Section 330

Schlum berger COILED TUBING SERVICES MANUAL

Dow ell Rev A - 98

MATRIX TREATMENT

Contents Page

Introduction .................................................................................................... 2
1 MATRIX STIMULATION ................................................................................. 2
1.1 Design ................................................................................................. 2
1.1.1 Candidate Selection ............................................................................ 4
1.1.2 Treatment Fluid .................................................................................... 5
1.1.3 Fluid Additives .................................................................................... 6
1.1.4 Injection Pressure and Rate ................................................................ 7
1.1.5 Treatment Volume ................................................................................ 7
1.1.6 Diversion ............................................................................................. 7
1.1.7 Downhole Tools .................................................................................... 8
1.1.8 Pumping Schedule .............................................................................. 9
1.1.9 Horizontal Wellbores .......................................................................... 10
1.2 Matrix Stimulation Operations ........................................................... 10
1.2.1 Execution Precautions ...................................................................... 10
1.2.2 Equipment Requirements .................................................................. 10
1.2.3 Coiled Tubing Equipment ................................................................... 10
1.2.4 Pressure Control Equipment .............................................................. 11
1.2.5 Pumping Equipment .......................................................................... 11
1.2.6 Monitoring and Recording Equipment ................................................ 12
1.2.7 Downhole Equipment ......................................................................... 12
1.2.8 Fluid Preparation ............................................................................... 12
1.3 Evaluation of Matrix Stimulation ........................................................ 12

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Introduction • Spotting the treatment fluid with CT will help ensure

complete coverage of the interval. This in conjunction
When a well does not, or can no longer, produce at the rates with an appropriate diversion technique will help ensure
expected, it is possible that the formation is “damaged.” By uniform injection of fluid into the target zone. Spotting the
carefully evaluating the wellbore and reservoir parameters, treatment fluid also avoids the need to bullhead wellbore
the type and degree of damage can be identified. If the fluids into the formation ahead of the treatment.
reservoir permeability is low, the well may be a candidate
for hydraulic fracturing. However, if near-wellbore damage • Long intervals can be more effectively treated using
is found to be reducing well productivity, matrix stimulation techniques and tools that have been developed for use
may be appropriate. In addition to offering economic with CT, e.g. a selective treatment system using straddle-
advantages over hydraulic fracturing, matrix treatments pack isolation tools. This is particularly important in
are preferred when fracturing may result in the undesirable horizontal wellbores.
production of gas or water.
By recognizing the limitations of the CT and associated
1 MATRIX STIMULATION equipment, treatments can be designed to achieve the
maximum benefit to the zone while operating within safe
Various types of damage exist, several of which may limits and approved techniques. For example, the relatively
coexist, because almost every operation performed on a high friction pressures and low pump rates associated with
well (drilling, completion, production, workover and stimu- CT can extend the duration of large volume treatments
lation) is a potential source of damage. The most common beyond viable limits. In many cases, a lower volume
form of damage is plugging of the formation around the treatment selectively applied will achieve similar, or better,
wellbore. results.

Stimulation treatments must either remove the damage (in 1.1 Design
sandstones) or create channels to bypass the damaged
zone (in carbonates). Such matrix stimulation treatments The following general guidelines outline the principal con-
are designed to restore the natural permeability of the siderations when designing and executing matrix treat-
formation by injecting treatment fluids at a pressure less ments. While most of the points listed will apply to any
than the formation fracture pressure. matrix treatment, some emphasis is made on consider-
ations which apply to operations performed through CT:
Coiled tubing is commonly used to perform matrix treat-
ments, and in many cases will offer several advantages • Ensure that the well is a candidate for matrix stimulation
over conventional treatment techniques: by confirming the presence of damage.

• The CT pressure control equipment configuration allows • Identify the location, composition and origin of the
the treatment to be performed on a live well. This avoids damage.
potential formation damage associated with well killing
operations. • Gather and compile the wellbore and completion informa-
tion required for job design and evaluation of treatment
• Associated operations can be performed as part of an options.
integrated service, e.g. wellbore fill can be removed prior
to the matrix treatment and nitrogen or artificial lift • Select an appropriate treatment fluid, including additives
services may be applied to restore production following and associated treatments. Conduct compatibility tests
the treatment if required. to ensure there are no adverse reactions between fluids.

• Performing the treatment through CT avoids exposing the • Determine the maximum injection rate and pressure.
wellhead or completion tubulars to direct contact with
corrosive treatment fluids. • Determine the treatment volume.

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• Consider the use of diverting agents to help ensure treatments cannot be understated. This is necessary for
complete coverage. several reasons:

• Consider the use of selective treatment tools. • By confirming the composition, location and degree of
damage, the selection of an appropriate treatment fluid is
• Prepare a complete pumping schedule, including shut-in possible.
and flowback requirements.
• The maximum cost effectiveness of the treatment can
• Forecast the economic viability of the treatment. only be ensured if all aspects of the treatment are
optimized.
The importance of obtaining adequate, and accurate,
wellbore and reservoir data prior to designing stimulation

MATRIX TREATMENT DESIGN DATA

Drilling - Drilling mud details over zone of interest, e.g. type, density, losses, unuaual conditions,
etc.
- Casing/liner cementing deatils for zone of interest, e.g. type, density, losses, evaluation,
unusual conditions, etc.

Completion - Production casing/liner and tubing details, e.g. size, weight, grade, depths, deviation,
nipples or restrictions, material/alloy, etc.
- Perforation details, depth, interval, shot density, etc.
- Completion fluid details, e.g. type, density, losses, etc.

Reservoir - Formation analyses

- Reservoir temperature and pressure
- Porosity and permeability
- Gas/oil contact, water/oil contact

Production - Production test results, e.g. skin, effective permeability, production rates, etc.
- Production logs/history
- Results of NODAL analyses

Workover - Details of previous stimulation or remedial treatments

Laboratory Analyses - Acid solubility

- Formation water analyses
- Emulsion and sludge testing
- Iron content testing
- Permeability and porosity
- Flow test (ARC)
- SEM/Edax studies
- Petrographic studies
- Determine paraffin/asphaltine content

Figure 1.

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• By conducting pre- and posttreatment tests and compari- The presence and amount of damage are calculated from
sons, the efficiency of the treatment may be quantified. data obtained by conducting a pressure transient analysis,
i.e. by pressure buildup or drawdown tests. Such tests
In addition to reservoir and wellbore parameters, the selec- provide invaluable information to optimize the treatment
tion of an appropriate treatment may be dependent on the and evaluate the results.
well or field production objectives and economics.
The type, location and origin of the damage are determined
1.1.1 Candidate Selection by reviewing the results of the pressure transient analyses
in conjunction with the information outlined in Figure 1.
When a well has been identified as a possible candidate for
matrix treatment, it is necessary to gather and compile data Damage can be characterized by two important parameters
for analyses and design purposes. Figure 1 summarizes - its composition and location. The locations of various
the typical fields of data required for matrix treatment damage types are summarized in Figure 2.
design. This should be regarded as a basic guide list which
may require additional input for complex job designs or Wellbore and Completion Characteristics
procedures.
A key factor in determining the suitability of CT in any
Formation Damage operation is the ability to safely run and retrieve the CT into
and out of the wellbore. The size of completion tubulars and
The objective of a matrix treatment is to remove the placement of restrictions will initially determine if CT can be
damage which impairs the productivity of the well, i.e. used to convey the treatment fluid or tools.
decrease skin. Therefore, it is essential to know the type,
amount, location and origin of the damage.

TYPE AND LOCATION OF COMMON FORMATION DAMAGE

Damage Location

Tubing Gravel Pack Perforations Formation

Type of Damage

Scales x x x x

Organic Deposits x x x x

Silicates, Aluminosilicates x x x

Emulsion x x x

Water Block x

Wettability Change x

Bacteria x x x x

Figure 2.

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In highly deviated and horizontal wellbores, deviation The following list summarizes the criteria considered when
survey data are required, in addition to completion geom- selecting treatment fluids for use with CT:
etry, as input for tubing forces model software. The soft-
ware may then be used to determine how far the CT may be • Physical characteristics of the damage. These will often
pushed into the wellbore. In addition, the anticipated forces determine the nature of the base treatment fluid (e.g. acid-
are calculated for running and retrieving the CT. or solvent-base treatment).

Well Preparation • Reaction of the treatment fluid with the formation. Adverse
reactions between the formation and treating fluid can
There are several options available when selecting a create new damage and compound existing productivity
treatment technique. The entire treatment, or only part of problems. Such potential reactions are controlled by
the treatment, may be performed through CT. Regardless additives in the treatment fluid and by preflush and
of the technique employed, it is undesirable to inject overflush treatments.
damaging fluids, scales or other wellbore solids into the
formation. Design consideration must be given to the • Prevention of excessive corrosion, both to CT and
removal of the following potential damage sources before completion equipment (see subsection Corrosion Inhibi-
conducting the main treatment: tor).

• Wellbore fill material near the treatment zone • Use of friction reducers to optimize the treatment rate (see
subsection Friction Reducer).
• Scale, asphalt or solids in the production tubing/liner
• Compatibility of treatment fluid with wellbore and reservoir
• Rust and scale deposits inside the CT work string fluids. Fluid additives are used to prevent sludge or
emulsions, disperse paraffins and prevent precipitation of
A typical treatment uses a fluid containing inhibited acid, reaction products.
solvents, iron reducing agents and solids suspending
agents to clean tubulars before stimulation and sand • Compatibility of treatment fluid with diverting agent (see
control treatments. In addition to removing damaging subsection Diversion).
solids, the treatment prevents the main treating fluid from
carrying high concentrations of dissolved iron into the • Cleanup and flowback. Using CT to perform a matrix
formation. treatment provides the means to quickly initiate produc-
tion following treatment. If the reservoir pressure cannot
1.1.2 Treatment Fluid overcome the hydrostatic pressure exerted by the spent
treatment fluid, nitrogen kickoff techniques may be per-
Selection of an appropriate treatment fluid is determined by formed. As an alternative, energizing the treatment fluid
the type of damage and its location. The location of the may be appropriate.
damage is a significant consideration because the treat-
ment fluid may contact several other substrates before Preflush/Overflush
contacting the damaged zone, e.g. rust or scale on well
tubulars or carbonate cementing materials. The fluid must Some treatments, especially in sandstone reservoirs,
then provide an effective treatment on contact with the require preflush and overflush fluids to prevent adverse
damaged zone. secondary reactions and the creation of precipitates from
the treatment fluid.
In most cases, the exact type of damage cannot be
identified with absolute certainty. In addition, there is often The preflush provides separation between the connate
more than one type of damage present. Therefore, many water and treatment fluid and, in sandstone treatments,
stimulation treatments incorporate fluids to remove more reacts with carbonate minerals in the formation to prevent
than one type of damage. their reaction with the hydrofluoric acid (HF). Brine, solvent
or hydrochloric acid (HCl) can be use as preflush fluids.

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The primary purpose of an overflush is to displace poten- • Surfactants have several functions and uses which may
tially damaging precipitates deep into the reservoir, away be summarized as aiding the penetration of fluids through
from the wellbore. Special overflushes can be formulated to the formation during treatment and flowback.
facilitate diverter cleanup. Ammonium chloride brine, HCl
(3 to 10%) and light hydrocarbons (e.g., diesel) are com- Many of the additives commonly used in stimulation
monly used as overflush fluids. treatments will present a hazard to personnel and the
environment if handled incorrectly. Consideration must be
The volume of preflush or overflush required is calculated given to the safe handling, mixing, cleanup and disposal of
on the basis of the radial displacement required. treatment fluids and additives.

1.1.3 Fluid Additives Corrosion Inhibitors

While the base treatment fluid is designed to remove the When selecting a corrosion inhibitor, the following condi-
damage, most treatments require the use of additives to tions must be considered:
improve reactions and control potential damage to the
formation, completion tubulars or CT work string. The • Type and concentration of acid
following types of additive are commonly used on matrix
stimulation treatments: • Maximum temperature

• Acid corrosion inhibitors are required on all jobs to reduce • Duration of acid contact
the rate of corrosion on treating and completion equip-
ment to an acceptable level. • Type of tubular/completion goods which will be exposed

• Alcohol is often used in gas wells to lower surface/ • Presence of H2S

interfacial tension, increase vapor pressure and improve
cleanup. The effective range of corrosion inhibitors can be extended
and improved by using inhibitor aids.
• Antifoam agents prevent excess foam from being formed
when mixing fluids on the surface. H2S Protection

• Clay stabilizers are used to prevent damage from the The presence of H2S affects the design and execution of
dispersion, migration or swelling of clay particles. matrix stimulation jobs in several ways:

• Diverting agents help ensure complete coverage of the • Because H2S is frequently liberated as an acid reaction
zone to be treated. product, the well condition must be considered sour
following treatment and during cleanup. Personnel and
• Formation cleaner will kill and remove bacteria and equipment safety requirements must be observed during
polymer residues. these periods.

• Iron stabilizers are used to prevent the precipitation of • Wells with a sour status must be treated using CT
gelatinous ferric iron in the formation. downhole tools and equipment that can be positively
identified as suitable for H2S service.
• Mutual solvents serve as a wetting agent, demulsifiers
and surface/interfacial tension reducer. • The efficiency of some additives, especially corrosion
inhibitors, can be significantly reduced in the presence of
• Organic dispersants and inhibitors are used to remove and H2S.
inhibit the deposition of organic materials.

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Protection against the effects of H2S can be achieved by 1.1.5 Treatment Volume
using a scavenger. In most cases, H2S protection should be
applied to the exterior surface of the CT as well as included The treatment volume (gal/ft of perforated interval) is most
in the treatment fluid. commonly determined by field experience, although labo-
ratory tests can be conducted if no history exists. The
Friction Reducers amount of acid required to remove formation damage is
dependent on many factors relating to the characteristics
A friction reducing agent can significantly increase the rate of the damage, formation and treatment fluid.
at which fluids may be pumped. In addition to improving
treatment efficiency, this reduces job time, which may be 1.1.6 Diversion
an important consideration in large volume treatments.
Successful matrix treatments depend on the uniform distri-
1.1.4 Injection Pressure and Rate bution of the treating fluid over the entire production (or
injection) interval. When fluids are pumped into a well, they
The design of matrix acid treatments should not only naturally tend to flow into the zones with the highest
specify the volumes and types of fluid to be injected, but permeability and least damage. By diverting the flow of
also the maximum permissible injection rate and treating treatment fluid to the areas of lesser permeability, a more
pressure, to avoid fracturing the formation. effective treatment will be achieved. Production log data
can be used to identify high-permeability zones or thief
Downhole Sensors zones, enabling the design of an efficient placement/
diversion technique.
Downhole sensors provide a real-time downhole data acqui-
sition system which can be used to monitor temperature, The criteria for selection of a diversion technique or agent
pressure and casing collar data. Real-time bottomhole include the following:
pressure (BHP) and temperature (BHT) data acquired
during a matrix treatment can be used to determine the • The diverting agent must provide uniform distribution of
efficiency of the stimulation as it progresses. This capabil- treating fluid into zones of widely different permeability.
ity provides several benefits contributing to the optimiza-
tion of the treatment: • The diverter must not cause permanent damage to the
formation.
• Provides accurate BHP and BHT data for any well profile.
This includes vertical, inclined and horizontal wellbores, • A rapid and complete cleanup must be possible to avoid
cased and open hole. secondary damage from precipitates.

• Evaluate-Treat-Evaluate – Well test data collected by the • The diversion agent must be compatible with the treating
sensors can be processed on location to allow for last fluid, additives and overflush or displacement fluids.
minute changes in a treatment design.
• The diverter must be effective at the applicable treatment
• Optimized diversion – Data from the sensors allows for temperature.
changes to be made to the treatment schedule as the job
is being pumped. For example, while a foam diversion Diverting techniques can be classified as mechanical,
stage is being pumped, the BHP continues to decrease chemical or foam. In addition, although not a true diversion
instead of increase; the foam stage can be continued until technique, reciprocating the CT nozzle over the treatment
the BHP sufficiently increases to indicate that diversion zone during the treatment can be beneficial in some
is taking place. operations.

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Mechanical Diversion greater than that of the tightest zone, little or no diversion
will occur.
Mechanical diversion methods applicable to CT matrix
treatments are limited to techniques incorporating bridge • Invasion – Deep invasion of diverter into a producing
plugs, packers and straddle packers. Conventional meth- formation is undesirable. The efficiency of diversion and
ods of diversion using ball sealers are not compatible with subsequent cleanup is increased by reducing invasion.
CT conveyed treatments because of the restricted internal
diameter and low pump rates associated with CT. • Dispersion – To ensure a satisfactory buildup of diverter,
the particles of diverting agent must be properly dis-
The use of packers and plugs to isolate and selectively persed in the carrier fluid.
treat zones can be desirable because the treatment is
effectively conducted on a shorter zone. The distance • Compatibility – Diverting agents must be compatible with
between the two packers is adjustable, using a range of the base treating fluid, additives and overflush/displace-
spacers, when the tool is assembled. ment fluids. They must be inert toward the carrier fluid at
the well treating temperature.
The following points must be considered when designing a
matrix treatment in conjunction with a packer tool string: • Cleanup – The diverting agent must be soluble in the
production (or injection) fluid to enable a rapid and
• The maximum spacer length (i.e. treatment interval) is complete cleanup.
limited by the maximum tool length that can be safely
deployed into and out of the well. Foam Diversion

• The maximum injection pressure is determined by the Foam can be an effective diverter in many matrix stimula-
specifications and expansion of the packers. tion treatments, particularly those performed in horizontal
wellbores. Unlike a particulate diverter that requires fluid
• All fluids must be free of particulate solid which could contact to assist cleanup, foam will break or be produced
block restricted passages within the tool string. to allow a rapid and efficient cleanup.

• Circulation through the work string while the toolstring is A typical foam diversion treatment generates and main-
being run and retrieved is not possible. Pumped fluids will tains a stable foam in the formation (thief zone) during the
cause the packer elements to inflate, thereby increasing treatment. By diverting the treatment fluid from the thief
the risk of damaging the packer or surging or swabbing the zone to the damaged zone, a complete and effective
wellbore. treatment is achieved.

Chemical Diversion The foam diversion treatment would typically follow a

pumping schedule such as outlined in Figure 3.
Most chemical diverters function by forming a bridge or
cake of lower permeability on the formation face to create 1.1.7 Downhole Tools
an artificial skin. This soluble cake is dissolved and
removed during cleanup and subsequent production (or A number of tool strings and bottomhole assemblies
injection). The efficiency of chemical diversion techniques (BHAs) are used in conjunction with matrix stimulation
is improved with higher injection or treating rates. treatments. The string composition and configuration will
depend on the tool-string function; however, the following
An appropriate chemical diverting agent must meet several criteria will apply to all tool strings used on matrix treat-
physical and chemical requirements: ments:

• Permeability – The bridge or cake formed on the formation • The material from which the tool is manufactured must be
face should be as impermeable as possible to achieve resistant to inhibited treatment fluid.
maximum diversion. If the permeability of the cake is

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• The tool seals and components must be compatible with • Fluids used to clean the completion tubulars
the treatment fluid and additives.
• Preflush and injectivity test fluids
• The tool seals or O-rings should be located to protect
threaded connections or components from corrosive • Main treatment fluid (including diverter stages)
treatment fluids.
• Overflush fluids
1.1.8 Pumping Schedule
Cleanup and Flowback
A pumping schedule detailing each fluid stage of the
treatment should be prepared. The schedule should include In most cases, flowback of spent fluids should be accom-
anticipated pump rates and times, and can be regarded as plished as soon as possible. Detrimental reaction products
a summary of the total operation. The volume and density and precipitates can be formed within the formation if some
of each fluid stage should be noted. Each fluid should be spent-acid products remain for an extended time. There-
listed, including: fore, a rapid flowback is generally desirable. However, in
some cases (notably following clay damage treatments),
• Fluids circulated while running in the hole (RIH) with the the production rate should be gradually increased to mini-
CT mize the migration of fines.

• Fluids used to circulate out wellbore fluids or fill material The pH of wellbore fluids should be monitored during the
that could be damaging to the formation cleanup period.

FOAM DIVERSION PRINCIPLES

A foam diversion process generally consists of five distinct and orderly steps.

1. Clean the near wellbore region (except dry gas wells).

Brine with mutual solvent or similar is injected to remove oil from the near wellbore region (oil destroys
foam) and to water wet the formation.

2. Saturate the near wellbore area with foamer.

Inject HCl or brine containing a foaming agent to displace the mutual solvent (solvents are detrimental
to foam), to minimize the adsorbtion of the foaming agent from the foam and ensure a stable foam is
generated in the matrix.

3. Foam injection.
A 55 to 75% quality foam fluid is injected into the matrix to generate a stable viscous foam,
resulting in an increased bottom hole treating pressure.

4. Shut-in (recommended).
A ten minute optional shut-in period decreases the time required to reach maximum diversion.

5. Inject treating fluids containing surfractant.

The treating fluid containing foaming agent is injected at a low rate. Omission of the foaming
agent at this step will reduce the foam stability and consequently reduce the diversion efficiency.

Figure 3. Foam diversion principles.

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1.1.9 Horizontal Wellbores addition, the requirements of the operating company and
applicable regulatory authorities must be known.
Attempts to bullhead acid treatments into horizontal
wellbores have generally proved ineffective. Techniques Equipment
that improve fluid placement and treatment efficiency have
been developed using CT. The work string is placed at the All treating and monitoring equipment must be spotted and
end of the wellbore and is slowly retrieved toward the operated in accordance with the requirements of the rel-
vertical section. Reactive fluids are pumped through the CT evant Standards of Operation. In addition, equipment
while an inert fluid is pumped down the CT annulus. This certified for use in hazardous areas must be operated and
technique assumes that the acid will react laterally with the maintained in accordance with the operating zone require-
formation exactly where the CT nozzle is located. Obvi- ments.
ously this is not always possible, especially in carbonate
reservoirs where thief zones can prevent the desired fluid Posttreatment
placement. Thus, horizontal wellbores are generally treated
in discrete intervals with stages of chemical diverters used Following any acid treatment, it is possible that H2S may be
to separate the treatment intervals. liberated. Therefore, appropriate precautions should be
taken during posttreatment work. Additionally, corrosive
1.2 Matrix Stimulation Operations treatment fluids may be produced to surface.

1.2.1 Execution Precautions 1.2.2 Equipment Requirements

Execution precautions to be observed during matrix stimu- Treatments, such as matrix stimulation, which require the
lation treatments are generally based on the corrosive and preparation and pumping of corrosive fluids must be care-
toxic nature of the chemical products used. However, there fully planned and executed. The treatment fluid and spent-
are several other important considerations which must be fluid returns should be routed to minimize exposure to
understood and accounted for in the execution procedure. personnel and equipment.
In addition, personnel involved in service activity or flowback
operations following the treatment, should be informed of 1.2.3 Coiled Tubing Equipment
the treatment and potentially hazardous conditions which
may exist on completion of the treatment. It is recommended that the CT workstring internal surface
be pickled with a low-concentration inhibited acid before
Personnel and Environment performing the matrix treatment. Such a treatment provides
the following benefits:
All personnel involved in the design or execution of matrix
stimulation or CT services must be familiar with require- • Rust and scale deposits that can be damaging to the
ments detailed in the relevant safety standards. formation if injected are removed.

The corrosive and toxic nature of most stimulation fluids • Inhibition from the main treatment fluid is more effective
and additives demands that care and attention are required if the inhibitor is adsorbed onto a clean surface.
during all phases of the operation. The handling, mixing
application, cleanup and disposal of stimulation fluids must The pickling process can be performed before or after the
be completed with due consideration for personnel and equipment arrives at the job site. A significant consider-
environmental safety. ation in determining the place of treatment is the disposal
of the fluids following the pickling treatment. In many cases
Well Security the most convenient disposal method is to use the wellsite
production or disposal facility.
The control of well pressure and fluids must meet the
requirements of the relevant Standards of Operation. In

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1.2.4 Pressure Control Equipment

Because significant quantities of H2S may be liberated

during an acid treatment, only H2S service pressure control
equipment should be used.

In treatments when acid is to be pumped through the

production tubing as well as the CT work string, the acid
injection point must be below the CT pressure control
equipment. Similarly, when flowing spent treating fluids,
avoid flowing through the CT pressure control equipment
(Figure 4). The extent of postjob flushing and neutralizing
of fluids in the CT pressure control equipment will depend
on the likelihood of corrosive fluid contact. However, due to BOP kill port
the nature of the equipment, acid contact should be Pump-in Tee
assumed and equipment internally cleaned and inspected
following every operation. Wing valve
1.2.5 Pumping Equipment
Casing valve
All fluid mixing pumping and storage equipment must be
clean and free from solids. If cementing equipment is to be
used, a pickling/acid treatment must be performed on the Production tubing
equipment and lines to ensure no solid particles are
released during the treatment. All tanks should have
accurate volume markers or strap charts to ensure correct
treatment volumes. Coiled tubing

All surface mixing, storage and pumping equipment must

be clean and free from damaging solids. The equipment and
lines should be flushed with clean water to remove poten-
tially damaging solids or liquids.

Pressure and rate limits for every stage of the operation

must be defined and noted on the pumping schedule.

Operations that require the manipulation or movement of

the CT string during the treatment must be conducted with
a good line of communication between the fluid pump
Figure 4. Pressure control equipment
operator and the CTU operator. In most cases radio
configuration.
headsets will be required.

The maximum pump rate achievable under the given

pressure limitations should be used to reduce the exposure
time of equipment to corrosive fluids and also to achieve
the maximum diversion effect.

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The volume and type of displacement fluid used during the 1.3 Evaluation of Matrix Stimulation
treatment will determine the amount of postjob flushing and
neutralizing that is required. The evaluation of matrix acidizing treatments is based on
the analyses of the reservoir response to the injection of the
1.2.6 Monitoring and Recording Equipment stimulation fluid. In particular, the change (improvement) in
reservoir flow characteristics is of interest.
Monitoring and recording equipment must be capable of
operating with all treating and displacement fluids at the By modeling and comparing the response of an ideal
rates anticipated during the treatment. reservoir with that of the actual reservoir, the degree of
damage is assessed. Injection pressures measured and
Wellbore, fluid and reservoir parameters required by record- recorded during the stimulation treatment can be inter-
ing and process software for real-time analyses should be preted to provide an indication of the efficiency of the
accurately input. damage removal.

Departures from the planned pumping schedule must be

noted for postjob reporting purposes.

1.2.7 Downhole Equipment

Prior to the installation of any tool in a CT tool string, the

following checks must be made:

• A note of the tool dimensions and profile must be made

for use in the BHA fishing diagram. Minimum require-
ments are length, OD, ID and connection size and type.

• Operating specifications for the tool must be noted, to

ensure that the operating conditions for the tool are not
exceeded. The following information should typically be
included — tension, compression and pressure limita-
tions, temperature ranges, H2S service and fluid compat-
ibility.

• All downhole tools which have been exposed to corrosive

fluids should be serviced as soon as possible following
retrieval. As a minimum requirement, the tools should be
broken at all service breaks and flushed clean.

1.2.8 Fluid Preparation

Fluids should be prepared to the design specification

following the standards set in the Standards of Operation.

Samples of all raw and mixed fluids should be taken and

kept until the job is completed and has been fully evaluated.
In addition, the pH and specific gravity (SG) of all fluids
should be checked and noted.

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