 SCF/bbl
WHP vs BHP
0.6

0.5
0.5 0.6 0.7 0.8 0.9 1.0 1.5 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10 15
WHP (103 psi)

Figure 7.21 - Commingled Carbon Dioxide Curve-1500 SCF CO2/BBL

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 Nitrogen/Carbon Dioxide and Foam Fracturing

Unit I Quiz

Work the following problem to check your progress in Unit I.

1. Find the wellhead pressure under the following conditions:
Tubing 2 7/8‖ 6.5 lb/ft
Perfs at 10,000 ft
BHTP Gradient .65 psi/ft
CO2 commingled at 1000 SCF/bbl
Base fluid density 8.5 lb/gal
Temperature Gradient is 1.1°F/100 ft

2. What is the Volume Liquid Ratio of a fluid under the conditions in question 1?

Now, look up the suggested answers in the Answer Key.

© 2009, Halliburton 7 • 42 Stimulation I

 Nitrogen/Carbon Dioxide and Foam Fracturing

Unit J: Foam Fracturing

One of the important applications of N2 and CO2 foam generator is recommended when using oil
in the oil field is foam stimulation. Foams have base fluids or crosslinked gels in order to
several advantages over other fluid systems: produce enough mixing energy to make a foam
(Figure 7.23).
less fluid in the system
gas assisted flow back of fluids
enhanced fluid loss control
minimized clean up time

Foam

Foams are fluids made up of two parts or phases. Figure 7.23 – Foam Generator
Gas bubbles compose the internal phase, and
liquids are the external phase (Figure 7.22).
Foams need to have an agent in the liquid to
remain stable over a period of time.
Foam Quality
External Foam quality is the ratio of gas volume to foam
Water Phase volume at a given pressure and temperature. In
the range of approximately 0 to 52 quality, the
gas bubbles in the foam are spherical and do not
contact each other. Foam in this quality range
has rheology similar to the liquid phase. In the
approximate quality range of 52 to 96, the gas
bubbles in the foam interfere with one another
and deform during flow. This causes the foam to
increase in viscosity and yield point. Above 96%
quality, foams may degenerate into a mist. When
the thin liquid layer is not able to contain the
larger volume of gas, the foam bubble ruptures.
In theory, foam between 52 and 96 quality could
be used to transport proppant in a static
Internal Gas condition. The higher quality foams have higher
Phase viscosity and give greater support to proppant in
a static condition. However, the higher quality
Figure 7.22 – Model of foam
foams require more horsepower to pump. A
compromise is reached between a 65 and 85
quality, with a 65 to 75 quality being most
A certain amount of mixing energy is required to frequently used in foam fracturing.
make a foam. If water or a water/alcohol mixture
is used, enough energy is produced by the gas
and liquid mixing in a tee to produce a foam. A

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 Nitrogen/Carbon Dioxide and Foam Fracturing

Foam Stability comparable non-foamed system. Since fluid loss

additives often are not required, the chance of
damage to formation conductivity is reduced.
Once a foam is formed, it will remain stable
Some fluid loss additive may be required at
when kept in motion. If the foam stops moving,
higher permeabilities in the presence of natural
the process of drainage occurs. Gravity forces a
fractures.
separation of the free liquid (which is not tightly
bound at the surface of the bubbles) from the
rest of the foam. The liquid drains at a rate that Proppant Transport
is dependent upon the viscosity of the liquid
phase and on the concentration of foaming
agent. As the temperature of a foam increases, Foam allows proppant to be carried deep into the
the viscosity of the liquid phase decreases, and fracture without settling out before the fracture
the liquid drains more quickly. Generally, the closes. Proppant particles are held in place by
concentration of a foaming agent must also be the foam structure and do not readily settle
increased to stabilize foams as temperature through it. This means foam will distribute
increases. proppant more uniformly throughout the
fracture.
Using a gelling agent appropriate to the liquid
phase may increase the static stability of foam.
Some gel viscosity is usually desired to aid Built-In Gas Assist
proppant transport through the blender and
pumps. Additional viscosity in the liquid phase The built-in gas assist derived from a foam
can make significant improvement in fluid loss treatment makes recovery of treating fluids from
control. low-pressure reservoirs more efficient than non-
In spite of the advantages to a gelled liquid foamed treatments. The compressible nature of
phase, high viscosity liquids are more difficult to foam helps bring back the liquid due to
foam than low viscosity liquids. Therefore, expansion of the gas as it is returned to the
viscosifiers should be used in moderation in wellbore.
relation to temperature and pumping times.
Minimum Well Clean Up Time
Low Liquid Content
The built-in gas assist and low liquid content
Fracturing foams used in the field contain only result in high fluid recovery. Low production
15 to 35% liquid. The low liquid content is due to slow clean-up may be minimized.
extremely important when treating a liquid Swabbing units are seldom needed to get the
sensitive formation. Large amounts of liquid treating fluid back.
may cause swelling of clays in the formation
and/or reduce the permeability of the formation
to the produced fluids. The low liquid content Foam Types
of foam results in a lower hydrostatic head. This
enhances well clean up, especially when treating A wide variety of liquid phases are available for
low-pressure formations. foam fracturing. The base liquids include water,
water-alcohol mixtures, and hydrocarbons.
Water is the most economical liquid phase
Fluid Loss available. When water-sensitive clays are likely
to be encountered, salts such as potassium
The low fluid loss characteristics found in chloride or sodium chloride may be blended into
foamed systems provide better fluid efficiency the treating water to help protect the clays. Up to
and may create larger fractures than a 50% alcohol will further reduce potential clay

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 Nitrogen/Carbon Dioxide and Foam Fracturing

swelling. Alcohol also lowers the surface tension compatibility, and formation temperature. The
of the liquid and has a higher vapor pressure to foamers available are listed in Table 7.6.
aid in producing back the frac fluid. Aqueous Max. Rec.
Ionic Charge
Maximum protection against formation damage Foamers Temp.*
may be obtained by using hydrocarbon foam. AQF-2 Anionic 300°F
Suitable oils for foam fracturing include diesel, SEM-7 Anionic 400°F
condensates, and medium gravity crude oils.
Lease crude oils must be laboratory tested for SEM-8 Anionic 400°F
foaming ability prior to field usage. Foam HC-2 Amphoteric 300°F
generators are recommended when foaming Howco-Suds Anionic 250°F
hydrocarbons.
SSO-21M Non-ionic 215°F
Pen-5 Non-ionic 200°F
Proppant Concentration ACO-1 (80%
Anionic 300°F
Methanol)
The concentration of proppant desired in the * Maximum Temperature is based on gel
foam influences the choice of quality. For systems mixed from powdered gel – no oil.
example, assume three pounds proppant per
Table 7.6 – Foaming Agents
gallon foam is desired. The concentration of
sand in the blender tub would be nine pounds
per gallon for a 67 quality foam, twelve pounds
per gallon for a 75 quality foam, and fifteen
pounds per gallon for an 80 quality foam. Foamed Acid

Mineral acids and mixtures of mineral and

Breakers in Liquid Phase organic acids foam equally well. Corrosion
inhibitors have little effect on foaming. Foamed
Breaker should be added to the system to break acid treatments should have minimum well shut-
the gel after pumping has ended. Since the in time after pumping, with the fluids being
viscosity of the foam is only mildly influenced flowed back as soon as possible following
by the liquid phase viscosity, flow back of the treatment. This will prevent the spent acid and
well is not critically dependent upon a gel break. nitrogen from separating. The longer the well is
However, breaking will: closed-in, allowing the foamed acid to remain
under non-flowing conditions, the more the
aid recovery of the liquid which drained
liquid drains from the foam bubbles and
out of the foam
suspended fines settle out of the foamed acid.
help limit the stability of any emulsions
which might be formed Foaming Agents—Compatibility
In most cases, the foam structure itself will not
be broken by the time flow back begins, A pre-job chemical compatibility test of the
typically one to two hours after shutdown. foaming agent should be conducted with both
the live and spent acid as well as with all other
additives in the system. A foaming agent should
Foaming Agents be capable of producing a stable foam in live
acid and still retain sufficient foaming properties
A variety of foaming agents have been to foam spent acid. This will allow recovery of
developed for foam fracturing. These foaming insoluble fines following the treatment. In spent
agents are selected based upon the type of liquid acid systems, HC-2 does not perform as well as
phase, formation compatibility, chemical Pen-5E. Contact with oil will break the spent

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 Nitrogen/Carbon Dioxide and Foam Fracturing

acid foam. If the return foamed fluids are the nature of the rock
anticipated to contact traces of oil, then SGA-2
or SGA-HT used in conjunction with Pen-5E is the volume
recommended. the type
the concentration of acid used
Fluid Loss
Tests performed on both homogeneous and
Laboratory tests have shown that foamed acid heterogeneous cores have shown that the foamed
has much better matrix fluid loss control than acid had fracture flow capacity similar to
unfoamed acid without the conventional fluid unfoamed acid.
loss additives. Increasing the viscosity of the
acid before it is foamed will help stabilize the Reaction Rate
foamed acid and improve fluid loss control. In
cases where there is high formation permability The surface reaction rate constant and order of
or natural fractures, conventional fluid loss reaction should be the same for foamed acid as it
additives need to be incorporated into the is with unfoamed acid. Foaming the acid should
foamed acid system. The use of a pad and/or the not alter its chemical properties. However,
inclusion of OSR-100, 100 mesh sand, or foamed acid is regarded as a physically retarded
Matriseal®-O in the treating fluids has been quite system because one layer of bubbles reacts at a
effective. time on the face of the fracture. This differs
from a chemically retarded system where a layer
Fracture Flow Capacity of chemical is deposited on the formation face to
slow down the acid reaction. In several cases,
A successful fracture acidizing treatment chemically retarded acid systems have been
depends not only on good fluid loss control, but foamed with good results. Chemical retarders
also on the acid system used. The quantity of are usually added to foamed acid systems when
rock removed and the pattern in which it is high temperature or long pumping times will be
removed from the fracture faces are important. involved.
Fracture flow capacity depends on:

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 Nitrogen/Carbon Dioxide and Foam Fracturing

Unit J Quiz

Fill in the blank or mark to check your progress in Unit J.

1. Foams are fluids made up of ____________________ ____________________ or
_____________________.

2. The most frequently used foam quality is __________ to __________.

3. ______ True ______False Foams remain stable under all conditions.

4. List three advantages of foams:

_________________________________________________

_________________________________________________

_________________________________________________

5. AQF-2 is a(n) ____________________ foamer that should be used at a maximum temperature of

__________ °F.

6. A foaming agent for acid systems should produce a stable foam in ____________________
_____________________ and still be able to foam ____________________ ____________________
to help return ____________________ _____________________ to the wellbore.

Now, look up the suggested answers in the Answer Key.

© 2009, Halliburton 7 • 47 Stimulation I

 Nitrogen/Carbon Dioxide and Foam Fracturing

Unit K: Flow back of Energized Fluids

Under normal circumstances, it is not the 1 ½‖ tubing – ¼ inch choke
responsibility of Halliburton personnel to flow
During flow back as the surface pressure
fluids back after stimulation. Occasionally,
decreases, larger chokes may be used to
situations do arise that make it necessary for
maintain flow. The manifold downstream of
Halliburton to assist with or give advice on flow
the choke should be as straight as possible to
back procedures.
minimize erosion.
2. Two (2) stop valves are required between
Procedures the choke and the well. These valves must
be located upstream of the choke and where
There are variations in rig-up of flow back they can be closed safely in the event the
manifolds and flow back procedures. This tends choke cuts out.
to make a set procedure impractical. Therefore, Always open the upstream valve first, then
general guidelines must be applied to make all the downstream valve. Always close the
of these possible rig-ups safe. Since fluids down-stream valve first, then the upstream.
containing nitrogen and carbon dioxide have a Lo Torc® and other stop valves are never to
tremendous amount of energy to dissipate on be used as chokes.
flow back, close adherence to guidelines is
essential. 3. Never use rubber hoses in a flow back
line. Always ensure that the flow back
The guidelines are as follows: line’s maximum pressure rating is equal to
1. All initial flow back must be done or greater than the initial flow back pressure.
through some type of choke. The 4. Always assume the presence of
maximum initial choke size should not combustible hydrocarbons. Have a
exceed 1/6th the diameter of the surface separator or flame source present to
manifold, or the tubing in the well. eliminate the hazard of flash fires.
Examples: 3‖ tubing – ½ inch choke
2‖ tubing – 5/16 inch choke

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 Nitrogen/Carbon Dioxide and Foam Fracturing

Unit K Quiz

Fill in the blanks with one or more words to check your progress in Unit K.
1. All initial ____________________ ____________________ must be done through some type of
choke.

2. Maximum initial choke size should not exceed ___________ the diameter of the surface manifold or
tubing in the well.

3. If the tubing is 1 ½‖ diameter, the maximum choke size would be __________.

4. __________ stop valves are required between the choke and well.

5. Always open the ____________________ valve first, then the ____________________ valve.

6. Always close the ____________________ valve first, then the ____________________ valve.

7. Never use ____________________ ____________________ in a flow back line.

8. Always assume the presence of ____________________ _____________________.

Now, look up the suggested answers in the Answer Key.

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 Nitrogen/Carbon Dioxide and Foam Fracturing

Self Check Test for Section 7

Mark the best answer(s) to the following questions.
1. ______ True ______False Viscosity reduction is produced by N2 since it is soluble in water and
oil.
2. Which of the following is not an advantage of jetting nitrogen?
_____ A) reduced rig time
_____ B) improved wellbore conductivity
_____ C) reduced danger of sticking swab cups
_____ D) higher returning fluid cost
3. Nitrogen combined with what allows many completion, workover, and remedial services to be
performed faster and at less cost than previously possible?
_____ A) corrosion inhibitors
_____ B) coiling tubing services
_____ C) workover fluids
_____ D) density control
4. Nitrogen circulation through continuous tubing will do what?
_____ A) clean out debris
_____ B) load low pressure gas wells
_____ C) block fluid from the well prior to perforating
_____ D) add sand after fracturing
5. Foam quality is the ratio of gas volume to foam volume. What two factors is foam quality most
dependent upon?
_____ A) time and pressure
_____ B) time and temperature
_____ C) temperature and pressure
_____ D) weight and temperature
6. What kind of an effect do corrosion inhibitors have on foaming?
_____ A) great effect
_____ B) little effect
_____ C) no effect
_____ D) unknown
7. Which of the following is not considered protective clothing when working with nitrogen?
_____ A) cuffed trousers

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 Nitrogen/Carbon Dioxide and Foam Fracturing

_____ B) safety goggles

_____ C) insulated gloves
_____ D) long sleeve shirts
8. Which of the following is a procedure to follow for freeze burns?
_____ A) flood or submerge affected body area with ice water
_____ B) apply hot compresses
_____ C) get patient to a physician for treatment
_____ D) secure any clothing to body area affected
9. At what temperature does carbon steel become brittle?
_____ A) + 30°F
_____ B) 0°F
_____ C) – 20°F
_____ D) – 40°F
10. Calculate the volume of nitrogen and the wellhead pressure necessary to develop a 3,000 psi cushion
for a drill stem test. The test uses 9,000 ft of 3 ½‖ 13.30 lb/ft internal upset drill pipe. The thermal
gradient is 1.1°F/100 ft.
Procedure:
1. Calculate drill pipe capacity
2. Look up data
3. Calculate nitrogen volume

11. ______ True ______ False The use of CO2 often results in the recovery of formation fines, silt,
reaction products, and mud lost during drilling.
12. When water is the treating fluid, the carbonated solution that is formed has an acidic pH. Which of
the following is not prevented when this acidic pH is formed?
_____ A) swelling of clays
_____ B) precipitation of hydroxides
_____ C) swelling of formation fines
_____ D) precipitation of gypsum
13. Which of the following is not true of CO2 in a liquefied state?
_____ A) non-combustible
_____ B) combustible

© 2009, Halliburton 7 • 51 Stimulation I

 Nitrogen/Carbon Dioxide and Foam Fracturing

_____ C) could be used as an auxiliary fire fighting medium

_____ D) is explosive if trapped
14. Water saturated with which of the materials below will form Carbonic Acid?
_____ A) N2
_____ B) O2
_____ C) CO2
_____ D) KCL
15. When spotting equipment for a CO2 transport, which of the following is true?
_____ A) the CO2 boost trailer should have the left side slightly higher
_____ B) the CO2 boost trailer should have the right side slightly higher
_____ C) the CO2 boost trailer should be as level as possible
_____ D) the leveling of the CO2 boost trailer is not important
16. ______ True ______ False Sags in hoses provide places for liquid CO2 to accumulate and form
dry ice at the end of a job. This can damage the hose.
17. When purging the CO2 system, which of the following will not occur when a small amount of ice
forms?
_____ A) stop vane pumps from turning
_____ B) restrict circulation making it difficult to cool the system
_____ C) stick valves in HT-400’s
_____ D) restrict vaporization
18. How must the valves be opened to cause vapor to exhaust at a high velocity and give a better purge?
_____ A) as quickly as possible
_____ B) as slowly as possible
_____ C) at a steady medium rate
_____ D) short, quick turns every 30 seconds
19. If needle valves become clogged with dry ice, what will clean them out?
_____ A) blowing with hot air
_____ B) flushing with hot water
_____ C) opening or closing slightly
_____ D) opening and scraping
20. After the HT-400’s injecting and circulating CO2 have been stopped, several steps take place for shut
down. Which of the following is not one of the steps?
_____ A) bring boost trailer engine to idle
_____ B) open valves on CO2 transports
_____ C) isolate CO2 pumping system from well pressure
_____ D) vent the pressure on boost trailer

© 2009, Halliburton 7 • 52 Stimulation I

 Nitrogen/Carbon Dioxide and Foam Fracturing

21. When bleeding off liquid CO2, valves may be opened as much as desired as long as the pressures on
the discharge and suction gauges do not fall below what pressure?
_____ A) 200 psi
_____ B) 150 psi
_____ C) 100 psi
_____ D) 50 psi
22. ______ True ______ False Rapid, high rate flow back of carbonated treating fluids decreases
well productivity by taking advantage of the CO2 gas expansion to
provide energy for formation clean up.
23. Find the bottom hole treating pressure in an 8,000 ft well that has just been acidized. The acid was
displaced with 2% KCL water, containing 1,000 scf CO2/bbl. Instantaneous shut-in pressure equals
2,500 psi. Temperature gradient is 1.1°F/100 ft.
Note: Use Figure 7.21 to help you with this problem.

24. What are the five guidelines for flow back of energized fluids?
______________________________________________________________
______________________________________________________________
______________________________________________________________
______________________________________________________________
______________________________________________________________
25. The range of foam quality generally used in stimulation is:
_____ A) 0 – 10%
_____ B) 0 – 52%
_____ C) 96 – 100%
_____ D) 65 – 85%
Now, look up the suggested answers in the Answer Key.

© 2009, Halliburton 7 • 53 Stimulation I

 Nitrogen/Carbon Dioxide and Foam Fracturing

Answer Keys
Items from Unit A Quiz
1. an inert gas, does not react adversely with treating or formation fluids, is slightly soluble in water, oil
and most other liquids, remains in bubble form to help lift fluids from the well bore when commingled
with liquid, is colorless and is brought to location in liquid form, is converted to gas at controlled rates,
pressure and temperatures
2. liquid / gas
3. C
4. E
5. -320.36

Items from Unit B Quiz

1. Cushion for Drill Stem Testing, Leak Testing, Density Control, Workover Services, Placing Corrosion
Inhibitors, Well Fire Control, Annulus Insulation, Freeing Differentially Stuck Drill Pipe
2. Reduced rig time, Improved wellbore conductivity, reduced danger of sticking swab cups, quicker
return on investment, lower returning fluid cost

Items from Unit C Quiz

1. Destroyed skin
2. 42,000
3. d
4. 8 minutes
5. Disengage the pump, close the discharge valve, open the prime up valve, turn off vaporizer,
Disassemblely and inspect for cracks

Items from Unit D Quiz

1. -40° F
2. a), c), d)
3. 70 / 100
4. shrink / explode

Items from Unit E Quiz

1. Quality of foam
Actual Volume Mix
Volume Liquid Ratio -
Actual Volume Liquid

Standard Volume Gas SCF

Volume factor - -
Actual Volume Gas bbl
Wellhead pressure

© 2009, Halliburton 7 • 54 Stimulation I

 Nitrogen/Carbon Dioxide and Foam Fracturing

Bottom Hole Pressure

Bottom Hole Treating Pressure
Bottom Hole Static Temperature

F
2. BHST 80 1455 ft 0.7 90 .185 F
100 ft

SCF
From Figure 7.6 - V' /V 688
bbl
bbl
3. From RedBook - Capacity of 4 - 1/2, 11.6 # /ft Casing 0.0155
ft
bbl SCF
N 2 Vol 3000 ft 0.0155 688 31,992 SCF
ft bbl

Items from Unit F Quiz

1. 87.8 / 1071
2. Solid / liquid / gas
3. 0 / 300
4. reduced
5. emulsion / foam
6. b

Items from Unit G Quiz

1. Carbonic acid
2. Iron /and or aluminum
3. 2625
4. Interfacial tension / water blocks

Items from Unit H Quiz

1. T
2. T
3. T
4. T
5. T
6. 33-1/2

© 2009, Halliburton 7 • 55 Stimulation I

 Nitrogen/Carbon Dioxide and Foam Fracturing

Items from Unit I Quiz

psi
1. BHTP = 10,000 ft × 0.65 = 6,500 psi
ft
from chart WPH ≈ 2,250 psi

1000
10000 8.5
359 bbl mixture
2. VLR 0.051948 1.3794
6500 2250 bbl liquid

Items from Unit J Quiz

1. To parts / phases
2. 6570 / 75
3. F
4. Less Fluid In The System
Gas assisted Flowbackflow back of fluid
Enhanced fluid loss control
Mminimized cleanup time
5. anionic / 300
6. live acid / spent acid / insoluble finesC

Items from Unit K Quiz

1. FlowbackFlow back
th
2. 1/6
3. 1.5 in ÷ 6 = – 0.25 inches
4. Two (2)
5. upstream / downstream
6. downstream / upstream
7. Rubber Hoses
8. Combustible hydrocarbons

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 Nitrogen/Carbon Dioxide and Foam Fracturing

Self-Check Test
1. F
2. D
3. B
4. A
5. C
6. B
7. A
8. C
9. D
bbl
10. 9,000 ft × 0.00742 = 66.78 bbl
ft
scf
V’/V = 868 from Fig 7.6
bbl
scf
66.78 bbl × 868 = 57,965.04 SCFscf
bbl
11. T
12. B, D
13. B, D
14. C
15. C
16. T
17. D
18. A
19. C
20. B
21. C
22. F
23. about 60005980 psi
24. All initial flowbackflow back must be done through some type of choke , Two (2) stop valves are
required between the choke and the well, Never use rubber hoses on a flow back line, Always
assume the presence of combustible hydrocarbons
25. D

© 2009, Halliburton 7 • 57 Stimulation I

Section 8

Chemical Stimulation

Table of Contents
Introduction ............................................................................................................................................... 8-5
Topic Areas............................................................................................................................................ 8-5
Learning Objectives ............................................................................................................................... 8-5
Unit A: Types of Acids.............................................................................................................................. 8-6
Hydrochloric Acid.................................................................................................................................. 8-6
Hydrofluoric-Hydrochloric Acid ........................................................................................................... 8-6
Additional Acids .................................................................................................................................... 8-6
Unit A Quiz............................................................................................................................................ 8-7
Unit B: Safety ............................................................................................................................................ 8-8
Safety Precautions.................................................................................................................................. 8-8
Unit B Quiz ............................................................................................................................................ 8-9
Unit C: Reactions of Hydrochloric Acid ................................................................................................. 8-10
HCL Reactions..................................................................................................................................... 8-10
Unit C Quiz .......................................................................................................................................... 8-12
Unit D: Corrosion Inhibitors.................................................................................................................... 8-13
Corrosion of Metals ............................................................................................................................. 8-13
MSA Inhibitors .................................................................................................................................... 8-14
Unit D Quiz.......................................................................................................................................... 8-15
Unit E: Carbonate Acidizing ................................................................................................................... 8-16
Matrix Acidizing.................................................................................................................................. 8-16
Expected Results .................................................................................................................................. 8-17
Types of Porosity ................................................................................................................................. 8-17
Fracture Acidizing................................................................................................................................ 8-17
Formation Core and Fluid Testing ....................................................................................................... 8-17
Tubing Movement Program ................................................................................................................. 8-19
Fracture Acidizing Plan Calculations .................................................................................................. 8-19
Acid Systems ....................................................................................................................................... 8-19
Additional Reference ........................................................................................................................... 8-21
Preflushes............................................................................................................................................. 8-21
Acid Placement Techniques................................................................................................................. 8-22
Unit E Quiz .......................................................................................................................................... 8-24
Unit F: Sandstone Acidizing.................................................................................................................... 8-25
Hydrochloric Acid................................................................................................................................ 8-25
Hydrofluoric Acid................................................................................................................................ 8-25
Damage Removal................................................................................................................................. 8-25
Reaction Rates ..................................................................................................................................... 8-25
Sandstone-2000 TM ............................................................................................................................... 8-26

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 Chemical Stimulation

Formation Conditioning....................................................................................................................... 8-26

Clays .................................................................................................................................................... 8-26
Secondary Precipitation ....................................................................................................................... 8-28
Acid Systems ....................................................................................................................................... 8-29
Unit F Quiz .......................................................................................................................................... 8-33
Unit G: Damage Removal – Mud............................................................................................................ 8-34
Mud Removal....................................................................................................................................... 8-34
Limestone Formations.......................................................................................................................... 8-34
Acid–Surfactant Mud Removal Solutions (MCA-III) ........................................................................ 8-34
Non-Acid Mud Removal Solutions (Mud-Flush) ................................................................................ 8-35
Sandstone Formations .......................................................................................................................... 8-35
Hydrofluoric-Hydrochloric Acid Mixtures (HF Acid)......................................................................... 8-35
Oil Base Muds...................................................................................................................................... 8-35
True Oil Base Muds ............................................................................................................................. 8-36
N-VER-Sperse ..................................................................................................................................... 8-36
Additional References.......................................................................................................................... 8-36
Unit G Quiz: Damage Removal-Mud .................................................................................................. 8-37
Unit H: Paraffins and Asphaltenes .......................................................................................................... 8-38
Paraffins ............................................................................................................................................... 8-38
Cloud Point and Pour Point.................................................................................................................. 8-38
Factors Affecting Paraffin Deposition ................................................................................................. 8-39
Loss of Volatile Constituents from the Crude...................................................................................... 8-39
Suspended Particles in the Crude......................................................................................................... 8-39
Conditions Favoring Paraffin Deposition ............................................................................................ 8-39
Paraffin Precipitation during Fracture Stimulation .............................................................................. 8-40
Methods Used to Remove Deposits ..................................................................................................... 8-40
Methods for Decreasing the Severity of Deposition ............................................................................ 8-42
Asphaltenes .......................................................................................................................................... 8-44
Targon® II Solvent ............................................................................................................................... 8-44
Unit H Quiz.......................................................................................................................................... 8-45
Unit I: Scale Removal and Prevention..................................................................................................... 8-46
Scale Effects......................................................................................................................................... 8-46
Types of Scale...................................................................................................................................... 8-46
Scale Formation ................................................................................................................................... 8-47
Scale Form ........................................................................................................................................... 8-47
Acid Soluble Scale Removal................................................................................................................ 8-48
Regular Inhibited Acid......................................................................................................................... 8-48
Penetrating Acid................................................................................................................................... 8-48
Non-Emulsifying Acid (NE) ................................................................................................................ 8-49
Fe Acid................................................................................................................................................. 8-49
Multiple Service Acid (MSA).............................................................................................................. 8-49
Paragon Acid Dispersion (PAD).......................................................................................................... 8-49
Acid Insoluble Scale Removal ............................................................................................................. 8-50
GYPSOL .............................................................................................................................................. 8-50
Liquid Scale Disintegrator ................................................................................................................... 8-50
Equations for Determining Volume of Scale Present .......................................................................... 8-52
gallons 15% HCL
Acid Volume = 180 × 27.5906 ft 3
ft 3 ........................................................................... 8-53
= 4966.308 gallons
Scale Inhibition .................................................................................................................................... 8-53

© 2005, Halliburton 8•2 Stimulation I

 Chemical Stimulation

Scalechek® Scale Prevention Service................................................................................................... 8-53

Scalecheck® HT ................................................................................................................................... 8-53
Calchek Service.................................................................................................................................... 8-54
Protex-All Inhibitor.............................................................................................................................. 8-54
Chemical Placement Technique (CPT)................................................................................................ 8-55
Unit I Quiz ........................................................................................................................................... 8-56
Unit I Quiz ........................................................................................................................................... 8-57
Unit J: Placement Aids ............................................................................................................................ 8-59
Temporary Bridging Agents ................................................................................................................ 8-59
Selection of Bridging Agent ................................................................................................................ 8-59
Well Completion Type......................................................................................................................... 8-60
Placement Techniques.......................................................................................................................... 8-60
Carrier Fluid......................................................................................................................................... 8-60
Concentration of Bridging Agent......................................................................................................... 8-60
Particle Size Distribution ..................................................................................................................... 8-61
MATRISEAL® O ................................................................................................................................. 8-61
Matriseal® OWG Diverter.................................................................................................................... 8-62
Temporary Bridging Agents in Conjunction with Temblok Diverting Materials................................ 8-62
Unit J Quiz ........................................................................................................................................... 8-63
Unit K: Job Calculations.......................................................................................................................... 8-64
Calculations for Spotting Acid to the End of Tubing or Packer .......................................................... 8-64
Calculations for Balanced Acid Spot ................................................................................................... 8-65
Calculations for Flush and OverFlush.................................................................................................. 8-66
Unit Quiz K:......................................................................................................................................... 8-67
Self-Check Test for Section 8: Chemical Stimulation............................................................................. 8-68
Answer Key ............................................................................................................................................. 8-70
Self Check Test .................................................................................................................................... 8-73

© 2005, Halliburton 8•3 Stimulation I

 Chemical Stimulation

Use for Section notes…

© 2005, Halliburton 8•4 Stimulation I

 Chemical Stimulation

Introduction
Chemical stimulation is an important method of • Job Calculations
increasing oil and gas well production which,
even today, is still experiencing rapid technical
growth. Different processes have been used Learning Objectives
extensively since 1935.
Upon completion of this section, you will be
able to:
Topic Areas
• identify the acid types
The section units are: • list critical safety precautions
• Types of Acids • identify the primary corrosion factors and
• Safety list the inhibitors that help decrease
corrosion
• Reactions of Hydrochloric Acids
• identify damage removal methods of mud,
• Corrosion Inhibitors scale and paraffin
• Limestone Acidizing • identify acidizing treatments for limestone
and sandstone
• Sandstone Acidizing
• identify types of acids
• Damage Removal – Mud
• identify inhibitors
• Paraffin and Asphaltene Deposits
• calculate placement of acid
• Scale Removal and Prevention
• Placement Aids

© 2005, Halliburton 8•5 Stimulation I

 Chemical Stimulation

Unit A: Types of Acids

Major acids used in chemical stimulation
include hydrochloric acid, hydrofluoric- Hydrofluoric-Hydrochloric Acid
hydrochloric acid mixtures, and organic acids.
This unit will explain the roles of these acids in
chemical stimulation. A Hydrofluoric-Hydrochloric (HF) acid mixture
is the basic acid for treating sandstone
formations with less than 20% HCL solubility.
Hydrochloric Acid These mixtures are used for removal of damage
caused by drilling mud, filtrate water, water-
swollen clays, migrating clays, and other small
Hydrochloric (HCL) acid containing inhibitors
formation particles. HF acid is typically
is the base solution for most oil field acidizing
prepared in the field by adding ammonium bi-
treatments. Depending on the use and
fluoride (ABF) to HCL. Hydrofluoric acid is
requirements of the treatments, the concentration
discussed further in Unit F, Sandstone
may range from 1% to about 35%. Hydrochloric
Acidizing.
acid reacts rapidly with carbonate formations
and is used in treating sandstone formations.
HCL can serve as the basic acid for damage Additional Acids
removal in addition to matrix and fracture
acidizing.
Two organic acids also used are formic and
Hydrochloric acid is a mixture of hydrogen and acetic. These are weaker than hydrochloric acid
chlorine gases dissolved in water. This gas is and exhibit less corrosion problems than HCL;
called hydrogen chloride and is readily soluble which means their hydrogen ions are released
in water up to 42% by weight at 60°F. more slowly than HCL with most materials
However, a solution of this concentration is found in wells. Ten- percent formic acid will
impractical since hydrogen chloride gas will dissolve as much limestone as eight- percent
come out of hydrochloric acid at temperatures HCL. Six percent HCL will dissolve as much
above 60°F. limestone as ten-percent acetic acid. Due to their
Commercially available hydrochloric acid has low degree of corrosiveness, organic acids can
been standardized at 20° Be (Baume). This is be used at higher temperatures for acidizing
equivalent to 31.45% acid, by weight, with a treatments. Acetic acid is the only acid that
density of 9.67 lb/gal. Higher concentrations of won’t damage chrome plating. It is useful for
acid can be purchased at 22° Be, or 35.2% acid. acidizing wells that contain pumps using chrome
It has a specific gravity of 1.179 and a density of plated parts. Organic acids may be used with
9.82 lb/gallon. HCL to allow deeper penetration and to provide
unique etching properties with some formations.

© 2005, Halliburton 8•6 Stimulation I

 Chemical Stimulation

Unit A Quiz

Fill in the blanks with one or more words to check your progress in Unit A.
1. Two major acids used in chemical stimulation are ____________________ and
____________________.

2. Hydrochloric acid can serve as the basic acid for ____________________ ____________________
in addition to ____________________ and ____________________ acidizing.

3. Commercially available hydrochloric acid is standardized at __________ °Be or __________%.

4. Hydrofluoric – Hydrochloric acid mixture is the basic acid for treating ____________________
formations having 20% or less HCL solubility.

5. Two organic acids commonly used are ____________________ and ____________________.

6. ____________________ acid is the only acid that will not damage chrome plating.

Now, look up the suggested answers in the Answer Key at the end of this section.

© 2005, Halliburton 8•7 Stimulation I

 Chemical Stimulation

Unit B: Safety
Safety is a top priority in all job procedures. • NO SMOKING around an acid tank. Tanks
Before pumping or handling acids or other containing acid or that have had acid in them
stimulation chemicals, you should study the can have an explosive mixtures of gases and
safety precautions given in the Chemical liquids trapped inside. Crude oil vapors
Stimulation Manual excerpts on HalWorld. mixed with air or hydrogen gas present in a
This unit discusses several important tank is also a possibility. Hydrochloric acid
precautions to use when handling chemicals on reacts with steel to produce iron chloride and
the job. hydrogen gas—a potentially explosive
situation.
• Even though an acid tank is coated with a
Safety Precautions sealant, there may be some exposed metal.
Hydrogen gas could be present.
Some critical safety precautions are as follows:
• Always add the water to the tank first and
• Always wear rubber gloves when working then add the concentrated acid. Never add
around acid. water to acid or fill the tank with acid first.
This increases the risk of splashing and can
• Goggles should be worn due to possible leaks
generate a large amount of heat.
in pump lines which may occur when
acidizing a well under pressure. • Hydrogen, mixed with air in the ratio of one
part per 24 parts, is an explosive mixture.
• Safety precautions should be taken when
For this reason, be aware of metal
handling hoses during the loading of trucks
connections when loading hoses. They could
or tanks or when disconnecting lines on a job.
strike the tank and ignite an explosion with
Acid may be left in the hoses.
the smallest of sparks.
• It is always a good practice to notify
• Clothes contaminated with chemicals should
personnel on location when acid is being
be removed and thoroughly washed before
used under pressure. All personnel should be
wearing them again. Wash off any chemical
kept at a safe distance.
spills with water immediately.
• Acid pump trucks or transport trucks should
• Wear a dust mask when handling powders.
be furnished with first aid kits containing
Inhalation of any powdered material can be
soda (sodium bicarbonate) for acid burns.
irritating even if the chemical is not toxic.
Drivers and operators should ensure that it is
always accessible in case of emergency. A The safety rules given here are a few of the rules
solution of one teaspoonful of soda to a pint listed in the Chemical Stimulation excerpts on
of water should be kept for use in the eyes. HalWorld. Be sure to study the remaining rules.
Dry soda can be applied directly to the skin An important section to be read in the safety
and then rinsed with water. DO NOT use dry section of the Chemical Stimulation manual on
soda in the eyes. HalWorld is “Hydrogen Sulfide”.
NOTE: When washing eyes, use a gentle
flow of water when rinsing. You could
damage an eyeball or even wash it out of its
socket with a heavy stream of water.

© 2005, Halliburton 8•8 Stimulation I

 Chemical Stimulation

Unit B Quiz

Fill in the blanks with one or more words to check your progress in Unit B.
1. Because of possible leaks in pump lines, ____________________ should be worn on chemical jobs.

2. First aid kits on acid trucks should contain ____________________ ____________________ that can
be dissolved in water for treating acid burns.

3. Dry soda can be applied directly to the ____________________ but not to ____________________.

4. The possible presence of ____________________ ____________________ is one reason smoking is

not allowed around an acid tank.

5. When working with acid and water, always put the ____________________ in first and then add the
____________________.

6. Wear a ____________________ ____________________ when handling powders.

Now, look up the suggested answers in the Answer Key at the end of this section.

© 2005, Halliburton 8•9 Stimulation I

 Chemical Stimulation

Unit C: Reactions of Hydrochloric Acid

Reaction rates and products are important Concentrations of HCL acid solutions may range
considerations in acidizing. The various from 1% to approximately 35% depending on
characteristics can have an effect on the choice the use and requirements of the treatment. It
of acid systems. may be your responsibility to mix the various
acid blends required in stimulation treatment
applications. Tables like the following one have
HCL Reactions been developed to assist you in determining the
proper amounts of concentrated acid and water
When 1,000 gallons of 15% hydrochloric acid to use when mixing an acid solution (see Table
solution reacts with calcium carbonate 8.1). These tables are usually posted in acid
(limestone), it will dissolve 10.9 cubic feet terminals.
(1843 lb) of the limestone. The products Information for both 22 °Be and 20 °Be acid is
resulting from “spending” the 15% HCL given in the table. Before using the table, find
solution upon the limestone will be: out which of the two acid concentrations are
• 2050 pounds of calcium chloride (CaC12) being stocked in the service center.
• 40 gallons of water (H2O) To illustrate the use of the table, assume that 20
°Be acid is stocked in the storage tanks and that
• 6620 cubic feet of carbon dioxide gas (CO2) you need to mix 1000 gallons of 15% HCL acid
at standard conditions solution. You need to determine how much
The total volume occupied by 1000 gallons of water to add to the acid transport and how much
15% hydrochloric acid after the reaction is: strong acid to add to the water to make the
solution.
• 912 gallons of water pumped into formation
In Table 8.1, locate the heading “Gals 20 °Be
• 40 gallons water made by chemical reaction Acid & Water To Make 1000 Gals Acid.”
• 68 gallons of volume occupied by 2050 Under this heading observe that acid and water
pounds of calcium chloride amounts are given in separate columns. In the
extreme left-hand column “HCL% Acid” is
• 1020 gallons total, assuming no volume is given. Under this column locate 15 % and move
occupied by the carbon dioxide gas or horizontally across the chart. You will read 442
diluted by formation brine gallons of 20 °Be acid and 558 gallons of water
15% hydrochloric acid spent on limestone required to mix 1000 gallons of 15% HCL acid
becomes a 20.0% solution of calcium chloride solution.
having a specific gravity of 1.175 and weighing
9.79 lb/gal.

© 2005, Halliburton 8 • 10 Stimulation I

 Chemical Stimulation

Gals 22°Be Acid & Gals 20°Be

Water To Make 1000 Acid & Water To
Gal Acid Make 1000 Gal Acid
Eqiv.
HCL Gal of
Wt. In Hydrostatic
% S. G. Acid Water Acid Water 15% per
lb/gal psi/ft depth
Acid 1000
gals
1 1.005 24 976 28 972 8.83 .435 62
2 1.010 49 951 55 945 8.42 .437 125
3 1.015 73 927 83 917 8.46 .439 189
4 1.020 98 902 112 888 8.50 .442 253
5 1.025 124 876 140 860 8.54 .444 318
6 1.030 149 851 169 831 8.59 .446 383
7 1.035 175 825 199 801 8.63 .448 449
8 1.040 201 799 228 772 8.67 .450 516
9 1.045 227 773 258 742 8.71 .452 583
10 1.050 253 747 288 712 8.75 .454 651
11 1.055 280 720 318 682 8.79 .457 723
12 1.060 307 693 349 651 8.84 .459 788
13 1.065 334 666 379 621 8.88 .461 858
14 1.070 362 638 410 590 8.92 .463 929
15 1.075 389 611 442 558 8.96 .465 1000
16 1.080 417 583 473 527 9.00 .468 1072
17 1.085 445 555 505 495 9.05 .470 1144
18 1.090 473 527 538 462 9.08 .472 1217
19 1.095 502 498 570 430 9.13 .474 1290
20 1.100 531 469 603 397 9.17 .476 1364
21 1.105 560 440 636 364 9.21 .478 1439
22 1.110 589 411 669 331 9.25 .481 1514
23 1.116 619 381 703 297 9.30 .484 1592
24 1.122 650 350 738 262 9.35 .486 1670
25 1.127 680 320 772 228 9.39 .488 1747
26 1.132 710 290 806 194 9.43 .490 1825
27 1.136 740 260 840 160 9.46 .492 1902
28 1.141 771 229 875 125 9.50 .494 1981
29 1.146 802 198 910 90 9.55 .497 2061
30 1.153 835 165 948 52 9.60 .499 2145
31 1.158 866 134 983 17 9.65 .502 2226
31.45 1.160 880 120 1000 0 9.66 .503 2262
32 1.163 898 102 --- --- 9.69 .504 2308
33 1.168 930 70 --- --- 9.74 .506 2398
34 1.173 962 38 --- --- 9.78 .508 2481
35 1.178 990 10 --- --- 9.82 .510 2558
35.2 1.179 1000 -- --- --- 9.83 .510 2573
Table 8.1

© 2005, Halliburton 8 • 11 Stimulation I

 Chemical Stimulation

Unit C Quiz

Fill in the blanks with one or more words to check your progress in Unit C.
1. 1000 gallons of 15% hydrochloric acid will dissolve __________ pounds of limestone.

2. The products resulting from the “spending” of 15% HCL on limestone are __________ pounds of
calcium chloride, 40 ____________________ of ____________________, and __________ cubic
feet of ____________________ ____________________ gas at standard conditions.

3. The total volume of 1000 gals of 15% HCL after spending is ____________ gallons.

4. If you have 20 °Be acid, how much acid and water are required for 1000 gallons of 10% HCL?

__________ acid

__________ water

Now, look up the suggested answers in the Answer Key at the end of this section.

© 2005, Halliburton 8 • 12 Stimulation I

 Chemical Stimulation

Unit D: Corrosion Inhibitors

Corrosion is defined as “the deterioration of a and 85M, as well as the newer inhibitors HAI-
substance (usually a metal) because of a reaction GE and OS. These inhibitors will not protect
with its environment.” In well stimulation, the such metals as aluminum and magnesium from
primary concern is the reaction of acids on the attack by hydrochloric acid. In addition,
well equipment, including tubular goods, during galvanized coatings and chromium plating will
acidizing treatments. This reaction can be be attacked by inhibited hydrochloric acid. This
minimized by the use of corrosion inhibitors. is true with these inhibitors and with all other
inhibitors, including competitive materials.
There is a dual purpose for adding inhibitors to Some types of chrome and steel alloys can be
acid: the first is to protect our equipment and protected. Contact Duncan Research for further
the second is to protect the customer’s well information about these alloys.
equipment. Several types of inhibitors are
available for use in the oilfield. Acid corrosion inhibitors can be used up to
about 500°F. At temperatures above 275°F a
secondary component may need to be added.
Corrosion of Metals Two such components are Halliburton Inhibitor
Intensifiers 124 and 500 (HII 124 and HII 500).
Several factors govern the degree of attack acid NOTE: When hydrochloric acid is mixed with
has on steel. The primary factors are: acetic or formic acid, the inhibitors used for
• temperature HCL are the inhibitors used in these mixtures.
In general, the mixing procedures to follow
• time of contact
when mixing hydrochloric acid and organic
• type of acid corrosion inhibitors together are:
• pressure • The required volume of water is first added
to the tank
• type of steel
• The proper, measured volume of inhibitor is
• ratio of volume of acid to exposed steel
added to the water and agitated
surface area
• The concentrated acid from storage is
The longer acid is in contact with steel, the
thoroughly mixed until uniformity is
greater the amount of steel dissolved. The
obtained.
corrosion rate increases with increasing
temperatures. You must remember that If the acid mixture requires additional additives,
inhibitors do not stop corrosion; they only they may be added to the water prior to final
decrease the rate of corrosion. This rate of agitation.
corrosion can be decrease to an acceptable level
It is very important that the steps of addition of
if the proper inhibitor type and concentration are
material, agitation and blending be followed.
used. Figure 8.1 shows the corrosion rate of
Even if each chemical has been dumped into the
15% HCL with different concentrations of HAI-
tank, do not assume that uniform mixing will
85 on N-80 steel at 200 °F. Notice that the
occur while being moved to the location.
Halliburton standard is a “Maximum Total
Corrosion Loss” of 0.05 lb/ft2 total steel For more complete and detailed mixing
dissolved over the life of the test. procedures, refer to the confidential field
bulletins for inhibitors found on HalWorld
Inhibitors being used presently in hydrochloric
acid are Halliburton Acid Inhibitors HAI-81M

© 2005, Halliburton 8 • 13 Stimulation I

 Chemical Stimulation

MSA Inhibitors procedures for MSA-II inhibitor are the same as

for other acid inhibitors. The Chemical
Stimulation Manual on HalWorld should be
Organic acids such as formic and acetic require
used when determining amounts of MSA
an inhibitor other than HA1-81, 85M, or 72 E+.
inhibitor to use.
MSA-II and the newer MSA-III inhibitors are
designed for use in these acids. MSA-II and Other inhibitors are designed for many purposes.
MSA-III inhibitors are not recommended for use You should become familiar with these
in hydrochloric acid solutions. Mixing inhibitors and their functions.

Figure 8.1

© 2005, Halliburton 8 • 14 Stimulation I

 Chemical Stimulation

Unit D Quiz

Fill in the blanks with one or more words or check the correct answer to check your progress in
Unit D.
1. The primary factors governing the degree of attack acid has on steel are:

________________________________________________

________________________________________________

________________________________________________

________________________________________________

________________________________________________

________________________________________________

2. ______ True ______ False Inhibitors will stop corrosion.

3. Above 275° F, secondary components such as ____________________ and ____________________

may be needed for better corrosion protection.

4. ______ True ______False Adequate mixing will occur if inhibitor is dumped into a transport and
the transport is driven over rough roads to the location.

5. The Halliburton standard limit for corrosion, over which more inhibitor should be added is
__________ lb/ft2

6. MSA Inhibitor is required when you use ____________________ acids.

Now, look up the suggested answers in the Answer Key.

© 2005, Halliburton 8 • 15 Stimulation I

 Chemical Stimulation

Unit E: Carbonate Acidizing

Successful acidizing in limestone and dolomite maximum production is the result of minimum
formations depends on a productive drainage damage.
pattern formed by the action of the acid. One or
a combination of the following ways that acid
invades a formation accomplishes this:
(1) entering natural existing fractures
(2) entering cracks caused by hydraulic
fracturing
(3) entering the permeability of the formation
The extension of an effective drainage pattern
into a productive zone requires deep penetration
into some formations regardless of whether the
crevices exist naturally or are artificially made.
WELLBORE SKIN OR ZONE
Penetration is dependent upon the permeability, OF DAMAGE
porosity, oil saturation, the amount of productive
interval, the formation pressure and the depth of
the zone.
PRESSURE IN
Unplugged flow paths should exist from the FORMATION
wellbore face to the outer limit of the formation.
Therefore, it is important that reaction products
and acid insoluble fines, which have been
PRESSURE DROP
dislodged by the chemical action on the ACROSS SKIN
formation, be removed after acidizing.

Matrix Acidizing WELLBORE

PRESSURE

Matrix acidizing consists of treating at a rate and Figure 8.2 - Schematic of a damaged well.
pressure low enough to avoid fracturing the Top view with oil or gas flow. Side view with
formation. This allows treatment of the natural pressure drop.
permeability, whether it is between the grains of
rock, in the vugular spaces of limestone or in
natural fractures. The skin factor can be reduced if near-wellbore
Matrix acidizing enhances well productivity by damage is removed or if a highly conductive
reducing the skin factor. Skin is the term used to structure is placed in the formation. In either
quantify damage that occurred to the formation case, the result is an increase in the production
during drilling and completion. Damage occurs in rate of a well and/or the reduction of the
all stages of the life of a well, and it is drawdown pressure differential. Decreased
impossible to completely eliminate this drawdown can help prevent formation collapse in
phenomenon. But, to produce hydrocarbons at weak formations, reduce water or gas coning,
an economical and profitable rate, maximum minimize both organic and mineral scaling, and
productivity is usually desired. In radial flow,

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 Chemical Stimulation

help ensure that a greater percentage of the Fracture Acidizing

completed interval contributes to production.
Matrix acidizing should be considered when Most limestone and dolomite formations have
damage is present or when a water zone or gas low permeability. Acid injected into these low
cap is close and fracturing could result in high permeability formations, even at moderate rates,
water production or excessive gas/oil ratio. usually result in a fracture type acid treatment.
Fracture Acidizing is the most widely used
treatment for limestone and dolomite
Expected Results formations. The success of a fracture acidizing
treatment depends upon the ability to create a
Results from matrix acidizing depend upon the conductive fracture with enough length and
type of permeability and porosity present and the height. Most fractures are vertical, and the
presence and extent of any formation damage. productivity should increase as the vertical
For example, assume that flow from a producing fracture height approaches the formation height.
limestone or dolomite is radial and the The productivity should also increase as the
permeability near the wellbore is the same as it fracture length approaches the drainage radius of
is deep in the formation (no damage). In this the well. Of course, the fracture must have
case, an increase in the permeability due to adequate flow capacity so that produced fluids
acidizing in the immediate vicinity of the well will have a passageway from the formation into
will give a relatively small increase in the the well bore.
production capacity of the well. In fact, if the To achieve good fracture extension and adequate
acid completely dissolves the limestone or flow capacity, an acid that has low fluid loss and
dolomite up to a radius of five feet, the
produces good flow capacity should be used.
production capacity of the well can be increased
by only 65% maximum. However, if the well is
partially plugged, and the damage can be Formation Core and Fluid
removed to a radius of five feet around the well
bore, the production capacity can increase by as Testing
much as 350%.
The following tests performed on formation core
samples are useful in planning acid treatments.
Types of Porosity In the fluid loss test, fluid is forced through a
core plug cut from a submitted core sample. A
When the porosity is intergranular (between differential pressure of 1,000 psi is used, and the
grains) and the formation is the same all over test temperature duplicates the bottom hole
(homogeneous), then matrix acidizing of this temperature of the well. Various types and
type of formation might produce approximately quantities of fluid loss additives are tried in
a 60% increase in production if no damage order to establish the most effective additive to
exists. Should damage exist, much larger use in the preflush and the acid. The fluid
production increases could be expected. efficiency of the acid and water preflush can be
If the porosity is vugular (large holes), the determined from these tests. These fluid
formation is homogeneous, and no damage efficiencies are used in calculating the created
exists, then production increases in the 100- fracture area.
150% range are possible. If damage exists, then A rotating disc reaction rate apparatus is used to
greater production increases can be expected. determine the true surface reaction rate and
If there are naturally occurring fractures in either order of reaction of the formation to be acidized.
a vugular or intergranular type formation, then Another test involves determining fracture flow
production increases of several hundred percent capacity from acid etched cores. On of the
might be possible. differences between fracture acidizing and

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 Chemical Stimulation

conventional water frac or oil fracs is that are placed together, and pressure is applied. The
usually no propping agent is used. The acid resulting fracture flow capacity can then be
produces flow capacity by removing limestone measured.
or dolomite from the fracture faces. However,
There are some formations in which fracture
laboratory tests indicate that certain types and
flow capacity cannot be created with acid, either
concentrations of acid can create more fracture
because the formation etches smoothly or
flow capacity.
because large quantities of insoluble fines plug
The etching time is also important. Laboratory the channels. In these formations, a SUPRA
etching tests determine the etching time and type technique or a conventional fracturing solution
acid which produce the maximum flow capacity. carrying a propping agent should be considered.
These tests are conducted by placing two core The acid etching tests can be used to determine
faces in a chamber approximately 0.1 inch apart. the feasibility of fracture acid stimulation and
Acid flows radially across this simulated the best type acid to use. Figure 8.3 shows a
fracture at 1,000 psi pressure and at simulated decision tree to help determine what type of
bottom hole temperature. After a certain etching treatment to perform.
time, the cores are removed, the etched surfaces

Figure 8.3 - Acid Treatment Decision Flowchart

© 2005, Halliburton 8 • 18 Stimulation I

For a successful acid treatment, the acid solution Fracture Acidizing Plan
must be compatible with the produced fluids. Calculations
Emulsion tests should always be run with the
produced fluids and the treating solution. These
The information obtained in the tests described,
tests are run by mixing equal volumes of the
along with certain well and formation data are
treating solution and the produced oil with high
used in computerized design programs. The
shear. The time and amount of separation are
calculations in Halliburton’s Acid Design
noted. Complete separation of the mixture
Program have been incorporated into FracPro
within ten to fifteen minutes is desirable. The
PT, a 3-dimensional fracture simulator which
tests are run with both live and spent acid
can determine the conductive fracture length and
because the fines released from some formations
the productivity increases that are possible. If
tend to stabilize emulsions. The acid used in the
cores are not available, a treatment design can be
emulsion tests should contain all of the additives
run using information determined previously on
that are going to be used in the job since many
cores from the same formation and same area.
of these additives affect the emulsion tests.
Acid can cause some of the asphaltene
components of the crude to fall out of solution. Acid Systems
These solids are commonly called “acid sludge.”
A sludge test should be run to see if anti-sludge In recent years, Halliburton has made an effort
agents are needed in the acid. to simplify it’s terminology in describing the
wide variety of acid systems and additives. The
Carbonate 20/20 program helps fill a void in the
Tubing Movement Program oil industry created by the lack of personnel that
can effectively design acid treatments. Several
The Tubing Movement Program (TMP) helps standard acid blends resulted from the Carbonate
predict the amount of tubing movement that can 20/20 initiative.
occur because of the high pump rates and fluid
volumes. This tubing movement is primarily Carbonate Completion Acid
caused by changes in the tubing through the
cooling effects from the pumped fluids, from the
Carbonate Completion Acid (CCA) minimizes
pressures exerted by fluids in the tubing and
compatibility problems, especially for reservoirs
annulus, and from the friction effect of these
containing asphaltene crudes. CCA uses HAI-
pumped fluids. One of the main advantages of
GE corrosion inhibitor which is compatible with
the program is that it uses bottom hole treating
non-ionic and anionic surfactants.
pressure as a starting value along with a specific
pump rate. A computer print-out includes: Although the CCA system is primarily used for
acidizing carbonate reservoirs that contain
• surface injection pressure asphaltene crude, it can also be used on “sour”
• total tubing movement, which includes wells (wells containing hydrogen sulfide) if
sulfide scavenger is added and on sweet wells if
• piston effect ferric iron control is used. Because the inhibitor
• ballooning effect and antisludging agent are compatible, they can
prevent sludging without compromising
• frictional effect corrosion protection. For effective corrosion
• buckling effect inhibition, the upper temperature limit of the
CCA system is approximately 200°F in 15%
• thermal effect HCL. Depending on acid concentration, contact
• the amount of force required to be exerted in time, and metal type, this temperature limit can
order to overcome these five effects be higher or lower.

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 Chemical Stimulation

Carbonate Stimulation Acid Zonal Coverage Acid

The Carbonate Stimulation Acid (CSA) system The Zonal Coverage Acid (ZCA) System is a
is used in carbonate formations for stimulating crosslinked acidizing fluid system that can be
production. Operators can use CSA to stimulate used in carbonates for fracture acidizing and for
carbonate formations by fracture acidizing or diversion during matrix acidizing. The use of
matrix acidizing. Regardless of the approach, the crosslinked acidizing fluids in the past was
acid should be viscous to promote effective limited. The high fluid viscosity required during
stimulation. pumping increased frictional pressures, which
required greater pumping horsepower. In
Gelling agents made from synthetic polymers
addition, obtaining a live-acid crosslinked fluid
are the most useful viscosifiers for acidizing
was an expensive process. In many cases, fully
carbonate formations. These materials resist acid
crosslinked acids were not necessary to retard
hydrolysis (breaking) over a wide range of
the reaction of HCL on carbonates; viscosifying
temperatures. Currently, Halliburton offers four
the acid provided ample retardation. In such
gelling agents made from synthetic polymers:
treatments, however, much of the acid was lost
SGA-HT, SGA-II, SGA-III and SGA-IV.
as a result of leakoff through wormholes (Figure
The most effective gelling agent for acidizing 8.4).
carbonate formations depends on the agent's
working temperature range, ease of mixing,
compatibility with other additives, and control
of reactivity. Based on these characteristics,
SGA-HT is usually the best gelling agent to use
for acidizing carbonate formations. However,
this viscosifier is also significantly more
expensive than SGA-II, III and IV. SGA-II and
SGA-III can be used at lower temperatures and
SGA-IV is the only gelling agent compatible
with sulfide scavengers. Table 8.2 presents
various properties of these three gelling agents.

Viscosity Ability
170 S-1 Temp Limit to
Figure 8.4 – Leakoff due to wormhole
Product Charge growth during acid fracturing
150°F (°F) cross-
2% Conc. link

SGA-HT 27 cp 400-425 + No
SGA-II 19 cp 200-225 - Yes
Zonal Coverage Acid (ZCA) system is an in-
situ crosslinked gelled acid system. When this
SGA-III 39 cp 300-325 + Yes* system is used, fluid loss can be controlled as
SGA-IV 33 cp 200-225 + Yes** the acid leaks off through wormholes and
Table 8.2 – Acid Gelling Agents spends. Once the acid is nearly spent, the system
crosslinks, blocking wormholes and preventing
*SGA-III must be premixed in HCL for 2 to 4 further loss of acid from the fracture face. The
hours to develop adequate crosslink sites. system will not break until the acid is
**SGA IV is the only acid gelling agent completely spent.
compatible with SCA-130 sulfide scavenger. SGA-II, III or IV can be used as a gelling agent
in the ZCA system. SGA-III must be premixed
in acid for 2 to 4 hours to develop adequate
crosslink sites for use in the ZCA system.

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 Chemical Stimulation

Therefore, if planning to run ZCA system fluids Handbook can be used when you design an
on-the-fly, use SGA-II or IV gelling agents. FRA treatment.

Carbonate Emulsion Acid Hot Rock Acid

Carbonate Emulsion Acid (CEA) is an The Hot Rock Acid (HRA) system is a totally
emulsified acid system used in carbonate organic acid system with a dissolving power
reservoir stimulation jobs that require retarded equal to 15% HCL. HRA is an acid system
acid reaction rates. The upper temperature limit specifically for high temperature wells. It
of the system is approximately 400°F. In consists of both acetic and formic acids set at
fracture acidizing applications, formations that different ratios to eliminate secondary
produce heavy crude oils with high quantities of precipitation problems and maintain maximum
asphaltenes tend to respond best to CEA. dissolving power. The Hot Rock Acid system
Because of its excellent acid retardation increases stimulation effectiveness and reduces
properties, the system has also been successfully corrosion rates. Specifically, it allows extended
used in higher-temperature matrix acidizing reaction times, provides built-in iron control,
applications. Under high-temperature conditions, and enhances the performance of acid gelling
the CEA system allows live acid to penetrate agents. Because of the reduced interfacial
deeper into the formation matrix than other acid tension the service provides, emulsion and
formulations. As a result, wormholing is sludging problems are less likely.
improved. Although the base acid cost for the Hot Rock
By volume, 70% of the CEA system consists of Acid system is about twice that of HCL, the
22% hydrochloric acid as the internal phase and reduction in corrosion inhibitor loading and the
30% of No. 2 diesel as the external phase of the reduced gelling agent requirement generally
emulsion. The CEA system is formed through result in lower overall treatment costs. In
the use of AF-61 emulsifier along with a addition to the two acids, the system includes
corrosion inhibitor. MSA-II inhibitor, SGA-HT gelling agent and an
appropriate surfactant. Iron-control additives can
be used but are not necessarily required.
Fines Recovery Acid

Fines Recovery Acid (FRA) is an energized acid Additional Reference

system for stimulating carbonate formations
with bottomhole static temperatures (BHST) up For more detailed information and mixing
to 150°F. The energized phase of FRA is procedures, consult the Carbonate 20/20
70% nitrogen. The acid is usually 20% technical bulletins on HalWorld.
HCL with a gelling agent and inhibitor. In
addition to demonstrating low liquid
concentrations and good fluid loss, the FRA Preflushes
system can also be used in low-pressure,
liquid-sensitive wells that normally produce In fracture acidizing, good productivity can be
fines during acidizing, or wells that have obtained if adequate fracture geometry can be
fluid and fines recovery problems. created that has enough conductivity. The
fracture geometry is determined by the fluid
Under matrix acidizing conditions, the FRA properties such as fluid loss, fluid viscosity and
system can be used to divert in long the injection rate. However, the conductivity of
horizontal open hole sections. the fracture is a function of the amount and
pattern of rock removed from the fracture faces,
STIMWIN, STIM2001, FOAMUP, not from acid leaking off into the formation.
FracproPT and the Halliburton Nitrogen

© 2005, Halliburton 8 • 21 Stimulation I

 Chemical Stimulation

The distance that a conductive fracture can be natural fractures, and fluid-loss control is
created is dependent upon the reaction rate of reestablished.
the acid as well as the fluid properties. One
method of obtaining slower reaction rates is to SUPRA CE (Conductivity
use water preflushes to cool the fracture faces. Enhancement)
Preflushes also produce wider fractures for the
acid, which improves the rock surface area to
When using the SUPRA CE technique, service
acid volume ratio. This gives better penetration
operators pump a viscous pad fluid ahead of the
distance of live acid. Acid fluid loss is also
acid and behind an optional nonviscous, cool
decreased by the use of water preflushes.
down prepad. As the viscous pad is pumped, it
A viscous preflush can be used like a non- generates fracture geometry. Because the acid
viscous preflush. The increased viscosity has that follows it is less viscous, it “fingers”
the added advantage of creating a wider and through the viscous pad. This fingering process
possibly higher fracture. limits the acid contact to the formation face,
which creates etched and nonetched areas. This
process results in longer acid penetration
Acid Placement Techniques distance and possibly more effective
conductivity at a greater distance along the
The SUPRA (sustained-production acidizing) induced fracture.
techniques are another result of the Carbonate
20/20 initiative. They detail the different
methods that can be used under various well
conditions to generate the optimum conductive
geometry in the reservoir being treated.

SUPRA FLC (Fluid-Loss Control)

SUPRA FLC controls acid fluid-loss in induced

and natural fractures. In rock matrix or natural
fracture systems, acid leakoff must be controlled
so that live acid will remain within the fracture
and generate effective etched fracture length.
Under some conditions, Carbonate 20/20
treating fluids provide fluid-loss control. Under
Figure 8.5 - SUPRA CE Technique
excessive fluid-loss conditions, some additional
fluid-loss material may be required in addition
to alternating phases of acid and nonacid fluids.
The acid provides conductivity, and the nonacid SUPRA EHC (Etched Height Control)
fluid (containing fluid-loss additive) establishes
or re-establishes fluid-loss control.
The SUPRA EHC technique uses fluid density
The nonacid phase also acts as an acid extender, differences to control fluid placement in certain
allowing a sufficient volume of acid to penetrate sections of an induced vertical fracture. This
the required distance while reducing the volume technique can place acid in areas of a fracture
of acid necessary for that distance. Phases can be that do not contain water or possibly a gas cap.
alternated at any time, depending on the treating Figure 8.6 shows the fracture-acidizing process
conditions. The acid leaks off and forms including SUPRA EHC. Advantages of the
wormholes or goes into natural fracture systems. SUPRA EHC system are that it prevents the acid
The nonacid phase (containing fluid-loss treatment from entering unwanted zones such as
additives) sands off and seals up wormholes or

© 2005, Halliburton 8 • 22 Stimulation I

 Chemical Stimulation

water-producing intervals and gas caps, and that Closed-Fracture Acidizing (CFA)
it uses less acid.
With the aid of nitrogen, many heavier fluids The closed-fracture acidizing (CFA) technique
can be lightened by foaming (gas content greater reopens previously created fracture systems with
than 55%) or commingling (gas content less a prepad fluid pumped at high rates. The
than 55%) gas in the fluid. Even with the best fractures are then allowed to close naturally, or
engineering and design, this treatment may not part of the prepad is flowed back to force the
always work. fractures to close. Next, acid and any necessary
additives and diverters are pumped below
fracturing pressure. This technique can also be
used immediately after a fracture acidizing
treatment performed for enhanced etched
conductivity.
For more information on these acid placement
techniques, consult the Carbonate 20/20 best
practices page on HalWorld.

Figure 8.6 - Fracture-Acidizing Process

Including SUPRA EHC

© 2005, Halliburton 8 • 23 Stimulation I

 Chemical Stimulation

Unit E Quiz

Fill in the blanks with one or more words to check your progress in Unit E.
1. Matrix acidizing enhances well productivity by reducing the ____________________ factor.

2. Matrix acidizing requires that rates and pressures be controlled so that ____________________ does
not occur.

3. Decreased well pressure drawdown can help prevent formation ____________________ in weak
formations, reduce water or gas ____________________, minimize both organic and mineral
____________________.

4. The most widely used treatment for limestone and dolomite is _____________________
____________________.

5. One method of obtaining slower reaction rates is to use water _____________________ to

____________________ the fracture faces.

6. _____ True ______ False Fracture conductivity is generated by acid leaking off into the
formation.

7. Which Carbonate 20/20 acid system is used when asphaltenes are a problem?

_____ a) Carbonate Stimulation Acid

_____ b) Carbonate Completion Acid

_____c) Zonal Coverage Acid

_____d) Carbonate Emulsion Acid

8. Which acid system uses a crosslinked gel to control leakoff?

_____a) Carbonate Stimulation Acid

_____b) Carbonate Completion Acid

_____c) Zonal Coverage Acid

_____d) Carbonate Emulsion Acid

9. What does SUPRA stand for?

____________________-____________________ ____________________

Now, look up the suggested answers in the Answer Key.

© 2005, Halliburton 8 • 24 Stimulation I

 Chemical Stimulation

Unit F: Sandstone Acidizing

Basically, two types of acids are used in reaction products and also has a significant
sandstone acidizing: hydrochloric acid alone and effect upon the reaction rate.
hydrofluoric-hydrochloric acid mixtures.
Normally, these treatments are used to stimulate
near the wellbore (maximum 5-6 feet out). Damage Removal
These treatments are done at rates that will not The hydrochloric-hydrofluoric acid mixture (HF
fracture the formation. They can be very Acid) has application in mud-or clay-damaged
effective in removing damage near the wellbore. sandstone formations. There are two
fundamental types of clay damage in sandstone.
One type is mud damage where bentonite
Hydrochloric Acid drilling mud particles have coated the formation
face or have invaded the formation. This type of
Even though hydrochloric acid will not dissolve damage is considered to be very shallow,
sand or clays, it is still useful in acidizing possibly only an inch or so deep.
sandstone formations. It will dissolve any
carbonates that might be present in the formation The second type results from naturally occurring
and will also partially dehydrate water-swollen clays that have either migrated toward the
clays. wellbore and are plugging flow channels or have
become hydrated and swollen due to contact by
In sandstone stimulation, hydrochloric acid is fresh water. This type of damage is deeper into
usually combined with Morflo III to produce the formation than mud damage.
MCA (Mud Cleanout Acid). The hydrochloric
acid in MCA shrinks swollen clay particles.
Morflo III disperses clays and acts as a Reaction Rates
surfactant to aid in emulsion prevention and
faster cleanup. The Speed with which hydrofluoric acid reacts
upon sandstone is affected by
Hydrofluoric Acid • physical and chemical composition of the
formation
In contrast to hydrochloric acid, hydrofluoric • temperature
acid does have the ability to dissolve silica
(sand) or silicates such as clays, silt, shale and • surface area of rock exposed to a particular
feldspars. Since bentonite is a silicate, it can volume of acid
also be dissolved by hydrofluoric acid.
• concentration of excess hydrochloric acid
Sandstone formations having permeability
damage due to clay migration or benetonite Sandstone formations are basically composed of
drilling mud can usually be helped by a quartz, with some limestone, dolomite,
hydrofluoric acid treatment. feldspars, and several clay minerals.
Hydrofluoric-hydrochloric acid mixtures react
Hydrofluoric acid is usually pumped as a
with these materials at varying rates. Therefore,
hydrochloric-hydrofluoric acid mixture (HF
the reaction rates of the HF Acid mixtures will
Acid) with the hydrofluoric acid being obtained
vary considerably with the composition of the
from the reaction of hydrochloric acid on
formation. The physical distribution of the acid
ammonium bifluoride. Hydrochloric acid
increases the solubility of some of the secondary

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 Chemical Stimulation

soluble material throughout the formation also Sandstone-2000 TM

influences reaction rate.
Another factor greatly influencing the rate of Sandstone acidizing technology has improved
reaction is bottom-hole temperature. The higher significantly in recent years as a result of field
the temperature, the more rapid is the reaction. analysis, fundamental research and applied
For example, laboratory data taken from tests research. Traditional sandstone acidizing
reacting 25 ml of acid on 4.0 gm of sand reveal treatments were performed by pumping a
that 33.6 lb of 20-40 mesh Ottawa sand would standard blend of 3% HF and 12% HCL acids.
be dissolved by 1,000 gallons of a 3% HF-12% These treatments often had minimal success and
HCL acid mixture in eight hours at 75°F. sometimes actually damaged the well further.
However, at 200°F, 1,000 gallons of the same Older theories regarding reactions occurring
acid mixture would dissolve 43.1 lb of the same between the acid and the formation proved to be
sand in only one hour. inaccurate in 1984 when samples from a Gulf
Coast well were obtained after sandstone
The surface area of material exposed to the acid
acidization. Based on this research, the
also influences the rate of the reaction. This is
Sandstone 2000TM acidizing processes were
probably the primary reason that hydrofluoric
developed. Like the Carbonate 20/20 initiative,
acid dissolves clay minerals more rapidly than it
Sandstone 2000TM created a set of “best
does quartz. As shown above, 1,000 gallons of
practices” to help improve Halliburton’s
3% HCL will dissolve 33.6 lb of 20-40 mesh
sandstone acidizing success rate.
sand in eight hours at 75°F. However, under the
same test conditions, 1,000 gallons of the same
acid will dissolve 50.7 lb of silica flour in only
30 minutes. Formation Conditioning
Further data show that 72.6 lb of silica flour Treatment of a well before sandstone acidizing
containing 5% bentonite will be dissolved by can greatly increase the success rate of this type
1,000 gallons of 3% HF-12% HCL in 30 of treatment. Formation conditioning design
minutes at 75°F. These examples illustrate the depends on the presence of key minerals. Proper
influence of the exposed surface area on the rate use of a formation conditioner or a combination
of the reaction. Under reservoir conditions the of conditioners before treatment with HF acids is
surface area-to-volume ratio will be much critical to the success of the treatment.
greater than that of any of these examples. As a
result, the reaction in the formation will be more
rapid. Clays
Therefore, the influence of exposed surface area
of rock on the reaction rate cannot be over- Clays were previously thought to be of minor
emphasized. consequence. However, recent work has shown
that the impact of clays can be dramatic for
The importance of the concentration of excess
hydrochloric acid can be illustrated with the brines undergoing deep matrix invasion in
following examples. Using calculations from sandstones. Table 8.3 shows some mineralogies
that could cause problems.
laboratory tests conducted by reacting 25 ml of
acid on 4.0 gm of sand for 30 minutes at 75°F,
1,000 gallons of 3% HF-0% HCL will dissolve
27.1 lb of silica flour containing 5% clay. The
same volume of 3% HF-12% HCL and 3% HF-
20% HCL will dissolve 72.6 lb and 90.8 lb
respectively.

© 2005, Halliburton 8 • 26 Stimulation I

 Chemical Stimulation

Mineral Problem The CLA-STA additives described in Section 6

Contains sodium and can also be used to enhance clay stabilization.
Feldspars
potassium. Fluosilicate
precipitation and K-Spars can
create major problems.
HCL Sensitivity
Carbonate Consumes HCL and can cause
precipitation of fluosilicates and Many formations are “HCL-sensitive;”
aluminum from spent HF. formation minerals decompose when contacted
Illite Can cause fines migration
problems, is ion exchanging,
by HCL. During this process, metal ions such as
and contains potassium which iron, aluminum, calcium, and magnesium are
can cause fluosilicate dissolved from the mineral, leaving an insoluble
precipitation from spent HF. silica gel mass that can be extremely damaging.
Kaolinite Can cause fines migration HCL-sensitive minerals include zeolites and
problems and disperses in fresh
water and causes plugging.
chlorite. However, research has shown than all
Is ion exchanging and swells in clays have a temperature above which they are
Smectite
fresh water. unstable. When conditions make formation
Mixed-Layer Clay Is ion exchanging, swells in minerals highly unstable, only organic acid-
fresh water, and frequently based systems should be used.
contains potassium which can
cause fluosilicate precipitation
from spent HF. CLAY-SAFE
Chlorite Is ion exchanging and is
unstable in HCL.
Is ion exchanging, is unstable in Despite the sensitivity of clays to HCL, they are
Mica
HCL, and contains potassium stable in acetic acid and fairly stable in formic
which can cause fluosilicate acid. Unfortunately, both of these acids are
precipitation from spent HF. similar to fresh water in the presence of water-
Zeolite Is ion exchanging, is unstable in
HCL, and occasionally contains
sensitive clays. Substituting acetic acid (MSA)
sodium which can cause for CLAYFIX is not a good alternative, since
fluosilicate precipitation from MSA does not exchange ions with the clays or
spent HF prevent clay swelling. MSA is not an equivalent
Table 8.3 – Problem Formation Mineralogy substitute for HCL because it does not dissolve
iron scales and is slow to dissolve carbonates.
However, use of CLAY-SAFE conditioners
should provide sufficient ion ex-change to help:
CLAYFIX
• prevent precipitates in the HF/HCL process,
When ion exchange occurs, the cations naturally • control clay swelling, and
present on the surfaces of the clays are replaced
or exchanged with ions from the invading brine. • stabilize the clay to sandstone acidization.
For example, 7% potassium chloride brine Their recommended uses are given in Table 8.4,
(KCl), after exchanging ions with the formation, but the Sandstone Stimulation Process section
becomes approximately 5% sodium chloride on HalWorld should be consulted for proper use
(salt). Because of this exchange it is important of these fluids.
that the transformed brine should also be
compatible with the formation.
The most effective brine for sandstone acidizing
is ammonium chloride (NH4CL), also called
CLAYFIX. CLAYFIX 5 (5% NH4CL) provides
sufficient ion exchange and maintains enough
salt concentration to prevent clay swelling
before and after ion exchange.

© 2005, Halliburton 8 • 27 Stimulation I

 Chemical Stimulation

Fluid System When to Use For example, 50 gal/ft (gallons per foot of
Mud Cleanout formation height) of 15% HCL preflush in a
Whole water-based mud sandstone containing only 5% calcite will
Mud-Flush
losses remove the calcite in a radius of about 2 ft from
N-Ver-Sperse Whole oil-based mud losses the wellbore. If spent HF follows, aluminum
Wellbore Conditioning fluoride precipitation will begin 2 ft from the
Paragon or other organic Asphaltene/paraffin problems, wellbore.
solvents heavy oils, pipe dope
Removing iron scales and
HCL for pickling preventing them from entering Gidley’s CO2 Conditioner
the formation
Oil Well Conditioning Carbon dioxide preflushes have successfully
Emulsion problems, terminal prevented fluid compatibility and emulsion
Gidley's CO2 Conditioner upsets, improves acid problems after sandstone acidizing treatments
penetration into oil zone
Matrix Conditioning
and have improved the HF treatment response.
One operating company’s study revealed that
CLAYFIX 5 High ion-exchanging clays
oil-wet particulates (silica and fines) stabilized
Carbonate removal, ion emulsions. These particles were precipitated
5-15% HCL exchange, removal of polymer
damage from HF acid reacting with the formation in the
presence of hydrocarbons, such as crude oil and
Carbonate removal, ion
CLAY-SAFE 5
exchange for HCL-sensitive xylene. The solution is in Gidley’s CO2
*See note below. Conditioner, a Halliburton-exclusive process
mineralogy
that removes the hydrocarbons from the near-
HCL-sensitive mineralogy, but
it requires removal of polymer wellbore area. The carbon dioxide treatment
CLAY-SAFE H uses 100 to 200 gal/ft of CO2 under miscible
damage (K-Max, HEC, etc.) or
high carbonate levels. (easily mixed) conditions to displace the oil
HCL-sensitive mineralogy, but
away from the matrix in the near-wellbore area.
it requires increased Displacing the hydrocarbons allows better HF
CLAY-SAFE F
*See note below.
carbonate dissolving power invasion of the matrix and prevents emulsions
without increased volume. from forming.
See note below.
*Note: MSA II Inhibitor and 5% NH4Cl are not compatible when The CO2 can also be used throughout the acid
the MSA II Inhibitor concentration is above 1%. Below 1% MSA II stages to provide enhanced energy for cleanup.
Inhibitor, dispersing agents may be required.
Some oils form asphaltene precipitation easily
Table 8.4 – Formation Conditioning System and other oils have minimal miscibility with
CO2 under reservoir conditions. Both of these
conditions can be at least partially eliminated
with a xylene preflush ahead of the Gidley’s
Carbonates CO2 Conditioner.

Sandstone formations containing greater than

5% carbonates are prone to matrix precipitation Secondary Precipitation
of complex aluminum fluorides as spent HF
flows across the carbonates. The solution to this When hydrofluoric acid reacts with either
problem requires silicates (clay minerals) or silica (quartz), one of
the reaction products is fluosilicic acid. This
• deep removal of the carbonate with large
acid will react with sodium or potassium to form
preflushes of HCL or
sodium fluosilicate or potassium fluosilicate.
• the use of an additive that prevents
The sodium and potassium fluosilicates have
precipitation. very low solubility, and precipitation can occur.
This can happen if the hydrofluoric acid contains

© 2005, Halliburton 8 • 28 Stimulation I

 Chemical Stimulation

sodium or potassium, or if the spent or partially • Contains ALCHEK to prevent secondary

spent acid becomes mixed with solutions precipitation of aluminum. This is
containing these chemicals. This means that salt particularly important when the mineralogy
water should not be used as mixing water for the is unknown or the formation contains high
acid or for displacing the acid. The acid should carbonate streaks or more than 5%
not be weighted with sodium chloride or carbonates.
calcium chloride. When calcium chloride is
added to hydrofluoric acid, calcium fluoride will • Aids in iron control, in most cases
precipitate immediately. Diverting aids such as eliminating the need for other iron control
rock salt should not be used because of additives such as Fe-2 (citric acid) and Fe-
secondary precipitates. If additional weight is 1A (acetic acid).
necessary, it is possible to use ammonium • Contains a penetrating agent to help acid
chloride as the weighting agent. contact damage.
The overall advantage of Sandstone Completion
Acid is that it provides the customer with
Acid Systems maximum dissolving power while maintaining
compatibility which is particularly important
when the mineralogy is unknown. The 1.5% HF
Silica Scale Acid is the maximum HF concentration recommended
in most sandstone matrix acidizing treatments.
Silica Scale Acid is the old regular HF or mud
acid (12% HCL-3% HF). It is effective at
removing damage, but its high HF
Fines Control Acid
concentrations almost invariably result in
secondary precipitation very near the wellbore RHF (Retarded HF Acid) is an acid system that
resulting in failures or limited, short-term has proven successful. The patented system has
successes. Therefore, this system is been modified slightly and renamed Fines
recommended for use only when the mineralogy Control Acid.
shows there are essentially no clays and 100% Conventional matrix acidizing with hydrofluoric
quartz, or in geothermal wells. acid is only effective for removing shallow clay
damage 1 or 2 in. from the wellbore. Fines
Sandstone Completion Acid Control Acid is a retarded hydrofluoric acid
system designed for treating sandstone
Sandstone Completion Acid consists of 13.5% formations that have been damaged from the
HCL-1.5% HF, Pen-88 as penetrating agent, and migration and/or swelling of silica, feldspars,
5% ALCHEK to prevent precipitation of and clays up to 2 to 6 in. from the wellbore.
aluminum in the formation and in the wellbore Formations with significant Kaolinite and /or
(alumino-silicate scaling). This fluid is illite are particularly sensitive to this type of
compatible with a majority of formations and damage. The fluoride content of Fines Control
was particularly designed for the cases where the Acid is equivalent to the fluoride content of
formation mineralogy is unknown or uncertain. 1.5% HF, but its effective dissolving power is
The primary advantages of sandstone equivalent to 1.1% HF. However, because of its
completion acid are: retarded nature in its reactions with sand, it is as
effective in removing clay damage as 1.5% HF.
• Contains high HCL-HF ratio to provide
compatibility with most formation Fines Control Acid can also be effective in
mineralogies. Exceptions include formations formations that appear to be HCL-sensitive. In
high in feldspars, particularly at these cases CLAY-SAFE 5 Conditioner can be
temperatures below 200°F and formations used followed by Fines Control Acid. Formation
containing "HCL-sensitive" minerals. minerals do not show acid sensitivity when

© 2005, Halliburton 8 • 29 Stimulation I

 Chemical Stimulation

treated in this manner, as discussed in an earlier overall content is greater then 10%. Since the
section on HCL-sensitivity. fluosilicates are less soluble at lower
temperatures, K-spar Acid should also be used
The primary advantages of fines control acid
in most formations containing any significant
are:
sodium feldspars below 175°F. In formations
• Deeper penetration of live HF into the containing high concentrations of potassium
formation. feldspars below 200°F, lower HF concentrations
are suggested. If fluosilicate precipitation cannot
• Retarded reaction with sand and silica to
be avoided, an HCL overflush should be used to
promote deep damage removal and improve
help re-dissolve the precipitate.
compatibility with feldspar-containing
formations. Cla-Sta FS is included to control fines migration
associated with illite or mixed-layer clays. These
• Minimized damage to formation clays are almost always present when potassium
consolidation - it reacts less with the sand feldspar is a dominant mineral and are very
that holds the formation together. susceptible to fines migration during a
• Fe-1A for iron control and preventing stimulation treatment. K-Spar Acid will prevent
aluminum scaling. this migration. If fines migration is the source of
damage, Fine Control Acid is recommended.
• Penetrating agent to help acid contact The HF fluid treatment design could consist of
damage. 50 gal/ft of K-spar Acid followed by 200 gal/ft
• Clay stabilizer to control fines migration of Fines Control Acid.
during and following the treatment. The primary advantages of K-Spar acid are:
• Temperature limitation only because of • Is compatible with formations containing
corrosion inhibitor and formation mineral significant feldspar and/or illite minerals
stability, as in non-retarded HF systems.
• Contains Fe-1A for iron control and
Higher volumes of Fines Control Acid should be
preventing aluminum scaling.
used where deep, severe damage has occurred. A
lower volume of overflush can be used when the • Contains penetrating agent to help acid
well is predicted to clean up rapidly. When contact damage.
difficulty in cleaning up the well is anticipated,
the large volume of overflush should be used to • Contains clay stabilizer to control fines
push the HF-containing fluids far from the migration during and following the
wellbore. Since Fines Control Acid does not treatment.
require a shut-in time to function, the well
should be returned to production as soon as Volcanic Acid
possible.
Volcanic Acid is a new organic-HF acidizing
K-Spar Acid blend developed to replace acetic-HF and
formic-HF fluids. This system is unique to
K-Spar Acid is a 9% HCL-1% HF blend which Halliburton. Recent research (including
was designed for treating formations containing laboratory reactions, core flow tests, and
significant sodium or potassium feldspar or flowback sample analyses from organic-HF
illite. As the sodium and potassium are treatments) has shown that the acetic-HF and
dissolved from these minerals, the potential for formic-HF systems have severe secondary
fluosilicate precipitation increases. Potassium precipitation of HF reaction products. The
fluosilicate is less soluble and presents a bigger systems are effective in removing skin damage
problem. K-spar Acid should be used in almost and increasing production in wells in which
all cases where the formation contains K-spar HCL-based fluids could not be used. However,
and/or illite as the dominant mineral, or the secondary reactions further from the wellbore

© 2005, Halliburton 8 • 30 Stimulation I

 Chemical Stimulation

precipitate the HF reaction products giving a less and asphaltenes or scale removal treatments
than optimum overall treatment. Volcanic Acid may also be required.
solves these problems while maintaining all the
3. Pump 100 to 200 gal/ft of Gidley's CO2
advantages of organic-HF fluids.
Conditioner (optional). Applicable for oil
The primary advantages of Volcanic Acid are: wells with emulsion problems, terminal
upset problems, or to enhance contact of
• Is compatible with HCL-sensitive minerals
acid into the oil zones.
• Can be used at higher temperatures than 4. Pump 50 to 150 gal/ft of non-acid CLAYFIX
HCL-based fluids, without decomposing 5 Conditioner (optional). CLAYFIX 5
clays or zeolites or having high corrosion Conditioner is recommended in formations
rates. with a high ion-exchange capacity. It also
• Typically will not cause sludging with should be used when completion brines or
formation crude oils, even with those prone kill fluids have not been recovered from the
to acid sludging. well and need to be displaced from the near-
wellbore area to avoid contact with acid
• Avoids secondary precipitation observed fluids. If the crude oil or formation brine
with formic-HF and acetic-HF. shows incompatibility with the acid fluids,
• Contains NH4Cl to prevent swelling of the non-acid preflush may also be necessary.
water-sensitive clays. 5. Pump 50 to 150 gal/ft of appropriate acid
• Contains a penetrating agent to help acid conditioner. Acid fluids are required prior to
contact damage. the HF-containing damage removal fluid
systems in order to ion exchange and
• Can be used anywhere formic-HF or acetic- remove carbonates. HCL, CLAY-SAFE 5,
HF fluids were previously used. or CLAY-SAFE H should be used. The
The name Volcanic Acid came from the fact that choice of these fluids depends upon damage
formations with high zeolite content and high mechanism, mineralogy, and temperature.
clay content are often associated with areas of 6. Pump 75 to 200 gal/ft of appropriate
volcanic activity. The name also has the damage removal fluid system. When using
connotation of high temperature. The Volcanic Fines Control Acid, pumping a small
Acid fluid systems are specifically suited for nonretarded HF stage is often beneficial in
these types of formations. removing very near-wellbore damage.
7. Overflush with 25 to 200 gal/ft of 5-15%
General Treatment Guidelines HCL or CLAYFIX 5. Overflush is required
to push the treatment fluids deeper into the
Designing sandstone acidizing treatment may formation. The larger volumes are required
seem very complicated due to the numerous with brines incompatible with spent acid or
considerations that must be dealt with, but for disposal wells where the fluids are not
following the 8 general steps listed below and recovered.
the decision tree in Figure 8.7, the goal of
improving well performance can keep things in 8. Displace with clean fluid such as nitrogen
perspective. or CLAYFIX 5. Volumes should be
sufficient to fully displace any acid fluid
1. Perform mud cleanout treatment if whole away from the wellbore and the gravel pack.
drilling mud was lost. Additional fluid Never use KCL, or formation brine to
should be circulated until returned fluid is displace since these fluids will be
clean. incompatible with spent acid.
2. Perform wellbore cleanout treatment. This
should include pickling the tubing with HCL
at the least. Solvent treatments for paraffins

© 2005, Halliburton 8 • 31 Stimulation I

 HF Acid Flow Diagram
W ellbore A rea D amaged?
Don’t use HF

Yes No

Is dama ge H F a cid soluble?

Don’t use HF

No Yes

Damag e remov ed, will production be e conomica l?

D on’t use H F

Yes No

Pump at re asonable ma trix inje ction rate?

Don’t use HF

Yes No

Carbo nate Conce ntra tion > 20%?

Don’t use HF

Yes No

C an treatment be control le d to tre at all in terval of Interes t?

U se HF

Yes No

Nec ess ary to tre at t he whole i nt erval t o ma ke well ec onomical?

D on’ t use H F U se HF

Yes No

Figure 8.7 – HF acidizing decision tree

© 2005, Halliburton 8 • 32 Stimulation I

Unit F Quiz

Fill in the blanks or mark the correct answer to check your progress in Unit F.
1. Hydrochloric acid used in sandstone acidizing is basically used to (check all that apply):
_____ a) partially dehydrate water-swollen clay
_____ b) dissolve clays
_____ c) dissolve carbonates that are present
_____d) create a fracture
2. Hydrofluoric acid will dissolve
_____a) silica
_____b) clays
_____c) silt
_____d) shales
_____e) all of the above
3. The speed of hydrofluoric acid’s reaction on sandstone is affected by:
_______________________________________________________
_______________________________________________________
_______________________________________________________
_______________________________________________________
4. Halliburton’s name for ammonium chloride is ____________________.
5. Gidley’s CO2 process displaces ____________________ away from the wellbore to allow better HF
____________________ of the matrix and prevent ____________________ from forming.

6. Which Sandstone acid system would you choose for removal of deep damage (up to 2 to 6 in. from
the wellbore) caused by clay migration or swelling?

_____a) Sandstone Completion Acid

_____b) Fines Removal Acid

_____c) Silica Scale Acid

_____d) Volcanic Acid

Now, look up the suggested answers in the Answer Key at the end of this section.

© 2005, Halliburton 8 • 33 Stimulation I

 Chemical Stimulation

Unit G: Damage Removal – Mud

Since many mud systems are used for well considered before a mud removal operation is
completion, it is almost impossible to describe started.
all of them, their properties, and how they might
affect production. Therefore, this unit is limited
to: Limestone Formations
(1.) water base muds which contain clay If damage from mud or mud filtrates exists in a
minerals limestone formation, the exact nature of the
(2.) oil base muds. Oil muds are either straight damage should be determined. If the producing
oils or oil external emulsions. formation has not experienced excessive lost
circulation problems during the drilling
It is desirable to remove muds from wells for a
operation, then the problem is probably one of
number of reasons.
the following:
• very shallow clay particle invasion
Mud Removal
• possible filtrate invasion resulting in water
blocks
Water base mud, if properly combined, will
build a filtercake on the wall of the wellbore as • possible changes in the formation
the well is drilled. The consistency of this (particularly if naturally occurring water
filtercake will vary from a tight, dense material sensitive clays are present)
to a soft, mushy cake that allows excessive fluid
to penetrate into the formation. The mud’s fluid
loss properties must be constantly monitored to Acid–Surfactant Mud Removal
do its job. Solutions (MCA-III)
As the well is drilled, the wiping action of the
bit, pipe, and tool joints on the on the sides of If the formation is limestone, any acid solution
the wellbore can remove the filtercake. This that penetrates the mud or filtercake should
allows more filtrate and even clay particles to result in increased production. To penetrate a
invade the formation. Also, excessive speed in mud filtercake, a surfactant is often added to
running the pipe can cause fracturing and loss of hydrochloric acid. The surfactant Morflo III
whole mud to the formation. Many factors can also acts to cure other problems associated with
contribute to lost circulation problems, including mud damage. In addition to aiding penetration
natural fractures and the vugular porosity of of the filtercake, Morflo III can
some formations. • aid in thinning whole mud
Damage results when filtrate, clay, and whole
• lower surface and interfacial tension to
mud invade a formation. This damage can
prevent or remove water blocks
seriously restrict the well’s production capacity
or injectivity if it is an injection or disposal well. • aid emulsion breaking or prevention of
The degree of damage can be determined emulsions
through pressure buildup tests. If damage does
exist, steps can be taken to remove the damaged • assists in dispersing the clay minerals and
condition. Potential damage and the other insoluble fines after acid has done the
composition of the formation should be job of shrinking the clay

© 2005, Halliburton 8 • 34 Stimulation I

 Chemical Stimulation

One potential problem with whole mud removal Sandstone Formations

is that even when acid is used to shrink clay
particles in the mud system, it does not
Removal of water base muds from a sandstone
necessarily mean the mud will be thinned. In
reservoir should follow much the same pattern
fact, the opposite can occur because the acid
as that of a limestone formation with some slight
may flocculate or cause the clay particles in the
changes. Where the calcium carbonate content
mud to clump together.
of the formation is low, hydrofluoric acid can be
To minimize this flocculation and mud used.
thickening, Morflo III is added to the acid, and
the acid strength is maintained at the lowest
possible level. Usually 5 to 10% acid is used for Hydrofluoric-Hydrochloric Acid
this work. Less than ½ % of the acid in the Mixtures (HF Acid)
solution is required for dehydrating the clay.
The rest can be used for dissolving lime in the One precaution that should be pointed out is that
mud and limestone from the formation. If the the fluoride ion (F-) will react with calcium ions
acid concentration used is 15% or higher, even (Ca++) to form a damaging precipitate. Serious
the special surfactant may not be capable of damage could result if it forms in excessive
thinning the mud effectively. Therefore, low amounts in the intergranular porosity of a
concentrations of acid solutions are sandstone formation. Limestone content of
recommended. sandstone formation is generally low enough so
that this problem will not occur. If limestone
content is too high where you can’t put enough
Non-Acid Mud Removal HCL ahead to get rid of it, then HF should not
Solutions (Mud-Flush) be used. If the well has had a weighted clear
completion fluid (such as 40% calcium chloride)
Mud-Flush lowers the viscosity of water-based used in it, damage could result. A spearhead of
mud systems and helps keep the solids in a dilute hydrochloric acid is almost always
dispersed state. Mud-Flush has several recommended ahead of HF.
applications comparable to MCA-III, but it
If whole mud or a mud filtercake is present on
cannot remove hard, dehydrated, filtercake from
the formation face or in perforation, it can be
a formation. Although Mud-Flush is not
removed by MCA-III. An appropriate surfactant
considered a replacement for MCA-III, it is a
can also be added to HF-HCL mixtures for the
more economical alternative for use in lost-
mud removal. The comments on concentrated
circulation situations. For example, if 100 bbl of
acid are still true. Even with HF solutions,
water-based mud was lost to a producing
flocculation can result, and whole mud
formation, the volume of MCA-III required to
thickening may be observed. Filtercake and
contact and chemically react with the mud
mud invasion, as well as clay within the
would be expensively large.
formation, may be removed by HF Acid.
Mud-Flush is a mixture of a mud thinner (MF-1)
The Mud-Flush solution previously mentioned
and MORFLO® III. The action of these two
can be used for whole mud removal in sandstone
chemicals dissolved in water is sufficient to
formations in the same manner as discussed for
perform the following functions:
limestone formations.
• Aid removal of water-based drilling muds
from all types of formations
Oil Base Muds
• Help prevent and break emulsions and water
blocks
Two basic oil mud systems require attention: the
Mud-Flush should not be used for removing oil- Oil External Emulsion Muds and the True Oil
based mud. Base Muds.

© 2005, Halliburton 8 • 35 Stimulation I

 Chemical Stimulation

Oil External Emulsions (Invert N-Ver-Sperse O consists of

Emulsions) • hydrocarbon solvents, such as diesel oil,
kerosene, or xylene
Emulsions used for drilling are usually fairly
low solid, oil external, oil wet clay stabilized • 5% MUSOL® or MUSOL A solvent
emulsions. They can be broken, with • and HYFLO® IVM surfactant
undesirable results, if too much of a high surface
area solid such as clay is added to the system. If the muds contain asphaltic materials, use
They can also be broken with appropriate xylene for the hydrocarbon solvent.
emulsion breakers in some instances. Use N-Ver-Sperse A fluid, containing wetting
agents and dispersants, when hydrocarbon-based
fluids must be avoided because of economics,
True Oil Base Muds environmental concerns or lower hydrostatic
pressures. The aqueous system also can be used
True oil base muds are usually prepared by as either a mud cleanout fluid or a formation
gelling a viscous, high asphaltene oil and adding breakdown fluid. When used as a mud cleanout
to it blown asphalt, fine calcium carbonate, and fluid, gelling agents can be added to give the
other materials which can have fluid loss fluid sufficient viscosity to carry the mud solids
properties. One of the most effective thinning from the wellbore. It can also be weighted to 11
and removal solutions consists of glacial acetic lb/gal using zinc chloride. Materials, such as
acid or acetic anhydride mixed with an aromatic calcium chloride and sodium bromide, are not
solvent containing Hyflo IV. These will also satisfactory weighting salts. Sodium bromide
water wet the pipe and formation. can be used for weighting, however, if methanol
Some oil base type muds tend to spontaneously is included in the formulation. Test weighted
form a very viscous emulsion with certain solutions at specific well conditions before use.
cements. This emphasizes the need for a wash N-Ver-Sperse A consists of
ahead of the cement.
• water containing 2% KCl by weight
• 10% MUSOL
N-VER-Sperse
(NOTE: MUSOL A is not recommended
N-Ver-Sperse A and N-Ver-Sperse O have been because of separation problems noted at
developed to help clean up a well where oil higher temperatures)
based muds have been used. • 1% MORFLO III by volume
Use N-Ver-Sperse O fluid when the presence of • 50 lb SPACER SPERSE per 1,000 gal of
a hydrocarbon fluid would be advantageous. Use fluid.
it either as a cleanout fluid to remove mud from
the wellbore and formation or as a formation
breakdown fluid. When used as a mud cleanout Additional References
fluid, circulate N-Ver-Sperse O at a fairly high
rate to prevent the solids in the mud from
Acidizing Methods and Materials (Mud
settling out.
Removal) - HalWorld

© 2005, Halliburton 8 • 36 Stimulation I

 Chemical Stimulation

Unit G Quiz: Damage Removal-Mud

Fill in the blanks or mark the correct answer to check your progress in Unit G.
1. Damage can result when ____________________, ____________________ and
____________________ ____________________ invade a formation.

2. Two solutions that can be used to remove mud damage in a limestone formation are
____________________ and _____________________ ____________________.

3. ______ True ______ False Mud damage in a sandstone formation can be removed with HF Acid
if the limestone content is high.

4. The two types of oil base muds are ________________ ____________________ ________________
and ________________ ________________ ________________ muds.

5. ____________________ and ____________________ are two solutions for removing oil base muds.

Now, look up the suggested answers in the Answer Key.

© 2005, Halliburton 8 • 37 Stimulation I

 Chemical Stimulation

Unit H: Paraffins and Asphaltenes

Other than the physical properties and condition the deposition problem varies between reservoirs
of the producing formations, one of the most in the same area and between wells in the same
aggravating problems for the petroleum reservoir. The severity is difficult to estimate
producer is the build-up of organic deposits in until it cannot be controlled by normal
areas like the well bore and feed lines. These production techniques. Many operators have
deposits act as chokes during build-up in the learned to live with their situation and have
well bore. They gradually decrease production “grown-up” with their removal techniques.
and, in time, could completely stop the flow of Therefore, they tend to treat the problem as an
oil. This may cause rod failure, split tubing, and unavoidable part of life.
worn pump parts unless some remedial action is
taken. Two common actions are
Cloud Point and Pour Point
• an orderly program for the removal of the
deposits Cloud point and pour point tests are used to get
• the use of some type of inhibitor. general measurements of the ability of the crude
oil to hold paraffin in solution. These are
The petroleum industry spends millions of experimental measurements that give us some
dollars annually correcting these deposition idea where or when paraffin might cause
problems. problems.
Organic deposits are formed when the chemical The cloud point is defined as the temperature
equilibrium of the oil is upset. This causes where paraffin begins to come out of solution.
certain chemicals normally in solution to This point is visible in clear crude oils as a slight
precipitate. The physical and chemical cloudiness. Obviously the cloud point of a dark
characteristics of many crude oils are such that crude oil has no meaning since the cloudiness is
the oils can deposit waxy material called not visible. Other instrumental methods are
paraffins or, in some instances, asphaltenes. sometimes used to obtain the cloud point of
crude oils.
Paraffins If the liquid or crude oil is slowly cooled below
the cloud point without agitation, small wax
The family of hydrocarbons classified as crystals gradually form an interlocking network
paraffins is generally inert. They are resistant to that will support the liquid. A temperature is
dissolving in acids, bases, and oxidizing agents. finally reached where the oil will not flow when
This makes it difficult to remove these deposits tilted to a horizontal position in a bottle. This is
chemically. referred to as the pour point. This point has
more meaning when dealing with crude oils.
Depending on the conditions where paraffin Generally, the higher the cloud point or pour
deposits were formed, they have different point of an oil, the less stable the paraffin is in
physical forms. These forms include soft mush the oil.
to hard, brittle deposits. Also, paraffin deposits
will often include other materials such as scale,
sand particles, or asphaltenes.
Paraffin problems are encountered in almost
every oil producing area. Some areas are more
severely affected than others. The severity of

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 Chemical Stimulation

Factors Affecting Paraffin expand and cool. The largest amount of cooling
is usually at the formation face.
Deposition
Paraffin deposition is primarily due to a Loss of Volatile Constituents
reduction in the amount of paraffin that can be from the Crude
dissolved in a crude oil. This loss of solubility
can be caused by many different factors. Some
of the more important factors are discussed Generally, the light parts of a crude oil are the
below. ones that dissolve the most paraffin. Loss of
these lighter constituents reduces the quantity of
paraffin that the oil can hold in solution at a
Temperature specific temperature.

In most solutions, as you lower the temperature Evaporation of the volatile constituents in crude
the material dissolved in the fluid begins to drop oil also tends to reduce the temperature of the
out of solution. This is also true of paraffins. oil. This is due to the heat required to change
As oil is produced, its temperature can drop for a the liquid to a vapor. This effect is not as
variety of reasons. Cooling can be produced: important as the loss in solubility mentioned
above.
• by gas expanding through an orifice or
restriction (choke) As a producing field becomes older, the lighter
constituents are constantly being removed from
• as a result of the gas expanding, forcing the the oil, even within the formation. Therefore,
oil through the formation to the well and the oil becomes more saturated with paraffin
lifting it to the surface before it ever leaves the formation. For this
reason, many paraffin deposition problems
• by loss of heat from the oil and gas to the
become more severe as the well becomes older.
surrounding formations as it flows from the
bottom of the well to the surface
• by dissolved gas being liberated from Suspended Particles in the
solution Crude
• by water production
As was stated previously, paraffin begins to
• by the evaporation or vaporization of the separate from crude oil when the temperature of
lighter constituents the oil cools and the paraffin is no longer stable
• in oil flow lines due to loss of heat to air in solution. There is some evidence that
(especially in winter) formation fines such as sand and silt often speed
this separation process. These small particles
suspended in the crude act as a nucleus for the
Pressure
small wax particles to form into larger particles.
These separate more readily from the oil.
Pressure helps keep gas and lighter constituents Paraffin problems are greatly increased when
dissolved in the crude oil. If the wellhead these fines are present, especially since fines
pressure were the same as formation pressure, tend to increase the bulk of the deposit.
paraffin would probably not cause many
problems.
However, oil will not flow unless there is some Conditions Favoring Paraffin
type of pressure drop. The largest percentage of Deposition
this pressure drop occurs near the bottom of the
well. As the pressure decreases, oil and gas Even though wax may separate from the crude
oil, the paraffin will not necessarily deposit on

© 2005, Halliburton 8 • 39 Stimulation I

 Chemical Stimulation

the tubular goods and other objects. The wax flow channels become partially blocked or
will probably remain suspended in the crude oil plugged, and the flow of oil is restricted. Even
itself. This ideal situation often exists. In some after the original formation temperature is
wells producing very waxy crude, little or no restored, it may be difficult to redissolve the
paraffin problems are experienced. precipitated paraffin in the same fluid. This is
because the melting point of solid paraffins is
On the other hand, some crude oil areas with
much higher than the cloud point. However,
“low” paraffin content have some severe
formations having temperatures higher than the
problems. Listed below are some conditions
melting point of the precipitated paraffin would
that are favorable for paraffin deposition:
not be affected.
• The alternate coating of the pipe and
One obvious method of minimizing this problem
draining of the oil. As the pipe fills, then
would be to heat the stimulation fluids on the
drains, the film left on the pipe surface is too
surface. Another method might be to run a
thin and its movement too slow to carry the
paraffin solvent ahead of the job.
wax particles away.
• The presence of only a film of oil in contact
with the pipe while the well is flowing. Methods Used to Remove
• When the oil contacts with an unusually Deposits
cold surface such as the production of oil
through water zones. This will cause Methods generally used to remove
paraffin crystals to grow directly on the pipe accumulations of paraffin can be classified as
wall. It is estimated that the heat loss from a follows:
pipe in contact with water is approximately • Those that remove the paraffin by use of
eight times greater than when in contact mechanical equipment.
with air or dry earth.
• Those that remove the paraffin by use of
• Rough pipe surfaces. solvents which dissolve the deposits.
• Electrical charges on various materials in the • Those that use heat, which melts the wax and
crude oil. reduces it to a liquid so that it can easily be
These conditions favoring paraffin deposition removed with produced oil.
combined with a sufficient cooling of crude oil Mechanical methods such as scrapers, knives,
can cause serious problems. hooks, and other tools for the removal of
paraffin deposits offer fairly satisfactory results
when the wax accumulation is in the well bore.
Paraffin Precipitation during Tools such as these are common in the oil field
Fracture Stimulation and will not be discussed here.

Studies have been conducted on the effect of Hot Oil

injecting cold fluids into a warm, producing
reservoir. It was found that the crude oil can One of the most common techniques of
deposit paraffin in the formation when the removing paraffin deposits is to dissolve or melt
reservoir is cooled by large volumes of cold waxy accumulation with hot oil. This removal
fluids such as those used in fracturing method is very simple. Lease crude is run
treatments. This is particularly true when the through heat exchangers and pumped into the
surface fluid temperature is cooler than the well at temperatures in excess of 300°F. This
formation temperature. If the fluid in the will usually melt the accumulated paraffin in the
formation is cooled to a temperature below the oil string. The paraffin is then produced back
cloud point, paraffin precipitates may deposit in with the oil. Many small businesses own and
the formation pores. Once this occurs, the fluid

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 Chemical Stimulation

operate specially designed hot-oil trucks. Many Parasperse Additives

wells are hot oiled at regular intervals ranging
from every two to four weeks or more. Parasperse has proven very successful in both
There is some evidence that hot oiling may be laboratory and field tests as a water-dispersible
detrimental to crude oil production. Paraffin paraffin removal agent.
damage is caused when temperatures higher than One of the most successful applications of
the formation temperature is used to melt the Parasperse® cleaner is periodic cleaning of the
paraffin wax. As the hot oil is circulated, some formation face. Other applications include
of the liquid containing a high concentration of wellbore cleanout, flowline cleaning, paraffin
paraffin may leak off into the producing zone inhibitor placement, and as a preflush in
where it cools to the formation temperature. fracturing. This material can be used as an
This allows paraffin to reprecipitate within the alternative to hot-oiling downhole. Parasperse®
formation. When this type of damage is is ordinarily used at a concentration of 2-10% in
suspected, it often requires several soakings with a water carrier. This water may be produced
a good paraffin solvent to clean the wax out of formation brine or clean surface water.
the formation matrix.
Successful treatments have been noted when
Many crude paraffin deposits contain inorganic cold water was used. Preferably, the system
solids such as corrosion products, scale, and should be warmed to about 100-120°F to aid the
formation fines. These solids can comprise as cleaning action of the Parasperse® solution. In
much as 60% of the paraffin deposit. If the laboratory tests, the Parasperse® solution
paraffin is melted by the hot oil, the solids could removed more crude paraffin than is dissolved in
be forced into the formation matrix and create conventional paraffin solvents.
another source of damage.
Parasperse® treatments are also less expensive
than conventional paraffin solvents. Since water
Steam
comprises 90-98% of the removal system, the
chemical expense is very reasonable. In many
Steam has been used successfully in a number of instances, Parasperse® treatments have
fields having severe paraffin problems. The significantly increased the production of a well.
application of steam heat to the formation is a
practical method of heating the sand and Paraspserse T was designed for the removal of
removing paraffin from the formation face. One both paraffins and asphaltenes. It has the same
disadvantage of this method could be the applications as Parasperse.
possibility of plugging the producing zone with Parasperse LR was primarily designed for use in
paraffin in much the same manner as with hot oil hydrocarbon-based fluids. However, it can also
jobs. be added to aqueous fluids and has the same
general applications as the other Parasperse
Aqueous Paraffin Removal Systems additives.

Certain water-based chemicals have been Solvents

successfully used to remove downhole paraffin
deposits. These chemicals, when added to The use of solvents to remove paraffin deposits
water, have the ability to remove accumulated is becoming more common in the oil field.
organic deposits and disperse them for easy Many laboratory studies have been conducted on
removal. a variety of solvents in an attempt to determine
the best solvents for paraffin and how the
solubility varies with different waxes.
In general, the solubility of different waxes in a
given solvent at a definite temperature decreases

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 Chemical Stimulation

as the molecular weight and melting point loss, produce the oil out of the well bore rapidly,
increase. and minimize agitation of oil in the wellbore.
The usual practice has been to dissolve paraffin
accumulations using light, hydrocarbon solvents Electrical Heaters
such as kerosene, naphtha, gasoline, diesel fuel,
etc. These solvents are very effective for The use of bottom hole heaters is a less
dissolving purified paraffins such as canning satisfactory means of controlling paraffin
waxes. However, crude waxes are usually deposition. Heaters are designed to heat the oil
deposited with a considerable quantity of as it comes out of the formation in order to keep
asphaltenes present. Because asphaltenes are the paraffin “in solution.” The use of this
insoluble in most solvents, they tend to hinder technique is severely limited by economics, high
the dissolving of the waxes present in the maintenance costs, and the absence of electricity
deposit. This makes the solvent less effective in in isolated fields.
dissolving the total deposit.
Plastic Coatings
PARAGON Solvents
Plastic pipe used as feedlines and plastic coated
Tests show that aromatic solvents such as xylene pipe used in the well has received much
and toluene dissolve both the wax and the attention in the last few years as a means of
asphaltenes. These two solvents are excellent combating paraffin deposition. Extruded plastic
for treating crude paraffin deposits. pipes and plastic coatings have proven effective
Halliburton’s Paragon is an effective blend of in some areas.
aromatic solvents.
The idea behind the use of plastic coatings on
Paragon 1 and Paragon 100E+ effectively downhole equipment is that paraffin will not
dissolve paraffin without using benzene, ethyl adhere to the smooth surface provided by the
benzene, toluene, or xylene (BETX). The use of plastic. In some cases this is true; however,
one or more of these four materials may be most plastic coatings will not withstand the
restricted in certain areas due to government rough treatment given to downhole equipment.
regulation. Therefore, the coating becomes scratched and
worn and provides an excellent base for paraffin
Paragon EA™ is a cost-effective solvent for the
deposition. In some instances, certain types of
removal of excess pipe dope, paraffin deposits,
plastic coatings actually promote the deposition
and crude oil residues. In most cases, Paragon
of paraffin. This method of combating paraffin
EA will be applied as a neat solvent. Unlike
deposition is also very expensive, especially if
Xylene and Paragon 100E+, Paragon EA does
the existing iron has to be junked and new
not contain any aromatic components and is
plastic coated equipment placed in the well.
environmentally acceptable.

Surfactants
Methods for Decreasing the
Severity of Deposition Many of the chemicals used to combat paraffin
problems are just ordinary surfactants or
dispersants. The surfactants work by water-
Altering Production Techniques wetting the tubular goods. This water film helps
keep paraffin from sticking to the pipe wall.
Altering production techniques is one way to Dispersants work by reacting with paraffin and
avoid paraffin problems. There are many causing the particles to repel each other.
methods that can be used to cut down on heat

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 Chemical Stimulation

These approaches have been partially successful. In all applications a concentration of 0.5 to 0.75
However, there is no information on when they gallons of inhibitor per 100 bbl. of produced
will work. It is mostly a trial-and-error method. crude oil should be maintained.
The squeeze treatment is done by diluting 1
Crystal Modifiers drum of paraffin inhibitor per each 50 bbl. of
produced crude per day in 500 gallons of
Generally, crystal modifiers have many of the diesel, kerosene, xylene, Paragon, or lease
same drawbacks of surfactants. They appear to crude. Thus, for a 50 BOPD (barrels of oil per
be somewhat unpredictable in their day) well 1 drum of inhibitor diluted to 500
effectiveness. However, with the proper gallons would be required; for a 100 BOPD
placement technique, they seem to work fairly well 2 drums of inhibitor diluted to 1000
well and offer the most hope for the chemical gallons would be required, etc. Once the
inhibition of paraffin deposition. When viewed inhibitor is spotted downhole, it is then over-
under a microscope, they appear to modify the displaced with 5-10 bbl. of lease crude per foot
wax crystals precipitating from a solution. The of formation. Inhibitor treatments as outlined
normal crystal growth of paraffin is deformed above should theoretically give about 200 days
sufficiently to inhibit further growth. The crude protection against paraffin deposition.
oil becomes filled with paraffin crystals that are
Parachek® 160 paraffin inhibitor continuous
much smaller than normal and have fewer
injection into the crude stream may be
tendencies to adhere to pipe surfaces. While not
accomplished by metering the inhibitor
completely curing the paraffin problem, crystal
downhole with a small surface chemical pump,
modifiers help reduce the severity of the
by injection into the power oil on wells
problem.
equipped with a subsurface hydraulic system,
or by using a bypass feeder arrangement. One
Parachek® 160 Inhibitor advantage to the continuous injection of the
paraffin inhibitor is that conscientious
Parachek® 160 inhibitor is an effective blend of operating personnel can carefully control the
chemicals that may be classed as crystal concentration of the chemical. In all continuous
modifiers. Parachek® 160 has been found to be injection applications, the inhibitor must enter
effective in relieving paraffin problems the crude stream well ahead of the point of
encountered in most crude oil producing areas. paraffin deposition. This is imperative for a
However, it should be noted that Parachek® 160 successful treatment.
does not prevent the paraffin crystals from
It is possible that Parachek® 160 could be
coming out of solution in the crude oil. Once the
placed during other remedial treatments on a
crude oil becomes saturated with dissolved
well, such as a propped fracturing treatment.
paraffin, paraffin crystals begin to form in
Paracheck® 160 is not ordinarily dispersible in
solution. Parachek® 160 is not a paraffin solvent
aqueous solutions; however, it could be
and should not be used in place of Paragon or
injected into an aqueous fracturing fluid
Parasperse. That is, it is not to be used as a
providing the pump rate is sufficient to keep it
paraffin removal solution, but rather as
dispersed. Parachek® 160 can also be added by
prevention against paraffin deposition.
mixing with Parasperse. Parachek 160 has not
There are three different applications that may been tested to determine if it has a detrimental
be used to introduce Parachek® 160 into the effect on the gel properties of My-T-Oil IV and
crude oil stream. These are: My-T-Oil V, so compatibility testing would
need to be conducted before attempting to use it
• squeezing into the formation with these fracturing fluids.
• continuous application
• introduction into other stimulation
fluids.

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 Chemical Stimulation

Asphaltenes tends to aggregate (form) the asphaltene

particles. The breaking of this bonding allows
better solvent penetration and increases the
Asphaltenes are generally considered to be
dissolution rate of the asphaltenes.
suspended particles in the oil. Unlike paraffins,
they are not soluble in the light constituents of Targon® II is used from 1 - 10% by volume of
oil. Asphaltene deposition can be caused by the carrier. It will not work in solvents such as
some of the same conditions as paraffin. kerosene, diesel, gasoline, condensate, etc.
However, it is believed that asphaltene deposits
are caused by the inability of a crude oil to keep Tarchek
the particles dispersed.
Asphaltene precipitation is less widespread in Tarchek is an asphaltene inhibitor for use in
the United States than is paraffin precipitation. wells with asphaltene precipitation problems. It
It appears that certain fields in Mississippi and can be run in combination with such paraffin
California are the most susceptible to this type inhibitors as Parachek®160 to treat crude oils
of deposition. However, any well producing that have both paraffin and asphaltene problems.
asphaltic base crude may experience this Laboratory testing has shown that Tarchek does
problem. Asphaltene deposition is also a not affect paraffin inhibition. Remember that,
problem in many areas outside the United States. like Parachek®160, Tarchek inhibitor is not a
Where asphaltene precipitation is a problem, the solvent and should not be used in place of
deposition usually occurs at the bottom of the Paragon solvent. The primary function of
well bore and adjacent to the producing Tarchek inhibitor is not to remove asphaltene
formation. In some instances the asphaltenes deposits, but to prevent asphaltene from
may precipitate within the formation itself and depositing. Before applying Tarchek, clean out
cause damage. any existing asphaltene deposit either
mechanically or by using a solvent soak
consisting of Paragon and the appropriate
Targon® II Solvent amounts of Hyflo®IV M surfactant and
Targon®II solvent.
Targon® II is an organic solvent used to remove Tarchek asphaltene inhibitor stabilizes the
asphaltene deposits. This solvent was designed asphaltenes by preventing their flocculation
for use with an aromatic solvent carrier (clumping) and/or deposition; thereby,
(Paragon). Targon® II was designed to use as an protecting the entire production system from
additive in aromatic solvents to enhance their asphaltene plugging.
asphaltene dissolution properties by breaking
down the strong intermolecular bonding that

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 Chemical Stimulation

Unit H Quiz

Fill in the blanks with one or more words or circle the correct answer to check your progress in
Unit H.
1. ______ True ______ False Most organic deposits in a well contain both paraffin and asphaltene.

2. ______ True ______ False Paraffin problems are rare in the oilfield.

3. The cloud point is the ____________________ when paraffins begin to come out of
____________________.

4. The pour point is the ____________________ when oil can no longer ____________________.

5. Factors affecting paraffin deposition are:

__________________________________________________________________

__________________________________________________________________

__________________________________________________________________

__________________________________________________________________

__________________________________________________________________

6. ______ True ______ False It is impossible to cause paraffin deposition during a stimulation job.

7. Paraffin removal is accomplished by:

__________________________________________________________________

__________________________________________________________________

__________________________________________________________________

8. Parachek® 160 inhibitor is an effective blend of chemicals that may be classed as

____________________ ____________________.

9. ____________________ can be used to help dissolve asphaltenes when added to Paragon and
____________________ can be used to prevent asphaltene precipitation.

Now, look up the suggested answers in the Answer Key at the end of this section.

© 2005, Halliburton 8 • 45 Stimulation I

 Chemical Stimulation

Unit I: Scale Removal and Prevention

The deposition of scaling material from brines
produced with oil has been a serious problem for Scale Type
Chemical
Mineral Name
many years. Compounds such as calcium Formula
sulfate, calcium carbonate and barium sulfate Water Soluble Deposits
have been found in many wells. These deposits Sodium
may exist in injection wells, producing wells and NaCl Halite (salt)
Chloride
waste disposal wells. Acid Soluble Deposits

Calcium
CaCO3 Calcite
Scale Effects Carbonate
Iron Carbonate FeCO3 Soderite
The effects that scales caused by brine Iron Sulfide FeS Trolite
production have on a well depend largely on the Iron Oxide Fe3O4 Magnetite
type of scale in the system. Scales may restrict
and completely choke off production in the Fe2O3 Hematite
tubing, flow lines, or tubing perforations either Magnesium
Mg(OH)2 Brucite
at the formation face or in the perforations. Hydroxide
Scales have been suspected of depositing in Acid Insoluble Deposits
fractures or in the formation some distance from Calcium Sulfate CaSO4 2H2O Gypsum
the well bore.
Calcium Sulfate CaSO4 Anhydrite
Scale not only restricts production, but also
Barium Sulfate BaSO4 Barite
causes inefficiency and production equipment
failure. Since many older fields have entered Strontium
SrSO4 Celestite
into enhanced recovery stages, scaling problems Sulfate
can have an even greater impact on waterflood Barium
operations. Strontium BaSr(SO4)2
Sulfate
One of the most important factors in dealing
Table 8.5 - Oilwell Scale Deposits
with scaling problems is to have an accurate
identification of the material being deposited.
There are essentially two methods used in the
laboratory for the identification of scales. One
involves the use of an instrumental method (x- Types of Scale
ray diffraction). The other uses chemical
methods. Scales can roughly be divided into three classes:
• water soluble
• acid soluble
• acid insoluble
These are based on the ability of water or
hydrochloric acid to dissolve the scale. This is a
simplified division (see Table 8.5) because many
times pure calcium sulfate or pure calcium
carbonate is not deposited. The scale deposit is

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 Chemical Stimulation

usually a mixture of one or more of the major

scales plus corrosion products, solidified oil,
silicates, paraffin, etc. However, separation into
water soluble, acid soluble or acid insoluble is
adequate for field analysis.

Scale Formation
Prior to production, well fluids remain in a
static, undisturbed state. Scale deposits occur as
a result of disturbing this equilibrium. When
production is started, a pressure drop occurs near
the well bore. This pressure change allows
dissolved gases to come out of solution. Since
changes destroy the state of equilibrium, Figure 8.8 - Heavy Scale Deposits
deposits can form. For example, calcium
carbonate scale can occur as a result of a
pressure drop at the well bore. Calcium
carbonate does not exist in the formation brine
as calcium and carbonate ions, but as calcium
Scale Form
and bicarbonate ions. A change in pressure
allows carbon dioxide (CO2) to escape from The Physical form of a scale deposit is
solution. Calcium carbonate scale can then be dependent upon the manner in which it was
formed. deposited. Scale does not form spontaneously.
Instead, it occurs in stages. Scale molecules
Scale deposits may also occur as the result of form clusters over a period of time. As these
mixing incompatible waters. Waters from clusters grow, they become too heavy to remain
different zones may become mixed in the well suspended in solution. They precipitate or
bore, or injection water may mix with formation become deposits. The final crystal form of the
water. In water injection wells, brines from scale may resemble popcorn and be either soft
several sources may be combined and cause and fluffy or very hard and dense. The hard,
compatibility problems which could form scale. dense scales occur as the result of slow growth.
The incompatibility of mixed brines results The soft, fluffy scales are often deposited
when one water contains a high concentration of rapidly. Most inorganic scales appear in one of
calcium or barium and the other water contains a three forms:
high concentration of sulfate or bicarbonate ions
in solution. As these waters mix, deposition can • thin scales or popcorn like
occur because the final solution becomes • laminated deposits
saturated with calcium sulfate, barium sulfate, or
calcium carbonate. These deposits may be • crystalline deposits
found on the rods, tubing or flow lines. The thin type scales are normally the most
Corrosion and microbial reaction products can permeable and easily removed. The laminated
result in deposition of various iron scales such as or crystalline scale forms are less permeable and
iron oxides and iron sulfide. Sulfate reducing harder to remove.
bacteria are a source of hydrogen sulfide which Factors such as pressure drops, temperature, and
can precipitate iron that is in solution, or the the mixing of water can result in severe scale
hydrogen sulfide can react with steel. Iron in problems. However, the formation of scale is
solution can also be precipitated if oxygen is usually a situation with several possible causes.
introduced into a system. Iron oxide (rust) can As changes in the equilibrium occur, interaction
form on metal surfaces when oxygen is present.

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 Chemical Stimulation

of these changes with other conditions downhole particular scale deposit takes can significantly
can result in deposits. The final form that a affect efforts to remove the scale.

Figure 8.9 - Flowchart for field identification of scale

Acid Soluble Scale Removal Regular Inhibited Acid

Acid soluble scales are: Regular inhibited acid solution is normally 15 %

hydrochloric acid that contains corrosion
• Calcium Carbonate
inhibitor. It is the basic acid for preparing
• Iron Carbonate penetrating and non-emulsifying acid. It is not
normally used for scale removal.
• Iron Sulfide
• Iron Oxides
Penetrating Acid
• Iron Hydroxide.
One or more of the following solutions can Penetrating acid solution is regular inhibited
remove these acid soluble scales. acid that has 1 ½ gallons of Pen-5 or Pen-88 per
1000 gallons. Pen-5 and Pen-88 are surfactants

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 Chemical Stimulation

that lower the surface tension of the acid during the course of the acidizing treatment, iron
solution to approximately 25 dynes/cm. salts and oxides that were put into solution as
Lowering the surface tension increases the iron chlorides may form insoluble iron
acid’s ability to contact the scale. hydroxides. These iron compounds can deposit
near the well bore and cause even lower
A penetrating acid solution can be successfully
injectivity than before the treatment.
used on scales containing only a small amount
of iron if it does not form an emulsion with the The pH control is based on the action of a weak
formation fluids. When treating surface acid that reacts much more slowly on the
pipelines, gathering lines, or other systems limestone scale and other acid soluble materials
where the solution will not enter the formation, than the hydrochloric acid reacts. While the pH
penetrating acid can be used for all acid soluble remains low (less than 3), the iron will not
scale. Under cold conditions, increasing the precipitate.
concentration of the hydrochloric acid will
increase the reaction rate. With most iron
scales, it is usually best to use at least 20 percent Multiple Service Acid (MSA)
hydrochloric acid.
MSA contains a 10 percent concentration of
acetic acid. MSA’s greatest attribute in scale
Non-Emulsifying Acid (NE) removal treatment is that it will not damage
chrome-plated parts or alloy steels found in
Non-emulsifying acid solution is regular downhole pumping. Calcium carbonate scales
inhibited acid that has one or more of the non- are readily dissolved by MSA.
emulsifying chemicals added. Non-emulsifying
acid can also have Pen-5 or Pen-88 added to the
solution to help obtain the desired wetting Paragon Acid Dispersion (PAD)
properties.
The non-emulsifying chemicals are added to Paragon Acid Dispersion (PAD) is a mixture
help prevent the formation of emulsions between that contains Paragon (an aromatic solvent),
the treating solution and the formation fluids. acid, and a surfactant. The acid phase may be
Non-emulsifying acid, like penetrating acid, is prepared from a number of acid solutions and
used when the scale is primarily calcium selection of the acid phase depends on the
carbonate and the iron concentration is low. conditions involved. In scale removal
applications, the aromatic Paragon portion of the
dispersion is effective in removing paraffin,
Fe Acid congealed oil and other organic deposits. This
allows the acid to contact the scale and react
more completely. PAD has been injected as the
Fe acid contains hydrochloric acid along with a
first stage for degreasing and removing acid
blend of sequestering agents and a pH control
soluble material prior to a Gypsol or Liquid
agent. During scale removal, the sequestering
Scale Disintegrator job for the removal of acid
agent contained in Fe Acid prevents the
insoluble gypsum.
precipitation of the iron by forming a complex
with the iron and keeping it in solution. Fe Acid
is most suited for the removal of iron
compounds from disposal and injection wells.
These deposits normally occur near the well
bore and gradually block the permeability.
Hydrochloric acid will dissolve iron scales and
cause a temporary increase in injectivity.
However, as the acid spends on the formation

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 Chemical Stimulation

Type of Scale
Gal 15% HCL/ lb Scale/ gal Before placing the Gypsol, the wellbore should
cu ft of Scale of 15% HCL be degreased with kerosene containing Hyflo IV
CaCO3 (Calcium 95 1.84 or with DopeBuster M. After pumping off the
Carbonate) kerosene, the acid reactive scales and corrosion
Fe2O3 (Iron Oxide) 318 0.98 products should be removed with Fe Acid or
MSA. PAD made with Fe Acid or MSA can
FeS (Iron Sulfide) 180 1.62
also be used to degrease the well bore to remove
FeCO3 (Siderite) 111 2.13 the acid reactive materials present. The acid-
Fe3O4 423 0.74 containing solution should be completely
pumped off before placing the Gypsol. The
Table 8.6- Volume of scale dissolved in 15% converted gypsum can then be removed by
HCL dumping or pumping inhibited hydrochloric acid
or MSA. If the scale is extremely thick,
successive treatments may be necessary with
Acid Insoluble Scale Removal Gypsol followed by acid.

Acid insoluble scales are:

• Calcium Sulfate
Liquid Scale Disintegrator
• Barium Sulfate Liquid Scale Disintegrator or LSD, is an organic
• Strontium Sulfate solution that is designed specifically for the
removal of calcium sulfate scales, gypsum and
• Barium-Strontium Sulfate. anhydrite. LSD reacts with gypsum to form a
Two general types of conversion agents have precipitate that won’t adhere to gypsum but
historically been used for scale removal; Gypsol forms a water dispersible sludge. The
and hydroxide solutions. Since then, research precipitate has a tendency to slough away from
has developed a number of additional scale the surface of the gypsum and increases the
removal chemicals that can be used. penetration of the solvent. Also, since the
precipitate does not adhere tightly and is readily
dispersible in water, an acid stage may not be
GYPSOL needed to remove the sludge. If it becomes
necessary to remove the LSD precipitate with
acid, it is soluble at 1.2 pounds per gallon of
Gypsol gypsum converter is a water solution
15% hydrochloric acid.
containing one-half pound of OG-1 and one-half
pound of OG-2 per gallon of solution. A Laboratory and field tests have shown that most
surfactant, Pen-5, is also added at one gallon per gypsum deposits can be removed with LSD in
1000 gallons of the solution. 24 to 48 hours. Also, LSD is more effective
than Gypsol for removing gypsum scale. A
With Gypsol, gypsum (CaSO4∗2H20) is
degreasing step with Paragon or a PAD solution
converted to acid soluble calcium carbonate.
with Fe Acid as the acid phase is preferable prior
Gypsol is inexpensive and has been successfully
to the scale removal treatment. The degreasing
used in many wells. However, the converting
step should be circulated for 12 to 24 hours
properties of Gypsol are severely retarded when
before being pumped off. The LSD solution is
encountering dense, laminated gypsum scale.
then dumped in the annulus. If the scale deposit
Because of this lack of penetration, repeated
is present in fractures some distance from the
application may be necessary.
well bore, a soaking period prior to circulating is
Gypsol works only with gypsum deposits. recommended. If the scale deposit is considered
Gypsol is normally placed in contact with the restricted to the well bore, circulation can be
scale for 24 to 48 hours and allowed to convert started immediately after dumping. Since the
gypsum to an acid soluble calcium carbonate. scale deposit may be oil wet, the addition of a

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suitable surfactant would allow better wetting 7.0

and contact.
6.0
NOTE: Emulsion tests should be conducted
5.0
with the LSD and non-emulsifiers added just as
they would be with an acid treatment. Wells on 4.0
gas lift or flowing wells must have the “spot and
3.0
soak” technique applied.
2.0
LSD can be used at concentrations ranging from
10-50%. Concentrations and volumes used are 1.0
determined by the amount of scale present
downhole. Figure 8.10 gives the theoretical 0 10 20 30 40 50
amount of gypsum removed by various CONCENTRATION OF LSD (WT%)

concentrations of LSD in pounds per gallon. Figure 8.10 - Theoretical Amount of

Note that these are theoretical values and Gypsum Removed by Various
represent the maximum amount of gypsum that Concentrations of LSD (per gallon)
can be removed. For instance, LSD-300 and
LSD-500 solutions will theoretically remove
4.35 and 7.0 pounds of gypsum per gallon, In cases as serious as the one mentioned,
respectively. However, laboratory tests circulating the LSD solution through the interval
conducted with field scale samples have shown would be more practical. The volume and
that LSD-300 and LSD-500 solutions will concentration of LSD treating solution necessary
remove only 2-3 and 3-5 pounds of gypsum per to circulate would depend upon the length of the
gallon in 24 to 48 hours under static test interval, tubing volume, and fluid level in the
conditions. annulus. The treatment time would depend on
The best method in determining the most the particular scale deposit, but 24-48 hours of
effective and economical concentration of LSD circulation should be enough. Longer
for a gypsum removal treatment is to conduct circulating times may be necessary in extremely
disintegration rate tests with scale from the well. difficult cases. Dilution with well fluids may
However, this is not always possible under field slow the disintegration rate.
conditions. Equations are in this unit for determining the
Success or failure of a scale removal treatment cubic feet of scale present on the inside and
often depends upon having sufficient volumes outside of various pipe sizes. The number of
and concentrations of chemicals. For example, pounds of gypsum present per linear foot may be
if a 2 in. I.D. pipe has scale 0.5 in. thick, it calculated by multiplying 144 x cubic foot of
would contain 0.016 cubic feet of gypsum per gypsum present per linear foot. A cubic foot of
linear foot of pipe. Gypsum weighs 144 pounds gypsum weighs approximately 144 pounds.
per cubic foot so each linear foot of pipe would
contain 2.3 pounds of gypsum. A pipe with a 2 BaSO4lvent
in. I.D. containing 0.5 in. thick scale has a
capacity of 0.0449 gallon per linear foot. BaSO4lvent, pronounced (bay-solvent), is a
Calculations show 0.0449 gallon of LSD will solution specifically designed to remove barium
theoretically remove 0.314 pounds of gypsum. sulfate and strontium sulfate scales from
So, as many as 5-10 treatments may be required injection wells, disposal wells, gas wells, or
to remove the scale if a spot and soak technique producing wells. BaSO4lvent solution is a one
is used. stage solvent; it does not require an additional
acid stage for the removal of the scale. The use
of BaSO4lvent solution can minimize or
eliminate costly and time-consuming pulling

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operations and physical descaling of pumps and Equations for Determining

tubing. Deposits in perforations, SSSV, and gas-
lift valves can be removed with BaSO4lvent
Volume of Scale Present
solution. By using BaSO4lvent, operators can
more effectively remove NORM (naturally Often, if a simple calcium carbonate scale is to
occurring radioactive material) scale without be removed, the problem is finding how much
exposure to its hazards and eliminate the costly 15% hydrocholoric acid is needed. It is possible
disposal of these materials. to use too little acid and fail to effectively
stimulate the well. For example, more than 90
BaSO4lvent solution can be applied neat or cubic feet of calcium carbonate scale have been
diluted to a 50% concentration consisting of found in some injection wells. For this quantity
freshwater, seawater, or low-hardness brines. of scale, a treatment of at least 8,550 gallons of
Higher temperatures increase the performance 15% hydrochloric acid should be used. A
and reaction rate of BaSO4lvent solution. Any smaller amount of acid may not improve
means of agitation, such as circulation or injectivity and may even decrease it because of
periodical pumping of the material back and sloughing of the deposit.
forth through scaled perforations, will reduce the
time required for scale removal. Formation The following equations give the scale quantities
squeezes are effective for removing scale from in cubic feet for deposits of various thicknesses
the near-wellbore area. Soak and shut-in times on the inside and outside of different pipe sizes.
of 8 to 48 hours are recommended. The actual By measuring the thickness of scale, finding the
time required can vary depending on the severity length of the scaled interval over which scale is
of the deposit. Before the solvent is used in deposited, and knowing the pipe size, the
downhole well applications, well fluids should amount of scale present can be determined. The
be pumped off or displaced to minimize necessary volume of acid or scale removal
interference with the dissolving process at the solution such as LSD can then be calculated.
problem contact point. Equation 1 is for the calculation of scale volume
When the deposition of barium sulfate or on the outside of tubular goods.
strontium sulfate has been diagnosed, the most (1) V = 0.0218 t (D1 + t)
practical solution to the problem is to eliminate
the causes. For instance, barium sulfate is most Equation 2 is for the calculation of scale volume
often formed as a result of high-barium content on the inside of tubular goods.
injection water being mixed with water that (2) V = 0.0218 t (D2 – t)
contains an excess of sulfates. By isolating
these waters, the problem could be eliminated. Where
If the cause cannot be eliminated, the next most V = volume of scale in cubic
practical approach is to treat the injection water feet/linear feet.
or produced water with a scale inhibitor such as
LP-55 to help prevent the deposition of the D1 = pipe O.D. in inches
scale. D2 = pipe I.D. in inches
t = scale thickness in inches
Hydra Jet
Table 8.6 gives the theoretical quantity of 15%
HCL necessary to remove one cubic foot of
A sand laden acid or water wash pumped
various types of scale and the pounds of scale
through a properly designed jetting device will
removed by one gallon of 15% HCL.
remove all types of scale that are not subject to
chemical means of removal. Hydra Jet is Example
especially valuable in open hole injection wells.
Determine the quantity of 15% HCL necessary
Special tools are available for use in removing
to remove an iron sulfide scale having an
scale from tubing or casing.

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average thickness of 3/8 inch from the outside of producing wells. The chemicals used in the
1000 feet of pipe having 3-inch O.D. Scalechek® service are three types: solid
Scalechek SCP-2 and HT and liquid Scalechek®
Solution
LP-55.
First, use equation 1 to calculate the quantity of
SCP-2 is designed to minimize the formation of
scale per linear foot.
scale in producing wells. The chemical nature
V = 0.0218 t (D1 + t) of the material allows formation water to pass
V = 0.0218 × 3/8 in. (3in. + 3/8 in.) over the polyphosphate with only a small
quantity being dissolved. This low
Change 3/8 in. to a decimal and solve for V: concentration stabilizes the scale-forming
V = 0.0218 × 0.375 × (3 + 0.375) tendency and minimizes scale deposits. SCP-2
is suitable for use in wells having bottom hole
V = 0.0275906 cubic foot per temperatures up to 200°F.
linear foot
Scalechek® treatments with SCP-2 can be
Now multiply this volume of scale times the performed with fracturing treatments by mixing
length of pipe to be cleaned to determine the the material with the first 75 % of the propping
total volume of scale to be removed. This would agent. Scale forming water flows over or filters
be: through the granular bed at formation
temperature and pressure and releases a low
ft 3
Scale Volume = 1000 ft × 0.0275906 concentration of polyphosphates. Most scales
ft such as calcium carbonate, calcium sulfate, and
= 27.5906 ft of iron sulfide scale
3
barium sulfate can successfully be controlled.
The quantity of 15% HCL necessary to remove Oil or water base solutions should be used to
iron sulfide is given in Table 8.3. Multiply the carry the SCP-2. Acids tend to cause the rapid
total volume of scale times the quantity of acid decomposition of all polyphosphates and should
necessary to remove one cubic foot of scale and not be used as a placement medium. This does
the total acid requirement is determined not mean that acid cannot be used as a
breakdown fluid, providing that an oil or water
spacer is used prior to placing the SCP-2. Wells
gallons 15% HCL which have had polyphosphates placed in them
Acid Volume = 180 3
× 27.5906 ft 3 should not be treated with acid.
ft
= 4966.308 gallons
Scalecheck® HT
Scale Inhibition
Scalechek® HT is a solid scale inhibitor
Scale removal treatments may be expensive, and designed to be placed in a fracturing treatment.
the deposition of scale might result in decreased It is placed along with the proppant as a method
production. Therefore, it is often more of inhibiting the formation of scale.
economical to prevent scale deposition before it Incompatibility between scale inhibitors and
occurs. A number of materials and techniques fracturing fluids has long been an inherent
are available to help prevent scale deposition. problem in stimulation treatments. This
incompatibility results in long or no crosslink
times due to the binding of the phosphate,
Scalechek® Scale Prevention phosphonate, or acrylic acid molecule with
Service crosslinkers such as CL-11, 18, 23, 24, and 29.
Scalechek® HT has been coated to prevent
interference with crosslinked fracturing fluids.
Scalechek® service is a process for preventing This encapsulation controls the flash release of
the deposition of scale in injection, disposal and inhibitor which affects crosslink time. The high

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concentrations (flash release) of inhibitor these kinds of uses, the final concentration of
observed in produced water following squeeze LP-55 in the treated water should be 5-20 ppm
treatments are not likely to occur with (parts per million).
Scalechek® HT. This leaves a higher percentage
of Scalechek® HT in the formation to control
scale compared to squeezed inhibitors. Calchek Service
Scalechek® HT is effective in controlling calcite
(calcium carbonate (CaCO3)), gypsum (calcium Carbonate or sulfate scaling, after acidizing
sulfate (CaSO4 · 2H2O)), and barite (barium limestone formations, has been observed in areas
sulfate (BaSO4)) scales. Scalechek® HT is where the formation water contains large
effective in preventing Naturally Occurring amounts of bicarbonates or sulfates. It has been
Radioactive Material (NORM) scale that is often found that 0.1% LP-55 in the acid will help
associated with barium sulfate scale formation. prevent this secondary scaling.
Scalechek® HT is effective for temperatures of Many oil operators routinely run remedial acid
100°F and above; it has been evaluated up to treatments on their wells and follow with
275°F. inhibitor squeezes after cleaning up the treating
LP-55 is a liquid scale inhibitor containing no fluids. With the Calchek service, the producers
polyphosphates. It is used to help prevent the are able to stimulate their wells with the same
deposition of calcium carbonate, calcium sulfate, treatment at reduced cost.
and barium sulfate scales in producing and Adding LP-55 at a concentration of 0.1% will:
injection wells. It is a water soluble organic
compound that acts as a crystal poison by • aid in preventing secondary scaling
altering the structure of the particles and • aid in well cleanup
preventing growth after a crystal nucleus has
formed. • provide scale protection for short periods of
time
LP-55 is recommended only as a scale
preventer, not a scale removal compound. If long-term scale protection is desired, the LP-
Consequently, it should be used after some 55 concentration should be increased to 0.5 to
effective descaling treatment has been applied. 0.1% of the treating volume. The shut-in time
for the treating slug should be increased to allow
The most popular method of placing LP-55 in a complete spending of the acid.
well is with the Chemical Placement Technique
(CPT). The CPT nomograph (Figure 8.2) is The Calchek service treatment is intended for
used to determine the volume of water in which application in either limestone or dolomite
to mix LP-55. This is based on production rate formations.
and desired recovery time. The volume of LP-
55 to be used is then based on the expected total
water production over the recovery time. For Protex-All Inhibitor
example, if the recovery time is six months, and
the production total is 5480 bbls, the required Protex-All is a blend of LP-55 and a surface-
volume can be calculated. LP-55 is used at a active agent that forms a slowly soluble complex
concentration of 0.002 gal/bbl gives 11 gallons when placed in contact with an aqueous fluid.
of LP-55. If the CPT nomograph shows that This complex appears to have very high
4,000 gallons of water should be used, then adhesive properties on tubular goods and on
eleven gallons would be added to 4,000 gallons sandstone and limestone formations. Protex-All
of water for placement. LP-55 can be diluted provides long term protection against gypsum,
with water and lubricated down the annulus of calcium carbonate, and barium sulfate scales.
wells or through small tubing strings to treat The following types of treatments have been
water downhole. It can also be metered into performed in the field:
water going into injection or disposal wells. In

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• dumping 1-5 gallons of Protex-All down the length and height of the fracture is required.
annulus and overflushing with water The effective permeability of the formation must
also be known so that the fluid loss coefficient
• placing Protex-All at a concentration of 1 can be calculated. The effective permeability
gallon/1000 in an acid or aqueous fracturing should include both matrix and fracture
fluid permeability, which is more important in
• placing 1-5 gallons of Protex-All in water limestones and dolomites rather than in
displacing this dispersion into the formation sandstones.
Protex-All is only very slightly soluble in If fracture dimensions are not available from
aqueous fluids, but is readily dispersible at low frac plans or effective permeability from logs is
concentrations. not available, then reasonable values must be
assumed. These will probably vary from one
Notice that Protex-All should be added to the area to another depending on depth, type of
aqueous carrying fluid on a continuous basis. formation, etc.
Mixing Protex-All in high concentrations with
water or an aqueous fluid will result in a mass Calculations and field evaluations indicate the
precipitation of the complex. Once this complex following treatment suggestions:
adheres to steel, it is difficult to remove. • Effective treatments can be obtained in both
propped and natural or acidized fractures.
Chemical Placement Technique • Treatments can be performed on previously
(CPT) fractured wells or along with fracturing jobs.
• Injection rates should be maintained at 1
CPT is a method of placing chemical solutions BPM or lower while placing the chemical
having high fluid loss properties into producing solutions.
formations to achieve slow feed-back with the
produced fluids. This technique can provide • No fluid loss additives should ever be
long term control of scale and paraffin incorporated into the chemical solutions.
deposition by using solutions of Scalechek LP- • The well should be left shut in for several
55 or Parachek. Emulsion breakers, corrosion hours to permit pressure to dissipate.
inhibitors, foaming agents, bactericides and
alcohols can also be placed for slow feed back. • Recovery times of 6 months to 15 months
have been achieved using LP-55 in water at
The placement of chemical solutions must be a concentration of 10 gallons/1000 gallons.
done in formations that contain natural fractures,
induced fractures that are propped, or along with It is possible to place two or more treating
a fracturing treatment. This is necessary since chemicals into a formation together. However,
the slow return of the chemicals is a result of the this requires careful selection to avoid
pressure drop profile or flow patterns that exist incompatibility. Chemicals that are highly
in a fractured formation. Injection into an adsorbed on formation rock require increased
unfractured formation will result in a fairly rapid treating levels to be effective (such as some
return of the chemicals. emulsion breakers and corrosion inhibitors).
Adsorption will not completely inactivate the
Equations have been developed which permit materials. In fact, it will probably increase the
calculation of total feed back time and also the recovery time but decrease the concentration
initial concentration of chemical being returned being returned. With corrosion inhibitors in
in the produced fluids. In order to use the sandstone formations, as much as 50% of the
equations, there are a number of things that must chemical injected in the initial treatment may
be known or assumed about the formation. never be recovered. However, on subsequent
First, the equations were developed for flow in a treatments nearly 100% will be recovered.
vertical fracture system. Knowledge of the

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Figure 8.11 – CPT Nomograph

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Unit I Quiz

Fill in the blanks with one or more words or select the correct answer(s) to check your progress in
Unit I.
1. Scale deposits can be found in ____________________ ____________________,
____________________, ____________________, and ____________________
____________________ .

2. Scales are classified as ____________________ ___________________, ____________________

____________________, or ____________________ ____________________.

3. Most scales appear as

______________________________________________

______________________________________________

______________________________________________

4. Which of the following fluids can be used to remove acid soluble scales? (check all that apply)

_____a) Regular Acid

_____b) Penetrating Acid

_____c) Diesel

_____d) NE Acid

_____e) Fe Acid

_____f) Xylene

_____g) MSA

_____h) Water

_____i) PAD

5. ____________________, ____________________ ____________________,

____________________ and ____________________ are chemical methods of removing acid
insoluble scales.

6. Scale formation can be inhibited with:

_____a) Scalechek LP-55 additive

_____b) SCP-2

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 Chemical Stimulation

_____c) Calchek service

_____d) Protex-All inhibitor

_____e) All of the above

Now, look up the suggested answers in the Answer Key.

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Unit J: Placement Aids

During stimulation operations it is sometimes
necessary to divert the stimulation fluid. Selection of Bridging Agent
Diverting materials should bridge effectively
and be easily removed. Temporary Bridging
Agents are solids used to divert treating fluids in
Well Conditions
stimulation operations and to protect producing
zones during workover operations.
A series of temporary bridging agents have been
developed for diverting operations involving a
Temporary Bridging Agents variety of well conditions and a wide range of
temperatures. The selection of the bridging
agent and concentration is based on:
The effectiveness of a Temporary Bridging
Agent is dependent on its particle size • formation fluids contacted
distribution. TBA-110, the first water soluble,
graded (specifically sized), temporary bridging • feet of formation
agent was introduced in 1969. Early in 1970, • formation temperature
TBA-350, the first oil soluble, graded,
temporary bridging agent was introduced. The • physical properties of the formation
bridging efficiency of these graded materials • type of well completion
was readily apparent in the field when pressure
charts were studied. • placement technique
Because of the efficiency of TBA-110 (TBA-
350 is now obsolete), TLC-80, with a particle
Melting Point
size distribution to help prevent caking and to
divert effectively, has also been added to the A bridging agent should be selected that has a
inventory. softening point high enough that it does not
soften before the diverting operation has been
The graded bridging agents contain particles completed. In most treating operations, the
ranging from about 0.25 inch to 0.002 inch in treating fluid preceding the diverting material
diameter. The larger particles bridge on the cools the formation. Effective diversion may be
zone. The smaller particles successively bridge accomplished when the normal bottom hole
on larger particles until a bridge is built that has temperatures exceed the melting point of the
very little permeability. Pressure increases are bridging agent.
then sufficient to register on pressure recording
charts and show effective diversion.
Solubility
Bridging agents previously used that were
ungraded (TLC-W3, TLC-15) bridged A bridging agent should be soluble in the
effectively and probably slowed down the flow produced or injected fluid if possible. Oil
of treating fluid into the bridged zone slightly. soluble bridging agents are not used in water
However, the slow down was not enough to injection and disposal wells. Water soluble
show a pressure increase on pressure recording bridging agents should not be used in oil wells
charts and gas wells that are not making water unless
an overflush of water is used to dissolve the
agents. Otherwise, a cleanup operation should
be planned with dilute acid or brine. Some

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materials will sublime (go from solid to vapor) increases the overall effectiveness of the
in gas wells at the bottom hole temperature and diverting process.
can be removed without a solvent.

Carrier Fluid
Well Completion Type
The carrier fluid is an important consideration in
The type of well completion should be diverting. It should have its specific gravity and
considered along with the physical properties of viscosity adjusted to maintain a uniform
the formation. If the formation to be bridged is dispersion of the bridging agent. The carrier
fairly homogeneous and free of vugs or fluid may be gelled or emulsified. Laboratory
fractures, consider bridging agents that are tests show that gel type carrier fluids are less
composed of smaller particles. These particles difficult for the bridging agent to hold in place
should not bridge on perforations or fractures, than emulsions. The strongest bridge is
but instead will bridge on the formation and fill probably achieved with carrier fluids having the
perforations and channeled areas behind the minimum viscosity for maintaining a uniform
casing. Such bridging agents are Matriseal O dispersion of the bridging agent. The lower
and Matriseal OWG. viscosity lets the carrier fluid continue to flow
through the bridge for a slightly longer time and
If the zone contains vugs, fractures or is
deposit more solids for a stronger, less
composed of coarse sand or gravel that will be
permeable bridge. The tail end of the carrier
difficult to bridge, a bridging agent such as
fluid should then have maximum pumpable
TLC-80, TBA-110 or FRAX-160 wax should be
viscosity so that it will not flow through the
considered. Since bridging may be achieved on
bridge and will act as a blanket. This would be
the perforations or on the formation, placement
the ideal method of application but would be
techniques must be considered.
difficult to achieve. The most practical option
would be to compromise between maximum
Placement Techniques pumpable viscosity and the viscosity necessary
to keep the bridging agent uniformly dispersed.
When the graded bridging agents (TLC-80,
TBA-110) are used, special techniques must be Concentration of Bridging
used if they are to pass the perforations and
bridge on the formation. Low concentrations of Agent
bridging agent should be used per gallon of the
carrier fluid, which must be viscous enough to The type of well completion and previous well
maintain a uniform dispersion of the solids. treatment history will help determine the
Larger volumes of carrier fluid are then quantity of solids required to form a bridge.
necessary to transport sufficient bridging agent Erosion of perforations and presence of voids,
through the perforation. vugs, and fractures are also important factors.
If you desire to bridge on perforations, a high The best volumes of both carrier fluid and
concentration of bridging agent is required in a bridging agent vary widely from area to area.
carrier fluid which has as low a viscosity as However, a general rule seems to be to use at
possible and can still transport the bridging least twice the volume of the casing covering the
agent to the perforation. interval for carrier fluid. The quantity of solids
should depend on type of diversion being
Decreasing the pump rate when the diverting attempted.
material approaches the zone is considered one
of the most important steps in correct placement Open hole completions in fractured or vuggy
techniques. This allows an initial bridge to be limestone may require 2-4 pounds of TBA-110
accomplished more easily and quickly and per gallon of carrier fluid. An open hole

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completion in a highly permeable formation, zone. The data presented for bridging in open
free of fractures and vugs, may be bridged and hole, highly permeable, or lost circulation zones
sealed with 4-6 pounds of TBA-110 per square were obtained using the BB Bed test. The zones
foot of open hole surface area. Bridging on 3/8 were considered unfractured and non-vugular.
inch perforations may be achieved with ½ to 2
pounds of TBA-110/gallon of carrier fluid. The
higher concentrations will bridge more quickly, Particle Size Distribution
have less loss of carrier fluid to the formation,
and form a stronger bridge. Effectiveness of a bridging agent is dependent
The bulk density of the solids is also a factor in on its particle size distribution. The efficiency
determining the concentration to use. TLC-80 is of various bridging agents is compared in Table
used at about one-half the TBA-110 8.7. The data were obtained at 76°F using water
concentration. All TLC-80 materials available gelled with 100 pounds of WG-6 per 1000
will not bridge on a 3/8 inch perforation. gallons. The specific gravity of the water was
adjusted to maintain a uniform dispersion of the
Specific data on bridging agent concentrations bridging agent. Bridging agents were used at a
are listed in each bridging agent bulletin. The concentration of 28 pounds per gallon. The
data on the perforations were obtained without carrier fluid containing the bridging agent was
formation, or other materials surrounding the displaced with kerosene using a constant pump
casing, and would simulate bridging on rate of two BPM. The maximum pressure was
perforations in a highly fractured or vugular recorded.

Pressure Held (psi)

Fracture Width 0.10 0.13 0.16 0.20 0.24 0.32 0.40
TBA-110 1000 1000 1000 1000 1000 385 No bridge
+
TLC-15S (graded) 1000 680 685 635 485 No bridge No bridge
+
Unibeads* 340 290 234 129 65 40 No bridge
TLC-80** (Velsicol Coarse) 0 0 No bridge No bridge No bridge No bridge No bridge
Table 8.7 - Bridging Agent Efficiency

*A 1:1 blend of Unibead Buttons and Unibead Wide Range material was used.
**These materials bridged fracture widths shown to have 0 pressure buildup but did not seal. Field operations at higher pump
rates than can be achieved in the laboratory have shown that these materials will achieve some fluid control. However, they are
not expected to be nearly as effective as TBA-110, TLC-15S, TBA-350, or the 1:1 blend of Unibead materials.
+ Obsolete

Open-hole completions in fractured or vuggy • disperses readily in aqueous treating fluids

limestone may require 2-4 pounds per gallon of
carrier fluid. Bridging on perforations can be • aids in maintaining a uniform dispersion of
achieved at 0.5-2.0 pounds per gallon. the polymer
• leaves the sandstone formation water-wet
® The oil-soluble polymer is readily soluble in
MATRISEAL O
most crude oils, kerosene, diesel, and Paragon
(aromatic solvents). Its particle size has been
Matriseal® O is used for diverting treating fluids
controlled so that it passes through 20-40 mesh
in wells that have been completed with sand
sand (permeability of about 121 darcies) and
packs behind slotted liners or sand screens. It is
bridges and seals on Oklahoma #1 sand
a finely ground, oil-soluble polymer slurried in a
(permeability of about 9 darcies). Musol® A,
carrier fluid. The carrier fluid has been carefully
solvent, included in a treating placement fluid
selected to provide a pourable slurry which:
with Matriseal® O softens the Matriseal® O

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diverter particles. The softened particles stick aqueous treating fluid a white precipitate forms
together and do not divert effectively. that functions as a fluid-loss additive for
diverting. The slow solubility of this precipitate
Matriseal® O diverter, compatible with LoSurf-
in water, oil, and gas enables it to divert
259 and LoSurf-300, are the preferred non-
effectively and still have good cleanup
emulsifiers for sandstone acidizing. Matriseal®
properties for all applications.
O can be dispersed in HF acid treating fluid.
The acid flows through the liner and sand pack Musol® A solvent should not be included in
and penetrates the formation. The resin carrier fluids with Matriseal® OWG. The
component of Matriseal O filters out on the face dissolution rate of Matriseal® OWG increases to
of the formation and diverts acid into areas of the extent that it will not be effective.
the formation having lower permeability.
Progressive diversion occurs and eventually
distributes acid over the zone. Temporary Bridging Agents in
The oil soluble polymer is readily soluble in Conjunction with Temblok
most crude oils and will be removed when Diverting Materials
contacted by produced crude oil. However, at
times it may be desirable to spot a hydrocarbon Temblok agents are a series of viscous fluid type
solvent (kerosene, diesel or Paragon) over the diverting materials available in several varieties
zone for rapid removal of the polymer present. to meet differing application requirements for
stimulation and work-over operations. Due to
their viscous consistency, Temblok materials
Matriseal® OWG Diverter resist flow into the formation matrix. Where
vugular or fractured zones are encountered,
Matriseal® OWG is a universal diverting granular agents such as the Temporary Bridging
material that may be used in treating or Agents may be incorporated into the Temblok
completion fluids for injection, disposal, oil and diverting materials to assist in bridging and
gas wells. Matriseal® OWG diverter has unique sealing the zone. The Bridging Agent must be
properties. It is a water clear liquid that may be insoluble in the Temblok material selected.
metered into the stream on large volume treating Table 8.8 describes the properties of various
operations, or it may be dispersed readily in the Temblok materials and compatible Temporary
treating solution when batch mixing. When Bridging Agents.
MATRISEAL® OWG is dispersed in the

Temblok Type Fluid Temblok Time and TBA additives that can be used
Temperature Stability if needed
1 180-350°F
80 Tough Water Gel TBA-110
0.2 to over 30 days
2 200-350°F
90 Tough Water Gel TBA-110, TLC-80, FRAX-160
2 to over 30 days
80-200°F
100 Tough Water Gel TBA-110, TLC-80, FRAX-160
over 30 days
Table 8.8 - Temblok/TBA Properties

1.
Should be prepared with saturated salt water for greatest 2.
Do not use Calcium brines.
stability, and to prevent dissolution of TBA-110.

© 2005, Halliburton 8 • 62 Stimulation I

 Chemical Stimulation

Unit J Quiz

Fill in the blanks with one or more words or circle the correct answer(s) to check your progress in
Unit J.
1. The effectiveness of a Temporary Bridging Agent is dependent on its ____________________
____________________ ____________________.

2. Bridging agent type and concentration is dependent upon:

_____a) formation fluids

_____b) temperature

_____c) formation interval

_____d) type of formation

_____e) all of the above

3. When the graded bridging agents (TLC-80, TBA-110) are used, special techniques must be used if
they are to pass the perforations and bridge on the formation. ________________ concentrations of
bridging agent should be used per gallon of the carrier fluid.

4. If you desire to bridge on perforations, a ________________ concentration of bridging agent is

required in a carrier fluid which has as ________________ a viscosity as possible and can still
____________________ the bridging agent.

5. Musol® A solvent should not be included in carrier fluids with ____________________ or

____________________ because of dissolving problems.

Now, look up the suggested answers in the Answer Key.

© 2005, Halliburton 8 • 63 Stimulation I

 Chemical Stimulation

Unit K: Job Calculations

Three common job types are:
1. Spotting to the end of the tubing or 2 3/8-in. 4.7 Tubing
packer
2. Balanced acid spot 4 1/2-in. 11.6 Casing

3. Flushing and overflushing

We shall go through an example of each.

Calculations for Spotting Acid

to the End of Tubing or Packer
In most wells, it is desirable to place as little Top of Acid
fluid on the formation as possible. Many
chemical placement designs call for the
chemical to be spotted to the end of the treating
tubing by circulating. To spot the acid or
chemical, first find the total capacity of the
tubing using the Red Book:
⎛ ft ⎞
Tubing Capacity = Depth (ft) × ⎜⎜ factor ⎟⎟
⎝ gal ⎠ Tubing Depth 6,500 ft

Then, subtract the amount of acid from the total

tubing capacity:

Flush Volume = Tubing Depth - Feet of Acid Spotted

Example:
Figure 8.12 – Acid Spotting Example
How much 2% KCL water is needed to spot 250
gal 15% HCL to the bottom of the tubing?
Solution:
gal
Tubing Capacity = 6500 ft × 0.1624 (RedBook )
ft
= 1055.6 gal
Flush Vol = 1055.6 gal − 250 gal
= 805.6 gal

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 Chemical Stimulation

2 3/8-in. 4.7 Tubing

Calculations for Balanced Acid
Spot 4 1/2-in. 11.6 Casing

Spotting a balanced acid pill may be necessary

for acid soaking and perforating applications.
The equal height (balanced height) of the acid
can be determined with the equation:
Gallons of acid to be spotted
Height =
⎛ gal gal ⎞
⎜ factor(tubing) + factor(annulus) ⎟
⎝ ft ft ⎠
To find the volume of displacement:
Feet of Tubing to Flush
= Tubing Length - Feet of Acid Spotted

Flush Volume
gal Top of Acid
= Feet of Tubing to Flush × factor(tubing)
ft
Tubing Depth 6,500 ft
Note: The ability to spotting a balance acid pill
is based on the assumption that the well fluid
and the acid are the same weight.

Example:

Find the displacement volume necessary to spot

a balance acid pill of 250 gal. Figure 8.13

Solution:
250 gal
Acid Height =
⎛ gal gal ⎞
⎜⎜ 0.4227 + 0.1624 ⎟
⎝ ft ft ⎟⎠
= 427.28 ft
Flush Height = 6500 ft - 427.28 ft = 6072.72 ft
gal
Flush Volume = 6072.7 ft × 0.1624 = 986 gal
ft

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 Chemical Stimulation

Calculations for Flush and 2 3/8- in. 4.7 Tubin g

OverFlush
4 1 /2- in. 11 .6 Casing
It is a standard practice to flush more than the
volume of tubing after pumping acid. This
ensures that:
• any acid that is not spent can continue to
penetrate the formation
• there is no live acid in the tubing to
cause corrosion
• any secondary precipitates that could
form from the acid reaction are
displaced as far into the formation as
possible
Acid flush volume calculations are done from
the bottom of the perforations or open hole
section. So:

Vol to Pump = Tubing Volume Tubing Depth 6,500 ft

+ Casing Volume to the Bottom Perf
+ Overflush Volume Top Perf 6,700 ft

Example: Bot tom Perf 6,8 00 f t

Calculate the volume needed to overflush an

acid job by 1 barrel per foot of perforations. Figure 8.14

Solution:

gal
Tubing Vol = 6500 ft × 0.1624 = 1005.60 gal
ft
gal
Casing Vol = 300 ft × 0.6528 = 195.84 gal
ft
bbl 42 gal
Overflush = 1 × × 100 ft
ft of perfs bbl
= 4200 gal
Vol to Pump = 1005.6 gal + 195.84 gal + 4200 gal
= 5401.44 gal

© 2005, Halliburton 8 • 66 Stimulation I

Unit Quiz K:
1. Well Information:
Casing – 5.5, 23 lb/ft L-55 to 10,200 ft
Tubing – 2-7/8”, 6.5 lb/ft N-80 with a packer set at 9,850 ft
Perforations – 10,030 – 10, 050 ft
Calculate the displacement necessary to spot 2000 gallons of 10% FE acid to the end of the tubing.

2. Well Information:
Casing – 5-1/2”, 15.5 lb/ft N-80 to 9,500 ft
Tubing – 2-7/8” 6.5 lb/ft N-80 to 8,500 ft
Perforations – 8,500 – 8,550
Assumption: Hole is full of a uniform weight of fluid.
Calculate the volume of flush necessary to set a balanced spot of acid at the top of the perforations.

© 2005, Halliburton 8 • 67 Stimulation I

 Chemical Stimulation

Self-Check Test for Section 8: Chemical Stimulation

Mark the single best answer to the following questions.
1. ______ True ______ False The major acids used in chemical stimulation are HCL and HF.
2. ______ True ______ False Commercially available HCL can be 20 °Be or 22 °Be.
3. ____________________________ acid is the only acid that will not damage chrome.
4. Check what procedures to observe when working with acid.
_____a. wear goggles
_____b. have sodium bicarbonate available
_____c. wash eyes with strong water jet
_____d. smoke around acid tanks
_____e. add acid to water
5. If you have 22°Be acid, how much acid and water are required for 750 gallons of 7% HCL?
__________ gal acid
__________ gal water
6. ______ True ______ False Inhibitors decrease the corrosion rate of acid on steel pipe.
7. ______ True ______ False Halliburton corrosion inhibitors will protect metals other than steel,
such as aluminum and magnesium.
8. ______ True ______ False Matrix acidizing is done at rates and pressures below fracturing
pressure.
9. Emulsion break tests are run with ___________________ ___________________ and
____________________ _______________________. Complete separation of oil and acid in
_____________________ to _____________________ minutes is desirable.
10. ______ True ______ False HF Acid is used to dissolve limestone out of a sandstone formation.
11. ______ True ______ False HF Acid’s rate of spending is constant; it never changes.
12. The major retarded HF system Halliburton offers is:
_____a. Sandstone Acid
_____b. FE
_____c. ClaySol
_____d. ClayFix
_____e. Fines Control Acid
13. ______ True ______ False HF Acid can react with limestone to form an insoluble precipitate.
14. ______ True ______ False Spent HF Acid can react with sodium and potassium to form more
HF acid.
15. Damage to a formation results when invasion of which of the following occurs?

© 2005, Halliburton 8 • 68 Stimulation I

 Chemical Stimulation

a. ______ Clay
b. ______ Whole mud
c. ______ Filtrate
d. ______ All of the above
16. ______ True ______ False If the formation is limestone, mud damage can be removed with HCL
or HF.
17. The cloud point of an oil is __________________________________________________.
18. The pour point of an oil is ___________________________________________________.
19. Paraffin can be removed ____________________, ______________________, and with
____________________.
20. Scales are classified as __________________ _________________ or _______________
________________.
21. List three methods of removing acid insoluble scales.
________________________________________________
________________________________________________
________________________________________________
22. What are two products used for scale inhibition?
______________________
______________________
23. ______ True ______ False Particle size determines how effective TBA agents are.
24. ______ True ______ False TBA products should be insoluble in formation fluids.
25. TBA agents can be placed using
a. ______ acids
b. ______ emulsions
c. ______ gels
d. ______ Temblok
e. ______ all of the above
Now, look up the suggested answers in the Answer Key at the end of this section.

© 2005, Halliburton 8 • 69 Stimulation I

 Chemical Stimulation

Answer Key
Items from Unit A Quiz
1. hydrochloric, hydrofluoric, organic
2. damage removal / matrix / fracture
3. 20 / 31.45
4. sandstone
5. Formic / acetic
6. acetic

Items from Unit B Quiz

1. Goggles
2. sodium bicarbonate
3. skin / eyes
4. hydrogen gas
5. water / acid
6. dust mask

Items from Unit C Quiz

1. 1843
2. 2050 / gallons / water / 6620 / carbon dioxide
3. 1020
4. 288 acid / 712 gal water

Items from Unit D Quiz

1. temperature, time of contact, type of acid, pressure, type of steel, ratio of volume of acid to exposed
steel surface area.
2. Ff.)
3. HII 124 / HHII 500
4. Ff.)
5. 0.05
6. Organic

Items from Unit E

1. skin

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 Chemical Stimulation

2. fracturing
3. collapse / coning / scaling
4. fracture acidizing
5. preflushes / cool
6. F
7. b
8. c
9. sustained – production acidizing

Items from Unit F

1. a, c
2. e
3. physical and chemical composition of the formation, temperature, surface area of rock exposed to a
particular volume of acid, concentration of excess hydrochloric acid
4. Clayfix
5. hydrocarbons / invasion / emulsions
6. Fines Removal Acid

Items from Unit G Quiz

1. filtrate / clay / whole mud
2. Acid / Mud flush
3. F
4. Oil External Emulsions / True Oil Base
5. N-Ver-Sperse A / N-Ver-Sperse O

Items from Unit H Quiz

1. T
2. F
3. temperature / solution
4. temperature / flow
5. The alternate coating of the pipe and draining of the oil, The presence of only a film of oil in contact
with the pipe while the well is flowing oil through water zones, Rough pipe surface, Electrical charger
on various materials in the crude oil, Temperature drop
6. F
7. Mechanical equipment, Solvents which dissolve the deposits, Heat, which melts the wax and reduces
it to a liquid so that it can be easily removed
8. Crystal modifiers
9. Targon II / Tarchek

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 Chemical Stimulation

Items from Unit I Quiz

1. Flow liner / tubing / perforations / formation face
2. water soluble / acid soluble / acid insoluble
3. Thin sealer or popcorn like laminated deposits crystalline deposits
4. a, b, d, e, g, i
5. GYPSOL, Liquid Scale Disintegrator, BaSo4lvent
6. e

Items from Unit J Quiz

1. particle size distribution
2. e.)
3. formation
4. high / low / transport
5. Matriseal OWG / Matriseal O

Items from Unit K Quiz

gal
Tubing Capacity = 9850 ft × .2431 = 2394.54 gal
1. ft
Flush Volume = 2394.54 gal - 2000 gal = 394.54 gal
gal gal
factor for 2 - 7/8" tubing = 0.2431
ft ft
gal gal
factor for 5 - 7/8" casing = 0.6625
ft ft
2. 500 gal
Acid Height = = 552.12 ft
⎛ gal gal ⎞
⎜ 0.2431 + 0.6625 ⎟
⎝ ft ft ⎠
gal
Flush Vol = (8500 ft - 552.12 ft ) × 0.2431 = 1932.13 gal
ft

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 Chemical Stimulation

Self Check Test

1. T
2. T
3. Acetic
4. a, b, e
5. 175 acid / 825 water
6. T
7. F
8. T
9. produced fluid / treating solution / ten / fifteen
10. F
11. F
12. e
13. T
14. F
15. d
16. F
17. the cloud point is the temperature where paraffin begins to come out of solution.
18. Pour point is the temperature where oil will not flow when tilted to a horizontal position
19. mechanically /, solvents which dissolve paraffin, / heat which melts the way and reduces it to a liquid
20. water soluble /, acid soluble /, acid insoluble
21. GypsolYPSOOL, Liquid Sacle Disintegrator, BaSO4lvent
22. SCP-2 / Scalecheck, LP-55
23. T
24. F
25. e

© 2005, Halliburton 8 • 73 Stimulation I

Section 9

Proppants

Table of Contents
Introduction ............................................................................................................................................... 9-3
Topic Areas............................................................................................................................................ 9-3
Learning Objectives ............................................................................................................................... 9-3
Unit A: API Standards............................................................................................................................... 9-3
Roundness and Sphericity...................................................................................................................... 9-4
Specific Gravity ..................................................................................................................................... 9-4
Bulk Density .......................................................................................................................................... 9-4
Sieve Analysis........................................................................................................................................ 9-4
Acid Solubility ....................................................................................................................................... 9-4
Silt and Fine Particles ............................................................................................................................ 9-5
Crush Resistance.................................................................................................................................... 9-5
Clustering............................................................................................................................................... 9-5
Unit A Quiz............................................................................................................................................ 9-6
Unit B: Proppant Types ............................................................................................................................. 9-7
Sand........................................................................................................................................................ 9-7
Resin-Coated Sand................................................................................................................................. 9-7
Sintered Bauxite..................................................................................................................................... 9-8
Ceramics ................................................................................................................................................ 9-9
Unit B Quiz .......................................................................................................................................... 9-10
Unit C: Flow Capacity............................................................................................................................. 9-11
Unit C Quiz: Flow Capacity................................................................................................................. 9-12
Unit D: Proppant Bed Damage ................................................................................................................ 9-13
Unit D Quiz.......................................................................................................................................... 9-15

9•1 Stimulation I
© 2005, Halliburton
 Proppants

Use for Section notes…

9•2 Stimulation I
© 2005, Halliburton
 Proppants

Introduction
Propping agents are the essential part of any
fracturing treatment. Propping agents prop Learning Objectives
open the created fracture to conduct reservoir
fluids to the wellbore. The selection of a
propping agent requires information on the Upon completion of this section, you will be able
conductivity at stress of any material used. to:
Sand is a natural material that is used as a • List API specifications for proppants
propping agent in many hydraulic fracturing
treatments. • Distinguish between different types of
proppants.
• List the physical properties of the different
Topic Areas proppants.

The section units are: • Compare flow capacities of different

proppants under loaded conditions.
• API Standards
• Avoid problems associated with proppant
• Proppant Types damage.
• Flow Capacity
• Proppant Bed Damage

Unit A: API Standards

API (American Petroleum Institute) is the major Some characteristics of proppants used in
national trade association representing the entire hydraulic fracturing that need to be
petroleum industry: exploration and production, monitored are:
transportation, refining, and marketing. With
• Roundness
headquarters in Washington, D.C., and petroleum
councils in 33 states, it is a forum for all parts of the • Spericity
oil and natural gas industry to pursue policy
objectives and advance the interests of the industry. • Specific Gravity

The impetus for forming API in 1919 was the need • Bulk Density
to standardize engineering specifications for drilling • Sieve Size
and production equipment. API has developed some
500 equipment and operating standards used around • Acid Solubility
the world. The API publications dealing with • Silt and Fine Particles
proppants are API RP 56 for frac sand, API RP 58
for gravel pack sand and API RP 60 for high • Crush Resistance
strength frac sand. These publications set limits on • Clustering
certain characteristics of proppant and the
procedures used for testing them. These properties and their API guidelines
are discussed below.

9•3 Stimulation I
© 2005, Halliburton
 Proppants

Roundness and Sphericity Bulk Density

These two properties are particle factors that Bulk density is the volume occupied by a
influence particle packing and load bearing given mass of proppant - the amount of
capabilities. Roundness is the measure of the material to fill a given volume. The units
relative sharpness of grain corners or a grain for bulk density are lb/ft3 or grams/cc. The
curvature. Sphericity is the measure of how closely API recommended maximum for proppants
a particle approaches the shape of a sphere. The API is 105 lb/ft3.
recommended limit for sand for both roundness and
sphericity is 0.6. For resin-coated sand, the API
limits are 0.7. Figure 2.3 is a Krumbein chart. Sieve Analysis
A sieve analysis shows the size distribution
of the sand within the designated size range;
90% of a sample must be within the
designated size range. Not over 0. 1 %
should be larger than the first sieve and not
over 1.0% should be smaller than the last
sieve. Table 9.2 gives U.S. standard mesh
screen sizes.
U.S. U.S.
Sieve Sieve
Series Series
Opening (in.) Opening (in.)
Mesh Mesh

4 0.187 25 0.0280
6 0.132 30 0.0232
8 0.0937 35 0.0197
Figure 9.1 – Chart for visual estimates of
sphericity and roundness (From Krumbein and 10 0.0787 40 0.0165
Sieve 1963) 12 0.0661 60 0.0098
14 0.0555 70 0.0083

Several samples of a particular sand should be 16 0.0469 100 0.0059

observed, then an average roundness factor 18 0.0394 170 0.0035
comparison can be made. In some select cases, 20 0.0331
angularity may be advantageous because the
proppant will tend to bridge in the fracture and be Table 9.1- Standard Sleeve Openings
less likely to flow back into the wellbore. This is
especially true in a formation where the fracture is
slow in closing back completely. Acid Solubility

The solubility of a proppant in 12% HCl -

Specific Gravity 3% FE acid is an indication of the amount of
contaminants present and of the relative
The specific gravity of a proppant is the measure of stability of the proppant in acid. It may also
the absolute density of individual proppant particles indicate the tendency of proppants to
relative to water. The recommended API maximum dissolve in hot brines. Acid solubility is
limit is 2.65 for sand. measured by percentage by weight. The API
recommended maximum for sand is 2%,
while the limit for resin-coated sand is 7%
maximum.

9•4 Stimulation I
© 2005, Halliburton
 Proppants

Silt and Fine Particles • 12/20 mesh- 25%

• 16/20 mesh- 25%
This measure indicates the amount of clay and silt or • 20/40 mesh - 10%
other fine material present. Properly washed and/or
• 40/70 mesh - 8%
processed proppant will not have excess silt and fine
particles. The API recommended maximum limit These tests are performed at stress levels of
for proppant is 250 FIJI (formation turbidity units). 7,500 psi, 10,000 psi, 12,500 psi, and 1
5,000 psi until the maximum fines limit is
reached.
Crush Resistance

Crush resistance indicates the relative strength of a Clustering

proppant by measuring the amount of material
crushed under a given load. It is expressed in units Clustering is measured by percentage by
of percentage of fines. API recommended maximum weight. It indicates the degree of attachment
limits for sand are: of individual proppant grains to one another.
• for 12/20 - 16% at 3000 psi During processing, the grains were not
broken apart. The API recommended
• for 20/40 - 14% at 4000 psi maximum is 1 %.
API recommended maximum limits for high
strength proppants are:

9•5 Stimulation I
© 2005, Halliburton
 Proppants

Unit A Quiz

Fill in the blanks with one or more words to check your progress in Unit A.
1. List 6 characteristics of proppants used in hydraulic fracturing that need to be monitored.

a.

b.

c.

d.

e.

2. Bulk density is the _________ __________ ___ ________ of proppant

3. ______ True ______ False: The maximum API recommendation for % fines of 12/20 sand
at 3000 psi is 16%.

4. The specific gravity of a proppant in the measure of the ______________ _____________ of

individual proppant particles relative to water.

Now, look up the suggested answers in the Answer Key.

9•6 Stimulation I
© 2005, Halliburton
 Proppants

Unit B: Proppant Types

Compatibility includes the effect on fluid
pH, crosslink time, breaker concentration,
Sand and foam stability. Resin coatings are
available on sands, ceramics, and bauxite
Two major sands used as proppants in hydraulic proppants.
fracturing is Ottawa Sand and Brady Sand. Ottawa
Sand, from the Jordan Deposit, is a high-quality Pre-cured or tempered products have a hard
sand from the northern United States. Its pure quartz coating or shell around the proppant grain
composition, white color, lack of dust, high and they are most compatible with our
roundness and sphericity, make it an ideal sand. The fracturing fluid systems. This coating will
grains are made up of mostly monocrystalline, which not bond grains together but it imparts a
results in high individual grain strength. higher level of conductivity performance
when compared to uncoated proppants. This
Brady Sand from the Hickory Deposit, near Brady is most significant with resin coated sands
Texas, is another high-quality sand used for and less significant with resin coated
fracturing, characterized by its slight angularity and ceramic or bauxite proppants.
presence of feldspars. Also known as Brown Sand
because of its color, it is considered to be of lesser Partially curable and encapsulated materials
quality than Ottawa Sand. Although sands are provide proppant grains that will bond
available from other areas, these two provide the together under closure stress in a fracture.
majority of material used in fracturing operations. They are also more compatible with our
The physical properties of commonly used types of fluid systems when compared to fully
sand are listed in Table 9.1 curable resin coated proppants.
Premium Sand Standard Sand
Borden Chemicals, Inc.
(Jordan/Ottawa) (Hickory/Brady) Oil Field Products—Precured
Properties
12/20 20/40 12/20 20/40 Product Name Description

Roundness 0.8 0.8 0.7 0.7 AcFrac Black Plus Furan Resin-Coated Sand

Sphericity 0.8 0.8 0.8 0.7

Specific Gravity 2.65 2.65 2.65 2.65 Borden Chemicals, Inc.
Oil Field Products—Partially Curable
Bulk Density (lb/ft3) 96 102 100 102
Product Name Description
Acid Solubility
(% by Weight)
1.3 1.2 0.9 1.6 AcFrac SB Prime Phenolic Resin-Coated Sand
Crush Resistance
2.4 1.8 11.1 11.0 AcFrac SB Excel Phenolic Resin-Coated Sand
(% Fines)
Ceramax P Phenolic Resin-Coated Bauxite
Clustering
(% by Weight)
0.3 0.1 0.8 0.3
Borden Chemicals, Inc.
Oil Field Products—Fully Curable
Table 9.2 – Physical Properties of Sand
Product Name Description

AcFrac CR 4000 Phenolic Resin-Coated Sand

Resin-Coated Sand Santrol Tempered (precured) Proppants
Product Name Description
Resin Coated Proppants (RCP's) have evolved over
time. They are more compatible with our fracturing Tempered LC Multiple Coat, Phenolic Resin-
fluid systems compared to early generation products. Coated Sand

9•7 Stimulation I
© 2005, Halliburton
 Proppants

Santrol Curable Proppants Sintered Bauxite

Product Name Description

Super LC Phenolic Resin-Coated Sand High-strength sintered bauxite and

intermediate-strength sintered bauxite are
Super DC Dual Coat, Phenolic Resin-
Coated Sand
produced by essentially the same
manufacturing process. Bauxite ore is
Super HS Multiple Coat, Phenolic Resin- ground to a fine powder and formed into
Coated Sand
green pellets. After drying and screening,
Super TF Phenolic Resin-Coated Sand the pellets are fired in a kiln. The firing, or
OptiProp Encapsulated Phenolic Resin- sintering process, fuses the edges of the
Coated Sand individual particles of each pellet. The basic
MagnaProp Encapsulated Phenolic Resin-
difference in the high strength and
Coated Economy Ceramic intermediate strength materials lies in the
raw material used.
DynaProp Encapsulated Phenolic Resin
Coated Premium Ceramic High-strength sintered bauxite is formed
HyperProp Encapsulated Phenolic Resin- from almost pure bauxite ore to create
Coated Bauxite corundum, Al 2O3. This imparts the highest
PolarProp Encapsulated Phenolic Resin-
density (approximately 3.7 specific gravity)
Coated Sand (low temperature and strength for this proppant. Intermediate-
formations) strength sintered bauxite is formed from a
Super HT Phenolic Resin-Coated Sand for less pure bauxite ore. The processing of this
Gravel Packs and Frac Packs ore produces both corundum and mullite
(Al6Si 3 O15).
Curable resin coated proppants offer the highest
bond strength and the greatest potential for This mineral composition results in a less
interference with our fluid systems. The tables below dense (approximately 3.25 specific gravity)
list some of the RCP's currently available. and slightly weaker compound than the
more pure sintered bauxite compound.
AcFrac PR 6000 Phenolic Resin-Coated Sand
Below is a list of some of the bauxite
AcFrac PR 4000 Phenolic Resin-Coated Sand proppants currently available.
Norton-Alcoa Proppants
Ceramix I Phenolic Resin-Coated Product Name Description
Premium Sand
INTERPROP Intermediate Strength Bauxite
Ceramix E Phenolic Resin-Coated
SINTERED High Strength Bauxite
Economy Sand
BAUXITE
Carbo Ceramics, Inc.
Tempered DC Dual Coat, Phenolic Resin- Product Name Description
Coated Sand
CarboProp Intermediate Strength Bauxite
Tempered HS Multiple Coat, Phenolic Resin-
Coated Sand Carbo HSP High Strength Bauxite

Tempered TF Phenolic Resin-Coated Sand Sintex Minerals and Services, Inc.

EconoFlex Phenolic Resin-Coated Product Name Description

Economy Ceramic SinterLite Intermediate Strength Bauxite
Table 9.3 - SinterProp Economy High Strength Bauxite
SinterBall Premium High Strength Bauxite
Table 9.4

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 Proppants

strength than the intermediate- and high-

strength sintered bauxite proppants.
Ceramics
Below is a list of some of the ceramic
proppants currently available.
Ceramic are one of the large classes into which all
useful solid materials can be divided, i.e., metals,
organics, and ceramics. Generally, a ceramic is any Carbo Cermics, Inc.
non-organic, non-metallic solid formed by high Product Name Description
temperature processing (above 875°F). Example CarboLite Premium Low Density Creamic
ceramics include glass, refractories, whiteware
(dishes, pottery, etc.), structural products (brick), EconoProp Economy Low Density Ceramic
abrasives, and cement. Norton Alcoa Proppants
Ceramic proppants are produced in a different Product Name Description
manner than the sintered bauxite proppants using NAPLITE Premium Low Density Ceramic
fluidizing bed processing. The composition of the
ceramic-type proppants shows mostly mullite VALUPROP Economy Low Density Ceramic
(aluminum compound) with some additional silica Table 9.5
compounds. This produces a compound only slightly
denser than sand with specific gravities of
approximately 2.65 to 2.75. These ceramic
proppants have greater strength than sand but less

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 Proppants

Unit B Quiz

Fill in the blanks with one or more words to check your progress in Unit B.
1. The four main types of proppant used today are:
1)
2)
3)
4)
2. The three types of resin coated proppants are:
1)
2)
3)
3. Intermediate-strength sintered bauxite is formed from a ________ _________ bauxite ore.
4. Generally, a ceramic is any ______-____________, ______-________ solid formed by
_________ ________________ processing
Now, look up the suggested answers in the Answer Key at the end of this section.

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 Proppants

Unit C: Flow Capacity

The purpose of proppants is to help prevent the • proppant strength and size
fracture from closing once pumping is stopped.
Proppants are added to the fracturing fluid and • hardness of the formation being
are introduced into the fracture along with the • propped closure stress being applied to the
fluid. proppant bed
A main factor affecting the outcome of a If the particle either crushes or embeds, the
hydraulic fracturing treatment is obtaining an fracture flow capacity will decrease. If severe
adequate propped fracture. The propping agent crushing or embedment occurs, the fracture flow
should provide and maintain a highly permeable capacity may decrease so low that not enough
path for fluid flow toward the wellbore. The contrast exists between the conductivity of the
need for a propping agent to help provide that proppant bed and the permeability of the
path has been verified by numerous field reservoir rock. If this were to happen, results
experiments. When proppants are used, from the fracturing treatment may not be
production is usually higher and the production satisfactory because of the loss of fracture
decline rate is much slower. This suggests that conductivity.
an unpropped fracture is subjected to a
combination of forces that tend to close the One of the first propping agents used in fracture
fracture which reduces its flow capacity. treatments was screened river sand. However,
such angular, poorly screened sand contained
Flow capacity (or fracture flow capacity) is the some particles that were too large to enter the
ability of the fracture to convey the reservoir fracture. Also, bridges formed in the wellbore,
fluid to the wellbore. It is generally expressed subsurface tools, and within the fracture itself.
as the product of fracture permeability and the If the proppant is too large, or if bridging occurs,
fracture width: screenout can result and the treatment will have
Fracture Flow Capacity = (kwf) to be ended prematurely. This results in a
smaller propped fracture than had been designed
where: and additional expense for cleaning out the
k = Permeability (md) of the fracture proppant in the wellbore.

wf = Fracture width (ft) Figure 9.1 is a sample fracture flow capacity

curve. This data were generated using steel
Proppant particles must support the closure plates. All measurements were made with radial
stress. In so doing, some of the particles may flow cells and nitrogen gas, and were conducted
crush, or in a soft formation, embed into the at ambient temperature.
rock. The degree of crushing or embedment
depends on:

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 Proppants

Effect of Proppant Type

20/40, 200 °F, 1.0 lb/ft²
3000
Proppant Type
H Brady
2500 H Ottawa

2000

1500

1000
Conductivity (md*ft)

500

0
0 3000 6000 9000 12000 15000
Stress (psi)
Customer: Job Date: Ticket #: 2
StimWinH v3.1.2
Well Desc: Job Type: Fracture Job 26-May-99 11:45

Figure 9.1 – Fracture Flow Capacity Data – 1 lb/ft2

Unit C Quiz: Flow Capacity

Fill in the blanks with one or more words to check your progress in Unit C.
1. Fracture Flow Capacity = (kwf), where:
k = ________________ ____ ______ ______________
wf = _____________ __________
2. One of the first propping agents used in fracture treatments was _____________ __________
_________.
3. If the proppant is too large, or if bridging occurs, _______________ will result and the treatment
will have to be ended ________________.
Now, look up the suggested answers in the Answer Key at the end of this section.

9 • 12 Stimulation I
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 Proppants

Unit D: Proppant Bed Damage

Several factors will be discussed in this unit that particles when they are completely embedded.
may influence the flow capacity resulting from a The flow capacity may be partially or entirely
bed of proppant under load: lost due to the closure.

• The particles may embed in the rock surface

if they are stronger than the rock and the
closure stress is sufficient to cause
embedment.
• A large percentage of the grains may crush
if the rock is strong and the stress is greater
than the grains can withstand.
• The proppant bed may become plugged
because of the invasion of formation fines.
• Unbroken gel and residue may remain in the
proppant pack plugging pore throats.
The crushing or embedment (sinking into the
fracture face) of proppant particles may cause a Figure 9.3 – Partial Monolayer
fast decline in productivity because of the
reduction in fracture flow capacity. If there is
significant embedment, the flow capacity may
be partially or entirely lost because of fracture
closure. In many cases, the closure may crush
the formation instead of the proppant. The
formation may then release debris that partially
plugs the proppant bed.
Sand may be crushed by the action of the
formation stresses in hard rocks; however, it
does not usually crush to a very fine powder.
Sand may shatter into smaller grains and,
eventually, produce enough small particles to
give some support. The result may be a propped
fracture of a slightly narrower width and a
Propping Agent Not Crushed Propping Agent Crushed
poorer range of proppant sizes than expected.
Therefore, the proppant bed would have less
flow capacity. Figure 9.4 – Multilayer System

Selecting the proper type and size of proppant to

use in a particular formation requires the
gathering of laboratory data.
Of these three, only proppant crushing can easily
be modeled in the laboratory.
Figure 9.3 illustrates what may happen in a
monolayer or partial monolayer system of rigid

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 Proppants

The flow capacity may only be reduced due to

the outer layer of grains embedding, while the
inner layer of grains remains effective. The net
result is to reduce the effective fracture width.
The crushing of the formation due to embedment
may release formation debris that could partially
plug the proppant bed.
Recent studies have shown that probably the
greatest influence on proppant pack conductivity
is our ability to break, clean up, and flow back
the carrier fluid used to place the proppant. Gel
residue, unbroken gel, and high gel-loading filter
Partial Embedment
cake on the fracture face can reduce the flow
Figure 9.5 – Multilayer System capacity of the proppant pack by as much as
80%. The influence of gel damage became clear
when studies were conducted based on gel
loading, base fluid type, and crosslinker type.
Figure 9.4 shows the crushing of rigid particles.
Figure 9.6 shows testing done through a specific
Figure 9.5 illustrates the condition that may exist
proppant pack with different carrier fluids.
in a multilayer system as a rigid particle tends to
embed into a soft formation.

BORATE
XLINK
30lb HPG BORATE 20/40 Sand
2400 w/ persulfate/ XLINK
2
*Conductivity (md • ft)

Con.=lb/ft 0
% Conductive Impairment

amine 40lb HPG

2200 Closure=2000psi
breaker w/ persulfate/ T=100°F
amine 10
2000 breaker

1800 BORATE 20
XLINK
40lb HPG
1600 w/ enzyme
30
breaker TI TAN TE
1400 2128
XLINK ANTI-
40lb HPG MONA TE
40
1200 1971
w/ enzyme XLINK
breaker 40lb HPG 50
1000 1500 w/ enzyme
breaker
TI TAN TE
60
800 1115 XLINK
808 40lb HPG 70
600 w/ enzyme
breaker
80
400 430
200 90
0 *STI M-LAB Data
100
Figure 9.6

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 Proppants

Unit D Quiz

Fill in the blanks with one or more words or circle the correct answer to check your progress in
Unit D.
1. Name four factors may influence the flow capacity resulting from a bed of proppant under load:

2. The crushing or embedment of proppant particles may cause a fast decline in productivity
because of the reduction in ____________ _______ _____________.
3. The crushing of the formation due to embedment may release formation ________ which could
partially _________ the proppant _______.
4. Gel residue, unbroken gel, and high gel-loading filter cake on the fracture face can reduce the
______ __________ of the proppant pack by as much as ______%.
Now, look up the suggested answers in the Answer Key at the end of this section.

9 • 15 Stimulation I
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 Proppants

Self Check Test for Section 9

Mark the single best answer to the following questions.
1. Name the two properties that influence particle packing and load bearing capability.

2. Define specific gravity of a proppant.

3. Define bulk density of proppant.

4. ______% of a proppant sample must be within the designated size range.

5. The degree of crushing or embedment of proppant depends on.

6. Name four factors that may influence the flow capacity resulting from a bed of proppant under
load.

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 Proppants

Answer Key

Items from Unit A Quiz Refer to

Page
1. Roundness, Spericity, Specific Gravity, Bulk Density, Sieve Size, Acid Solubility, Silt
and Fine Particles, Crush Resistance, Clustering
9-3
2. Volume / mass
9-4
3. T
9-5
4. Absolute Density
9-4
Items from Unit B Quiz Refer to
Page
1. Sand, Resin Coated Sand, Ceramics, Sintered Bauxite 9-9
2. Curable, Partially cured, pre-cured 9-8
3. less pure 9-8
4. non organic / non metallic / high temperature 9-9
Items from Unit C Quiz Refer to
Page
1. Permeability of the fracture / fracture width 9-11
2. Screened river sand 9-11
3. Screenout / permeability 9-11
Items from Unit D Quiz Refer to
Page
1. The particle may embed in the rock surface
A large percentage of the grain may crush
The proppant bed may become plugged
Unbroken gel and residue may remain in the proppant pack 9-13
2. Fracture flow capacity 9-15
3. Debris / plugs / bed 9-13
4. Flow capacity / 80% 9-14
Self-Check Test Refer to
Page
1. Roundness
Sphericity
9-4
2. The absolute density of individual proppant particle relative to water
9-4
3. The volume occupied by a given mass of proppant
9-4
4. 90%
9-4
5. Proppant size to strength
Hardness of the formation
Propped closure stress being applied to the proppant bed 9-11

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 Proppants

6. The particle may embed in the rock surface

A large percentage of the grain may crush
The proppant bed may become plugged
Unbroken gel and residue may remain in the proppant pack 9-13

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