21. Method of Diluting Raw Acid.

the raw acid in terms of Baumé (°Bé) or the Specific Gravity (s.g.). The first step in
the mixing acid is to measure the density as follows:
1. Put a sample of the raw acid to be tested in a 250 cc cylinder and take
the degrees Baumé (or specific gravity) reading with a hydrometer.
Also take the temperature of the sample.
2. Correct the degrees Baumé or specific gravity to the standard
temperature of 60° F (16° C) by using the correction factors listed in
Table .
3. Convert the corrected degrees Baumé or specific gravity to percentage
of HCl using Figure 29, page 148.
4. Use dilution charts (see Mixing Manual or Engineering Handbook) to
determine how much raw acid is required to mix 1000 gallons (litres) of
acid at the desired strength. Alternatively the following equation can be
used.
Gallons of Strong Acid = 1000 x (s.g. Weak Acid) x (% Strength Weak Acid)
Per 1000 gallons Weak (s.g. Strong Acid) x (% Strength Strong Acid)
Litres of Strong Acid = 1000 x (s.g. Weak Acid) x (% Strength Weak Acid)
Per 1000 Litres Weak (s.g. Strong Acid) x (% Strength Strong Acid)
Where °Bé = 145 - 145 or s.g. = 145
s.g. 145-°Bé
To use Table to correct the degrees Baumé (Bé) or specific gravity to the standard
temperature of 60° F (15° C), choose the °Bé or specific gravity reading closest to
that of the reading measured with the hydrometer.
· If the acid temperature is above 60° F (15° C), add the correction value
shown for every 1.0° F above 60 °F.
· If the acid temperature is below 60° F (15° C), subtract the correction
value shown for every 1.0° F below 60 °F.

Example.
Acid sample Hydrometer reading = 20.4 ° Bé
Acid Sample Temperature = 45 ° F
Correction Factor for 20 Bé = 0.04 per 1.0 °F
Temperature Difference from 60° F = 60 - 45
= 15 ° F
Temperature correction = 0.04 x 15
= 0.8 ° Bé
Temperature is below 60° F (subtract) = 20.4 - 0.8
Corrected °Bé at 60° F = 19.6 ° Bé
Acid Strength = 30.6 %
(From Figure 29, page 148)
Specific Gravity = 145
(145-19.6)
= 1.156 s.g.
Required Acid Strength = 15 % HCl
Specific Gravity = 1.075
(From Figure 29, page 148)
Raw acid required to mix = 1000 x 0.15 x 1.075
1000 gallons of 15% acid 0.306 x 1.156
= 161.25
0.3537
Gallons of Raw acid required = 455.9 gallons
(at 19.6° Bé)
Gallons of water required = 1000 - 455.9
= 544.1 gallons
Note that when obtaining the volume of water required for proper dilution of the raw
acid, that additives such as corrosion inhibitors, NE-Additives etc. are considered
part of the dilution water requirement. Therefore, all additive volume must be
subtracted from the volume of dilution water.
Corrosion Inhibitor = 2.0 gallons CI-Additive
(2.0 gallons/1000 gallons)
NE-Additive (Non-emulsifier) 0.6% = 1000 x 0.006
= 6.0 gallons
Total Additives = 6.0 + 2.0
= 8.0 gallons
Water required = 544.1 - 8.0
= 536.1 gallons
Final Mixing Requirements = 536.1 gallons Water
for 1000 gallons = 2.0 gallons CI-Additive
= 6.0 gallons NE-Additive
= 455.9 gallons Raw Acid
If the volume of acid required for a job, or the mixing tank is greater or less than
1000 gallons a simple factor can be calculated to convert the required volumes. For
example if the required volume was 750 gallons:
Volume factor = 750 ÷ 1000
= 0.75
New Mixing requirements:
Water (0.75 x 536.1) = 402.1 gallons
CI-Additive (0.75 x 2.0) = 1.5 gallons
NE-Additive (0.75 x 6.0) = 4.5 gallons
Raw Acid (0.75 x 455.9) = 341.9 gallons
Total = 750.0 gallons

21.2 Loading and Mixing HCl Acid.

When preparing for an acid job, it must be ensured that the acid should be uniform
throughout the tank. The raw acid, dilution water, and all additives must be
thoroughly mixed together. The best loading method is as follows:
1. Load the volume of water (freshwater whenever possible) less the
volume of additives needed.
Note : Water should always be added first to prevent excessive heat
being evolved and causing an explosion that can occur when water is
added to raw acid.
2. Add the required concentration of inhibitor and NE-Additives
separately. Do not mix any inhibitor or NE-Additives together or
combine any NE-Additives in the same container. Chemical reactions
can occur, and emulsion tests for proper additives would become
useless. Always add each additive separately.
3. Add the volume of raw stock acid required to the volume of water and
additives already in the tank. Keep the end of acid loading hose above
the fluid level in the acid tank to aid in mixing the water, additives and
acid.
4. When the required volume of liquid is placed in the tank additional
mixing is necessary by one of the following methods:
· Circulate the acid with a pump
· Mix the acid with a paddle or auger (Where available).
· Mix the acid by bubbling air for 10 to 15 minutes. This should not
be used where other methods are available. Oxygen may
become dissolved in the acid and create problems of corrosion
in the well.
Agitation during transportation (where acid is premixed in transportation tanks)
cannot be relied upon for properly mixing the treating solution.

21.3 Loading and Mixing HCl:HF Acid.

In sandstone stimulation, HF is normally used in combination with HCl. Mixtures of
the two acids may be prepared by dilution mixtures of the concentrated acids with
water or more commonly by the addition of fluoride salts such as ammonium
bifluoride with water and then raw stock acid. The fluoride salts dissolved in water
release HF when mixed with HCl. Fresh water should always be used for mixing
HCl:HF acid, and no field waters containing sulphate, calcium, sodium or potassium
ion should be used.
HF is poisonous, alone or in mixtures with HCl it should be handled with extreme
caution. Mixing proportions of HCl:HF at various strengths using ammonium
bifluoride can be found in the Engineering Handbook or in the Mixing Manual. Table
to Table can also be used for this purpose.
Note: The concentration of HCl required for mixing is always higher than the final
concentration desired as part of the HCl is consumed in changing the ammonium
bifluoride to HF.
Mixing HCl:HF requires rapid agitation or circulation of the water to facilitate the
dissolving of the ammonium bifluoride, and proper mixing of all acid ingredients.
The following procedure should be used when preparing HCl:HF.
1. Place the required volume of dilution water in the acid tank.
2. With agitation, add the remaining ingredients in the following order to
allow complete mixing or dissolving of the additives: corrosion
inhibitors, NE-Additives and ammonium bifluoride.
3. With agitation, add the required amount of raw acid and agitate until
uniform.

20. Quality Control.

1. Titrate the acid for strength. Refer to Table and Table for acceptable
limits.
2. Check the service company's load sheet to make sure that all the
additives are in the acid.
3. Agitate the acid on location prior to pumping to the well to ensure a
uniform acid blend.
4. Determine the maximum surface treating pressure allowable to prevent
fracturing of the formation.
5. Pressure test equipment to 5000 psi for 15 minutes
6. Maintain a constant injection rate during execution of the job. This will
allow real time or post job analysis of pressure data to be performed.
7. Do not allow the use of transports and pumps that are used for
anything other than acidizing services. This can lead to contamination
of the acid.
8. Conduct a safety meeting on location to ensure that everyone knows
what is to be done. Review all contingencies and safety procedures.
9. Take return acid samples each day until pH returns to that of the
formation brine. Have samples analyses for the following :
· pH.
· Acid strength.
· Surface tension.
· Amount, size and type of solids.
· Dissolved iron versus total iron.
· Presence of emulsions and organic sludges.
· Formation of precipitates.

19. Acid Jobs That Do Not Work.

Acid treatments which fail to stimulate production have usually been troubled by one
or more of the following problems :
1. Using acid on formations which are inadequately perforated, or on
sandstones which are not damaged.
2. Using the wrong type of acid to remove the damage.
3. Using dirty water in the preflush or overflush.
4. Lack of Hydrochloric Acid Preflush when using Hydrofluoric Acid with
sandstones.
5. Inadequate mud acid volume, minimum volume should be 50 gallons
per foot of pay.
6. Lack of immediate clean-up with mud acid, even with acid post-flush,
allows deposition of precipitates.
7. Failure to clean the acid or water tanks.
8. Additive misuse or overuse.
9. Fracturing sandstones with acid (except with very small volume
perforation breakdown treatments).

18. Treatment Evaluations.

1. Monitor the pressure response when the acid contacts the formation and
during injection.
· The pump rate should be held constant throughout the job.
If not, the pressure response record is useless.
· The pressure should never increase when injecting the acid.
If it does, the acid is damaging the formation.
· If a pressure increase is seen when acid first arrives at the formation, it
is probably plugging from solids that were present in the treating string.
(A pipe pickling treatment should have been performed).
· A gradual increase in treating pressure while acid is penetrating the
formation, indicates precipitation of reaction by-products.
· A slight increase in pressure should be seen when any diverter
contacts the formation.
If not, the diverter is probably ineffective.
2. Collect and analyse spent acid returns for:
· pH
· Iron content.
· Presence of emulsions.
· Amount, type and size of solids.
· Presence of reaction.
3. Compare productivity improvement with productivity potential.
Real-time computer analysis of formation skin damage is now possible by using
monitoring equipment to measure pressures and rates during the performance of the
job. This information is then transferred to a computer for calculation of bottom hole
pressure and various other parameters. With the computer program (FracRT) it is
possible to optimise the size of an acid job (or stages) during the actual execution,
as the skin damage is seen fall to a minimum. The program calculates and displays:
a. Damage Ratio Value
b. Paccaloni Style Injection Pressure vs. Injection Rate Plots.
Data collected during the job can be stored with the monitoring equipment (3600 or
3305 monitors) or on the computer and used for post job reporting and analysis.

17. Well Testing Prior to Acid Fracturing

Prior to performing a fracture stimulation, a series of tests should be conducted to
optimise the hydraulic fracture treatment design. Real time data recording and
analysis should bed used. Where possible, water inflatable packers should be used
when testing in open hole (less compressible than nitrogen). If possible down-hole
pressure and temperature transducers should be included for more accurate
measurement.

17.1 In Situ State of Stress Tests.

Used to determine which formations can contain a hydraulic fracture height growth.
Isolate the selected zone in open hole and inject small volume of fluid (10 gallons to
2 barrels freshwater) at low rate (2 GPM to 0.5 BPM) until breakdown of formation
occurs or a stabilised injection pressure is established. Record the bottom hole
pressure during the test. Repeat the test several times to overcome near well-bore
effects or until repeatable results are obtained. Carry out tests on each horizon in
the open hole section to determine barriers to fracture height propagation.

17.2 Step Rate Tests.

Used to determine breakdown and fracture extension pressures. Fracture extension
pressure is the stress that must be exerted on the rock to open a fracture and cause
it to grow. Pressure during the test is measured and plotted against time. Analysis of
the plot should show an inflection point in the rate of change of pressure which
indicates the pressure at which fracture extension took place. Where two inflection
points are seen at different pressures this indicates that the fracture has grown out
of zone. These should be consistent in magnitude with minimum in situ stresses.
Step rate tests can also be used to determine the magnitude of fracture tortuosity
effects in the near well-bore, by differentiating between measured friction pressures
and calculated perforation pressure drop, where no abrupt changes in net pressure
and closure pressure can take place.

17.3 Pump In/Flow Back Tests.

Used to measure fracture closure pressure. Fracture closure pressure is the
minimum horizontal stress in the rock less the fluid pressure in the fracture, and is
one of the determinants of fracture conductivity. Fluid is pumped into the well at
sufficient rate to cause fracture extension. The pumps are then shut down and the
well allowed to flow at a constant rate, with the pressure being plotted as a function
of time. An inflection point on this plot from concave upward to concave downward is
interpreted as the fracture closure pressure. This test should be repeated several
times to verify the closure pressure. Where two inflection points (closures) are seen
this can indicate the presence of natural fractures or a horizontal component ("T"
shape

17.4 Mini-Frac Treatments.

Used with actual fracturing fluid to measure fluid leak-off, fluid efficiency and gross
vertical fracture height. The gross vertical fracture height determines the treatment
size that must be pumped to achieve a given length and conductivity. Fracture fluid
efficiency is the volume of the created fracture at the termination of pumping divided
by the total volume of fluid pumped, and is a measure of fluid leak-off across the
fracture face. Since fracture volume cannot be physically measured, fracture fluid
efficiency and leak-off are derived from post fracturing pressure decay analysis.
Tests are usually conducted with using a volume ranging from 10% to 20% of the
planned fluid volume without proppant at the planned injection rate. Radio active
materials can be used to facilitate logging of the vertical fracture height.

15. Acid Systems and Additives for Fracturing.

Variables influence acid penetration before becoming spent include the volume acid
used, fluid-loss control, acid concentration, injection rate, formation temperature,
fracture width, and the composition of the formation.

15.1 Materials and Techniques for Acid Fluid-Loss Control

Controlling of fluid loss during acid fracturing of carbonate formations presents
problems unique to reactive fluids. Fluid-loss additives and gelling agents normally
used in non-reactive fracturing fluids are seldom stable in acid and are therefore
ineffective due to rapid degradation. This has led to the development of special acidstable
additives required for acid fracturing treatments.
In addition to the problem of degradation, as acid flows across the faces of carbonate
fracture, it constantly erodes the fracture surfaces, making it difficult for wall-building
fluids to form an effective filter cake.
Acid tends to selectively enlarge certain large pores and hairline fractures, which
results in "worm-holes" and channels perpendicular to the fracture faces. This further
complicates the problem of leakoff and causes the rate of acid fluid loss to increase
with time. Consequently, excessive fluid loss is generally considered to be the
controlling factor that limits fracture growth and fracture extension when fracturing low
to moderate-temperature carbonate formations.
Laboratory studies have shown that most acid fluid loss occurs from the worm-holes
rather than uniformly into the face of the core. Nierode and Kruk (1973) suggested
that acid fracturing fluids require much higher concentrations of fluid-loss additive for
effective fluid-loss control than do non-reactive fluids. They also concluded that the
only effective additive is a product composed of a mixture of oil-soluble resins. Oilsoluble
resins eliminate the possibility of conductivity impairment (in oil wells or gascondensate
wells) when compared to 100-mesh sand in the fracture. However, acid
fluid-loss additives have not been used extensively because of performance limitations
and high cost.

15.1.1 Viscous Pads.

One of the technique most commonly used for fluid-loss control involves the use of a
viscous pad preceding the acid. The pad is used to initiate the wide fracture and to
deposit a filter cake which will act as a barrier to fluid leakoff.
Low-viscosity linear gel pre-pads and high-viscosity cross-linked gel pads will also
increase fracture width, which improves acid penetration and fracture conductivity.
Multiple stages of a viscous pad, alternating with acid stages, will further improve acid
fluid-loss (to the worm-holes) control, and therefore, the efficiency of the treatment is
improved. This technique is widely used in acid fracturing treatments.

15.1.2 Foamed Fluids.

The use of foamed acid is one of the most effective methods for controlling acid fluid
loss. Fluid-loss control is further enhanced by the use of a viscous pad preceding the
foamed acid. However, foaming the acid does reduce the effective amount of acid
available for etching since there is less acid present per unit volume of fluid injected.
Therefore, 28% HCl should be used in preparing the foamed acid to maximise the
amount of acid available for fracture etching. The primary advantages of foamed acid
are its low fluid-loss and improved cleanup characteristics.
15.2 Materials and Techniques for Acid Spending Control.
Another major factor limiting penetration of live acid along fractures in carbonate
formations is the spending of the acid. The acid reacts constantly with fracture
surfaces and decreases in strength during its travel down the fracture. Once acid
strength falls below about 10% of the original concentration, it is no longer capable of
providing sufficient etching for acceptable fracture conductivity.
Higher acid concentrations increase penetration distance due to the greater amount of
available acid. The more concentrated acid has a higher viscosity and generates
more reaction products during spending, and both factors act to reduce the reaction
rate.

15.2.1 Viscous Fluids.

Fracture width also has a significant influence on penetration distance. An increase in
width results in an increase in acid penetration distance in both limestone and
dolomite. This demonstrates the importance of using a viscous pad fluid preceding
acid injection or the use of viscous acid, such as gelled acid or crosslinked acid. Highviscosity
cross-linked gels are more widely preferred as pad fluids than low-viscosity
linear gels since they have the advantage of creating wider fractures.
Temperature accelerates the reaction of acid on carbonate, an increase in
temperature decreases acid penetration. Acid penetration distance in limestone is
relatively less sensitive to temperature compared to that in dolomite. Pre-pads and/or
pad fluids that precede an acid injection treatment will cool the tubular goods, which
reduces corrosion, and cool the fracture, which reduces acid reaction rate and
enhances live acid penetration.
At temperatures above 200 °F (93 °C), certain acrylamide-base copolymers, of a type
commonly used to thicken acid, can be used in preparing pad fluids since they have
good acid and temperature stability. The presence of a high-viscosity pad in the
fracture promotes viscous fingering of the acid, which decreases the reactive surface
area to which the acid is exposed. This fingering also tends to increase the effective
conductivity of the etched fracture.

15.2.2 Chemical Retarders.

Retarders such as alkyl sulfonates, alkyl phosphonates, or alkyl amines reduce acid
reaction rates by forming a hydrophobic film on the carbonate surfaces. This films act
as a barrier which inhibits acid contact with the formation face and thus slows the acid
reaction with the formation. Some retarders slow the reaction rate by blanketing
carbonate surfaces with a thin layer of carbon dioxide foam which can be a stabilised
by the presence of foaming agents.

15.2.3 Organic Acids.

Acetic and formic acids are sometimes used as retarded acids since they react at a
much slower rate than hydrochloric acid at high temperatures. Their cost per unit
dissolving power is higher than HCl, however, they are less corrosive, and therefore,
can be inhibited at high temperatures for long periods of time. Inhibited acetic acid
does not attack chrome plating, and small amount of formic acid in HCl may serve as
inhibitor aid and reduce HCl acid corrosion.
15.3 Materials and Techniques for Improved Fracture Conductivity.
For an acid fracturing treatment to be effective, the wall of an acidized fracture must
be etched sufficiently that conductive channels remain after the treatment. If the
fracture faces are etched uniformly, the conductivity after the fracture closure is very
low. Fortunately, several factors promote uneven etching of the fracture faces, such as
mineral composition. Acid reacts with different minerals at different rates resulting in
non-uniform etching.
The rate of acid reaction is also greatly affected by the acid flow velocity. Faster
reaction rate at high flow rate results in the erosion of the fracture faces in areas of
more rapid acid flow and creates erosion patterns. Once these channels develop, the
acid tends to flow selectively along a few of the larger channels and most of the
fracture faces remain relatively un-etched. This not only promotes increased fracture
conductivity, but also increases live acid penetration.
Rock strength and closure stress are important factors affecting ultimate fracture
conductivity. Crushing of fracture faces can result in loss of conductivity if the rock is
too soft or closure stress is too high. Soft chalk formations are very prone to this
problem.
The injection of a viscous pad fluid ahead of the acid is the most commonly used
technique to maximise fracture conductivity. The presence of higher viscosity pad fluid
promotes viscous fingering of the thinner acid which follows. This selective acid flow
increases penetration distance and tends to create deep channels with good

14. Acid Fracturing Concepts and Design.

14.1 Introduction to Hydraulic Fracturing.

Hydraulic fracturing is a process of creating a fracture by the injection of fluids into a
formation at a pressure higher than the parting pressure of the formation. Injection
rate has to be high enough and formation permeability to the injected fluid has to be
low enough that fluid loss is not excessive in which pressure can build up and
sufficient to fracture the formation or to open existing natural fractures.
Normally, proppants are injected with fluids to prop the fracture open in sandstone
formations, and acids are used to etch the fracture faces making them uneven to
prevent them from completely closing in carbonate formations. The propped or etched
fracture will act as high conductivity passage for fluids to move to the wellbore with
much ease.

Hydraulic fracturing has been used to accomplish four basic jobs:
1. Overcome wellbore damage (high permeability formations).
2. Create deep-penetrating fracture into reservoir to improve the
productivity or injectivity of a well.
3. Aid in secondary recovery operation.
4. Assist in the injection or disposal of brine and industrial waste material.

14.2 Candidate Selection.
All carbonate formations can be candidates for Fracture Acidizing treatments.
However, poorly performing wells due to low reservoir permeability and/or wells with
restriction due to damage near the wellbore are more suitable as acid fracturing
candidates.
Factors affecting well's productivity are:
1. Low reservoir permeability.
2. Damage in near-wellbore region.
3. Inefficient production equipment.
Well's productivity can be evaluated by:
1. Offset well comparison.
2. Production history curves.
3. Pressure transient analyses (buildup, draw-down, etc.).
4. Producing well system analysis.
5. List of damage indicators (well's report).
14.3 Acid-Fracturing Design Concepts.
In low to moderate-temperature wells, acid fluid-loss control may be the most
important consideration. In high temperature wells, effective acid penetration distance
often is limited by rapid spending, and retarded acid should be considered. In soft
formation, such as chalks, the treatment should be designed specifically to maximise
fracture conductivity.
As the acid flows along the fracture, portions of the fracture faces are dissolved. Since
flowing acid tends to etch in a non-uniform manner to create conductive channels
which usually remain open when the pumping pressure is released and the fracture
closes. The effectiveness of the acid fracturing treatment is largely determined by the
length of the etched fracture which is controlled by the volume of the acid used, acid
reaction rate, and the acid fluid loss from the fracture into the formation. When
designing an acid fracturing treatment, all factors affecting the success of the
treatment must be considered:
· Pre-treatment formation evaluation.
· Production system analysis.
· Rock mechanics and fracture geometry.
· Rock solubility (reservoir temperature).
· Acid penetration.
· Acid and additives.
· Lab tests.
The following goals are expected after an acid fracturing treatment:

· The fracture propagated across the pay zone.
· The acid dissolved a large amount of reservoir rock.
· The acid etched the fracture faces unevenly to create channels with
sufficient etched length and width that contained high conductivity after
the fracture closed.
· Rapid and complete recovery of the treating fluids.
· Large fold of increase at a reasonable cost
14.4 Acid Fracturing Design Considerations.
14.4.1 Pre-treatment Formation Evaluation
a. Geologic considerations.
· Lithology: Carbonate (limestone, dolomite).
· Drainage area
xf/re ratio.
Fault patterns.
· Well logs.
Porosity.
Net pay.
Water saturation.
Mechanical properties. (Young's modulus, Poisson's ratio).
Fracture height (temperature logs).
· Core analysis.
· Conventional core analysis.
Porosity.
Permeability (5 to 100 folds high).
Compatibility with stimulation fluids.
· Special core analysis (in-situ).
Permeability.
Porosity.
Relative permeability.
Capillary pressure.
· Oriented coring.

Natural fractures direction.
In-situ stress in three directions.
Fracture azimuth.
b. Well testing considerations.
· In-situ reservoir permeability.
· Skin factor.
· Reservoir pressure.
· Reservoir temperature.
· Reservoir fluid properties.
14.4.2 Production system analysis.
· IPR (flow in reservoir).
· Pressure drop across completion.
· Pressure drop in production string.
14.4.3 Rock mechanics and Fracture Geometry
a. In-situ stress:
· Fracture extension pressure
· Closure pressure
b. Basic rock mechanics and properties:
· Young's modulus (E) ( 8 to 13 x 106 psi for limestone and
dolomite)
· Poisson's ratio (u) ( 0.15 to 0.27 for limestone and dolomite)
c. Fracture geometry:
· Fracture height:
Upper and lower barriers (stress contrast)
Pump rate.
· Fracture models:
KGD.
PKN.
Radial.
· Fracture half-length:
Injection rate.

Leak-off rate.
Fracture height and width.
Volume pumped ($).
· Fracture width:
Formation hardness (Young's modulus).
Fluid viscosity.
· Fracture azimuth
Perpendicular to minimum compressive principal in-situ stress.
14.4.4 Rock Solubility
· Greater than 70%.
· Limestones, dolomites, chalks.
· No insoluble reaction by-products.
14.4.5 Acid Penetration.
· Acid injection rate.
· Leak-off rate (worm-holes).
· Acid concentration.
· Formation temperature.
· Fracture width.
· Reaction rate.
· Composition of the formation.
· Effect of viscous fingering.
· Cost $ (volume -up to a certain point).

13. Job Design Considerations.

13.1 Spotting Fluids in the Wellbore.

Special down hole problems may make it necessary to completely immerse a
specific area of the wellbore with acid, for example:

• · Removing permeability damage caused by mud filter cake or scale deposits on the formation face or in perforation tunnels.
• · Freeing stuck pipe.
• · Dissolving junk in the hole.

When spotting acid in the annulus to solve these problems, the fluid columns in the
tubing and in the casing must be either balanced so that no pressure differential
exists, or enough pressure must be held at the surface to balance out the difference
in hydrostatic heads.

13.1.1 Balanced Columns Method.

When it is necessary to balance the fluid columns, the height to be filled with acid
and or solvent must be determined and the volume of fluid calculated. When this
volume has been pumped into the well, just enough flush and displacement fluid
should be pumped to balance the fluid columns, that is, that the top of the acid and
or solvent is at the same level both inside and outside the treating string (if the hole
is standing full).

13.1.2 Unbalanced Columns Method.

When the bottom of the tubing is below the treating area, enough flush and
displacement fluid must be pumped to displace the acid down the tubing and up the
annulus to the desired location. Normally this spotting method results in an
unbalanced condition between the volumes in the tubing and casing. To prevent
further fluid movement towards equalisation enough pressure must be held on the
tubing at surface to balance out the difference in hydrostatic heads.
Relatively small volumes of fluid are used in spotting pickling and solvent soak
treatments (250 to 1000 gallons). The precise volume used depends upon the
nature of the treatment and the length of section to be filled.
Acid treating solutions typically employed in pickling treatments are NE-Type Acids
which normally consist of inhibited hydrochloric acid with the necessary demulsifying
and low surface tension surfactants. Other acid systems used include Mud Sol
acids, Clean-up and MMR acids, One Shot acid, Sequestering, Organic acids and

The maximum surface treating pressure at the maximum allowable pump rate is
calculated as follows:

Maximum Surface Treating Pressure =
(Fracture Gradient x TVD) + Friction Pressure - Hydrostatic - 300 psi
Note : 300 psi is an arbitrary safety factor to assure that the reservoir will not be
fractured.

In many sandstone matrix stimulation treatments, the initial injection rates will be
substantially less than those predicted when using the above equation and Figure
21, when pumping at the maximum allowable treating pressure. This is caused by
permeability damage in the near wellbore area. Once this damage is removed by the
acid , the predicted and actual injection rates will be close in value.

probably will respond better to a proppant fracturing treatment, than to a sandstone
matrix treatment, since the treating time would be extremely long for matrix
stimulation.
Example :
Well Depth (TVD) 9500 ft
Permeability 100 md
Formation Thickness (MD) 10 feet
Fracture Gradient 0.65 psi/foot
Fluid in Hole 15%:4.0% HCl:HF
Hydrostatic Pressure Gradient 0.476 psi/foot
Formation Pore Pressure 4500 psi
Tubing Size 2-3/8 inch
Formation Fracture Pressure = Fracture Gradient x Depth (TVD)
= 0.65 x 9500
= 6170 psi
Hydrostatic Pressure = Hyd. Pressure Gradient x Depth (T.V.D.)
= 0.476 x 9500
= 4522 psi
Differential Pressure = (Formation Fracture Pressure) -
Formation Pore Pressure - 300 psi
= 6170 - 4500 - 300
= 1370 psi (DP)
Formation Flow Capacity = Formation Thickness (MD) x Permeability
= 10 x 100
= 1000 md. ft.
Maximum Injection Rate = 2.3 Barrels Per Minute.
(From Figure 21)
Friction Pressure = Friction Pressure From Figures x
(From
Figure 17, page 100) Specific Gravity x Depth (MD)/1000
= 90 x 1.08 x 9500/1000
= 922 psi.
Surface Treating Pressure = (Fracture Gradient x TVD) + Friction
Pressure - Hydrostatic - 300 psi
= 6170 + 922 - 4522 -300 psi
= 2270 psi

Therefore maximum surface treating pressure is 2270 psi at a maximum treating
rate of 2.3 barrels per minute.

13.5 Shut-In Times.

Shut-in time is the length of time a well is closed in after a stimulation treatment is
completed, before flow back is initiated. This time is determined by the type of acid
used and by downhole factors such as formation type, bottom hole temperature and
bottom hole pressure.
After an acid solution has been neutralised by reaction with the formation, it is no
longer a stimulation fluid. However it may become harmful to the formation
permeability if allowed to remain downhole.

13.5.1 Hydrochloric Acid with Limestone.

Hydrochloric acid reacts so rapidly with limestone that it is essentially neutralised by
the time the acid has been completely placed. This generally holds true at all ranges
of temperature and pressure. Since limestone formations incorporate varying
amounts of insoluble materials that can plug permeability, if allowed to come to rest,
it is important to remove the neutralised hydrochloric acid as soon as it is spent.
Shut-in times with such formations is zero.

13.5.2 Retarded or Emulsified Acid.

When chemically retarded acids such as the Sta-Live systems, and emulsified acids
such as SRA-3 are used, the reaction time of the acid can exceed the displacement
time. Here a shut-in time of one to two hours is recommended for maximum
stimulation. The shut-in time may be extended where there is sufficient bottom hole
pressure to promote rapid clean-up
.
13.5.3 Organic Acid and HCl Acid Mixtures.

Mixtures of acetic or formic acid with hydrochloric acid delay the time required for
complete spending of the acid mixture and thus require a shut-in time.

13.5.4 Gelled and Cross-Linked Acid Systems.

When Gelled or Cross-linked acids are used the reaction time of the acid can
exceed the displacement time. In these cases, longer shut-in times are required to
allow time for the acid to fully spend and the viscosity to be reduced to allow easy
flow-back.

12. Viscosity and Friction Pressure

12.1 Viscosity.

Since acids systems have a water base, their viscosity is about 1.0 centipoise and
they behave as Newtonian fluids with easily predicted flow properties. However,
when they are altered by adding gelling agents or polymers, or when combined with
hydrocarbons to form emulsions, they become Non-Newtonian and more complex in
behaviour. Generally, low viscosity Newtonian acids are used in matrix acidizing,
whilst viscous Non-Newtonian treating solutions are used when acidizing within
natural fractures and in fracture acidizing.
Viscosity is defined as the property of a fluid that resists the force tending to cause
the fluid to flow. The common oil field unit of measure for viscosity is the centipoise
(cp), which is expressed in centimetre-gram-seconds.

12.2 Newtonian Fluids.

A fluid undergoes continuous deformation when subjected to a shear stress, such as
when it is pumped. Some fluids follow a standard pattern of behaviour under shear
stress (i.e. when subjected to pump pressure). Specifically this standard pattern is
that shear stress is directly proportional to the rate of shear (Figure 16).
A fluid which behaves in this manner is classified as a Newtonian fluid and its flow
properties can easily be predicted from a measurement of the fluids viscosity.
Viscosity is the single rheological property needed for the flow calculations of a
Newtonian fluid.
Common examples of Newtonian fluids are water, most oils and most other liquids
that do not contain solid particles in suspension.



12.3 Non-Newtonian Fluids.

In some specialised acid treating solutions, flow properties are changed by adding
synthetic or natural polymers, or by combining the acid with a hydrocarbon such as
kerosene to form a viscous emulsion (as in BJ Services Emulsified Acid or SRA-3
acid).
These fluids are Non-Newtonian which may be defined as materials which do not
conform to direct proportionality between shear stress and shear rate (Figure 17)
Consequently, Non-Newtonian fluids do not exhibit a simple viscosity and their
consistency changes as their flow rate changes. In acid stimulation, flow rate is
related to pumping rate, pipe size, size and number of perforations and other
factors



In general, Non-Newtonian fluids become less "viscous" at higher pump rates (shear
thinning) and are often unstable at these rates (turbulence). In effect the apparent
viscosity of the fluid becomes less as it is pumped faster (Figure 18).



The effects of viscosity must be considered when designing acid treatments. In
matrix acidizing, where injection rates are low, the viscosity of the treating solution
should be kept to a minimum to prevent excessive pressures during placement and
to aid in the clean-up of the treatment when the job is complete.
On the other hand , a viscous acid has advantages when stimulating within natural
fractures or when fracture acidizing for deeper penetration. In these treatments the
higher viscosity helps to control fluid leak-off, increasing the efficiency of the acid as
a fracturing fluid.