1. If there are no guidelines being followed for pipe dope application, use
50 gallons of xylene per 1000 feet of tubing.
2. Use 100 gallons of 15% HCl per 1000 ft of tubing if the tubing is new or
has been used for water injection.
3. Circulate the xylene ahead of the acid down the tubing and out of the
annulus.
4. If the reservoir pressure is too low for circulation, foam the acid and
displacement fluid.
5. A pickling treatment would not be necessary if a concentric treating
string is used, or if a replacement treating string is used.
6. Repeating pickling treatments on production strings is unnecessary. It
may be necessary on injection wells.
7. If a pickling treatment cannot be done, highly sequester the HCl
preflush or use a highly sequestered acid ahead of the preflush.
8. Alternatively, if a pickling treatment cannot be done, a spearhead of
xylene dispersed in highly sequestered HCl will address any pipe dope
accumulations.
10.2 Preflushes.
Preflushes are often used ahead of an acid treating solution, to prepare or condition
the formation, so that it will accept the acid in the most favourable sections and
without creating damage.
Several acid systems have been developed where preflushes are required. The
Spearhead Acid Control (SAC) technique employs an aqueous spearhead to create
fractures and place a temporary protective film on the face of the fractures. This film
restricts leak-off and aids in the deep penetration of live acid.
Selective acidizing formulations (SAF) employ a specially treated kerosene or diesel
oil preflush. The preflush allows the formation to react with acid in the oil producing
interval whilst restricting the invasion of acid into the water producing strata.
In stimulating sandstone formations, it is generally recommended that the
hydrochloric and hydrofluoric acid mixtures be preceded by a preflush of
hydrochloric acid commonly at a concentration of 15% HCl (See Figure 15). This
preflush serves two purposes:
- · It dissolves carbonates in the formation so that the following hydrofluoric acid will remain active to dissolve the clays and silicates.
- · It removes calcium compounds, minimising the formation of insoluble precipitates.
Figure 15 can be used to calculate the required volume of 15% HCl Preflush
required for a sandstone stimulation based on formation solubility and treating
radius.
Example :
10 feet of pay zone with a solubility in HCl of 5.0%.
Required treating radius is 5 feet.
From Figure 15:
Gallons of 15% HCl required per foot of pay = 310 gallons
For 10 feet of pay = 310 x 10
Volume of preflush required = 3100 gallons of 15% HC
Other preflushes include:
- · Aromatic solvents and diesel for removal of hydrocarbon deposits or as carrier fluids for acid retarders and anti-sludging agents.
- · Mutual solvents and alcohols, for the prevention and removal of water blocks, improved clean-up and water-wetting, and where clay minerals are present.
- · Hydrochloric acid for the prevention of precipitation of acidizing byproducts with hydrofluoric acid (see section 3.2.2., page 24).
1. When acidizing sandstones, iron control additives are most critical here
because iron bearing minerals are highly soluble in HCl. The ensuing
mud acid treatment will come into contact with less iron because these
minerals will have been removed (Ferrotrol Agents).
2. Iron control additives are also important because the preflush will
remove any iron scales from the tubulars and carry the into the
formation.
3. If asphaltenes are present, it is important to use Anti-sludging additives
in the preflush (NE-32, ASA-251, MSS-100). This is the fluid that will
come into contact and mix with the crude oil in the greatest volumes. It
is therefore more likely to cause a problem with asphaltenes
.
4. A solvent wash ahead of the HCl preflush may be necessary to control
sludging. (Xylene, Toluene, Diesel).
5. If carbonate scales have been deposited in the matrix, the preflush
should be a solvent/acid dispersion (One Shot Acid). If the scale is the
only damage mechanism involved, mud acid should not be used.
6. Use a preflush of hydrochloric acid when treating sandstones with mud
acid (hydrofluoric acid). The preflush prevents brine contact with the
mud acid and potential precipitation of by-products.
7. As a general rule of thumb, the HCl preflush volume should be half the
volume of the mud acid treatment, if the HCl solubility is less than
10.0%. If the HCl Solubility is from 10.0% to 18.0%, the volume should
be calculated for removal of all HCl soluble material within a two foot
radius of the wellbore. (Refer to Table 14 page 67).
10.3 Diverting Treatment Options and Design Criteria.
To obtain the best results from most acid stimulation jobs it is important that the acid
be distributed over the entire production or injection interval. Without some method
of diverting an acid treating solution, most of the acid will enter the most permeable,
and often least productive sections of the formation, leaving parts of the producing
zone un-stimulated. The following are guidelines for diverting:
1. Use mechanical diverting whenever possible.
2. Diverting before a gravel pack should utilise sand and HEC polymer
only.
- · Divide the zone into treatment stages.
stages.
If the zone is greater than 80 feet, base the treatment on 30 ft
stages.
- · Sand concentration should be 1.0 to 2.0 pounds per gallon.
perforations. Re-completions will require 25 pounds of sand per
foot of perforations.
- · When the diverter stage reaches the cross-over tool, rate should be increased to 8.33 ft/second.
Example : 60 ft Zone New Completion.
Step 1 : 1000 gallons HCl
Step 2 : 2000 gallons HCl:HF
Step 3 : 3000 gallons 3% Ammonium Chloride
Step 4 : 6 barrels HEC containing 250 lbs 40-60 sand
Step 5 : Repeat 1, 2, 3, 4
Step 6 : Repeat 1, 2, 3
Step 7 : Pump Gravel Pack System.
Diverting all other conditions.
General Best Results:
Oil wells : Oil soluble Resin.
Gas wells : 65 Quality Foam.
10.3.1 Foam Diverting Techniques.
When using foam diverting techniques, the first stage of the acid solution is injected
into the formation as in a conventional acidizing job. This is followed by an aqueous
solution of a foam producing surfactant which is displaced into the formation with a
compressed gas such as carbon dioxide or nitrogen. Parts of this surfactant adheres
to the rock, both in fractures and within the matrix. When this retained solution
mingles with and is agitated by the following stream of nitrogen, foam is formed.
As the procedure continues and additional foam is generated, its resistance to
continued movement through fractures and rock matrix increases until the pressure
required to sustain additional flow is greater than the pressure required to break
down another section of the interval. At this point the rate of injection into the original
section is reduced, and the newly opened section accepts the next portion of acid.
This procedure is repeated as many times as necessary to stimulate the entire
producing zone.
Alternatively, compressed gas is injected into the aqueous fluid stream containing
the foaming surfactant at surface and foam is created. As the foam follows the acid
pad into the formation the effects of multiple phase flow (liquid and gas) creates
resistance to flow and results higher pressures. The higher pressure breaks down
further sections of formation and the newly opened section accepts the next portion
of acid.
The advantages of foam diverting techniques over conventional diverting methods
using solid blocking materials are as follows:
- · Foam produces a block within the formation rather than a solid block at the well bore. It contains no solid particles thus reducing potential for damage to permeability.
- · The compressed gas aids in cleaning silt and undissolved particles from the formation and in the clean-up of fluids.
- · Adaptability to a wide range of temperatures 70 °F to 350 °F.
Since acidizing solutions preferentially enter water bearing formations, increased
production of water is an unwelcome by-product of many stimulation jobs. When the
water contact is in the perforated interval, then selective acidizing should be
employed to prevent accelerated water production after treatment. When applying
the selective acidizing technique, the acid is diverted into the oil bearing zone,
resulting in increased oil production, whilst water production remains the same.
The principal component of the SAF (Selective Acidizing Formulation) system is a
specially treated kerosene or diesel oil (not crude oil) preflush, usually a minimum of
500 gallons in volume. This preflush is injected ahead of a conventional acid
stimulation treatment. Preceding the preflush is a spearhead volume of 5.0 barrels of
clean, water free crude oil, kerosene, or diesel oil. Between the preflush and the
conventional acid is a pad volume of 2.0 to 5.0 barrels of clean water free crude oil,
kerosene or diesel oil. The spearhead and the pad prevent the preflush from
contacting any water based fluids and precipitating prematurely, prior to entering the
water bearing zone.
With the pay zone isolated by packers or bridge plugs, the SAF preflush enters the
formation as a low viscosity fluid. Upon contact with any water in the formation, the
preflush immediately forms an oil soluble precipitate at the water-SAF interface. This
oil soluble precipitate will partially penetrate and effectively plug the permeability of
the water producing strata. With this strata effectively plugged, the acid treatment is
diverted into the oil producing strata. When the treatment is complete, the well is
shut in and produced in the conventional manner. SAF systems can be used with
any type of acid, with any formation and in all wells except dry gas wells.
10.5 Post-Flush Design Considerations.
1. Use Ammonium Chloride at a concentration that is compatible with the
formation (2.0 to 4.0%).
2. If damage from precipitation of reaction by-products is suspected,
consider using 3.0% HCl as the post-flush for greater pH control.
3. Use 5.0% to 10% mutual solvent for wettability (INFLO-40). This is
most important when high concentrations of corrosion inhibitor have
been used.
4. The post-flush prevents the mixing of the displacement fluid (brine)
with the spent HCl : HF acid.
5. Use sufficient volume to over-displace the acid treatment to between
4.0 and 5.0 feet radially.
10.6 Over-flushing.
Over-flushing is the displacement of the acid treating solution with more than the
volume of fluid required to clear the tubing and casing. This procedure is sometimes
desirable and often necessary.
For example, when using retarded acid systems, the reaction time can be longer
than the injection time. Greater penetration may then be obtained by over displacing
the acid. The exact amount of over-flush used is related to the reaction time of the
acid, therefore, for maximum penetration, just enough overflush should be used to
keep the acid moving within the formation until it spends.
Occasionally it is not convenient to flow back the well immediately after acidizing. In
such cases, the treating fluid should be over-flushed with water or brine to reduce
the contact time of live acid on the tubing and casing.
An over-flush with hydrochloric acid is recommended in injection wells that are
stimulated with mixtures of hydrochloric and hydrofluoric acids. The over-flush helps
prevent plugging precipitates from forming until the acid treatment has been
displaced away from the critical region of the near well-bore (4.0 to 5.0 feet), thus
reducing the effects of this damage.
10.7 Retarded Acid Systems.
Retarder techniques are used to improve the effectiveness of acidizing treatments
by slowing the rate of reaction with the formation to achieve placement of live acid
deep into the formation. These treatments are normally considered in fracture
acidizing of limestone or dolomite formations. Six types of retarded acid systems are
available :
- · Emulsified acid.
- · Chemically retarded acid.
- · Organic acids.
- · Mixtures of organic acid and hydrochloric acid.
- · Gelled Acid.
- · Cross-linked Acid.
In order to effectively retard an acid system, an understanding of the factors
effecting the rate of reaction of an acid must be considered.
10.7.1 Reaction Rate Considerations.
The rate of reaction between an acid and a soluble formation depends primarily
upon the following factors:
- · Temperature of the formation during treatment.
- · Pressure within formation during treatment.
- · Type and concentration of the acid used.
- · The kind of formation with which the acid reacts and the purity of the formation.
formation surface area and the rate of shear (agitation) within the acid. The rate of
shear through a fracture depends on the velocity of the acid and the width of the
fracture.
Higher reaction rates may be employed to remove local well-bore damage, but a
slower reaction is preferred for fracture acidizing. The intrinsic reaction rate of an
acid cannot be changed, but it can be effectively controlled by emulsifying the acid in
oil or by interposing a film of oil between the acid and the formation such as in Super
retarded acid (SRA) systems.
The effectiveness of an acidizing treatment, to improve the production from any well,
depends essentially on the ability of the acid to reduce resistance to flow of the oil or
gas from the formation to the well-bore.
Acid treatments may over come or reduce many kinds of flow resistance found in
production or injection wells such as:
- · Naturally low permeability of the formation.
- · Limited conductivity of natural and induced fractures.
- · Formation damage caused by drilling mud or clay swelling. Reduced
- permeability in the vicinity of the well bore due to formation of scale
- deposits.
- · Reduction of effective tubing diameter resulting from the accumulation
- of scales.
The rate at which acid reacts with the impeding material becomes more important as
the acid's distance from the wellbore increases. A high reaction rate is desirable for
removing scale, which is usually formed at or near the wellbore. However, when
using fracturing pressures to treat a formation, a slower reaction rate is preferred in
order to enable deep penetration of the live acid. The increase in production from
induced fractures or the etching of natural fractures by acid depends upon three
factors :
- · Increased permeability.
- · Length of zone of increased permeability from the wellbore.
- · Width of resulting fractures.
live acid accomplishes little. If the fracture faces are etched effectively, and the zone
adjacent to the fractures has increased permeability, deeper penetration into the
available drainage area can raise the “production increase ratio” significantly.
However, it should be noted that the "rate" of improvement decreases with depth of
penetration.
10.7.2 Measuring Reaction.
Generally the rate of reaction between limestone and acid is measured by the rate of
change in the amount of available acid. In conducting a laboratory test, small
samples of acid are drawn from the reaction vessel and titrated. The fraction of
available acid consumed in the reaction is then plotted against elapsed reaction
time. Since the basic rate of reaction on a given formation at a particular
temperature and pressure depends upon the acid concentration, the last part of the
reaction can be much slower than the first part. For practical reasons, the end of
reaction is taken as the time at which 90% of the acid has reacted rather than 100%.
(See Figure 2 to Figure 5 on pages 16 through 19).
10.7.3 Controlling Reaction Time.
The reaction rate of the acid on the formation can be retarded by changing the
properties of the acid treatment. Acid systems can be retarded by chemical and
physical means or by mixing HCl with organic acid.
Some acids, particularly the organic acids, react more slowly than hydrochloric acid.
As there is no known way to change the intrinsic rate of reaction between a
particular acid and a soluble rock, it is necessary to introduce "interfering" agents to
reduce the rate. This is accomplished by reducing the effective area of contact
between the acid and the soluble formation by:
- · Emulsifying the acid in oil
- · Interposing an oil film between the acid and the formation.(Chemically Retarded Acids)
- · Gelling or Cross-linking the acid.
The effective reaction rate of some acids may be reduced by dissolving them in nonpolar
solvents (such as the lower alcohols) or in mixtures of this type of solvent and
water. This method is not in general use because of the cost of non polar solvents.
Rate of reaction is related to the rate of diffusion of hydrogen ions and reaction
products through the solvent containing them, therefore, increasing the viscosity of
the solvent decreases the reaction rate (Gelled and Cross-linked Acids). This may
be accomplished by means of certain organic gelling agents or by the use of
inorganic salts. Some surfactants also act to retard the effective reaction rate.
10.8 Emulsified Acid.
Physically retarding HCl acid by emulsifying the acid with kerosene or diesel. This
method accomplishes retardation by placing an external phase of hydrocarbon
around droplets of the acid thus reducing the effective contact area with the
formation. This method is by far the best means of retardation.
Emulsified Acid of acid reacts slowly with the formation, permitting deep penetration.
It is generally used at fracturing pressures, where, it cleans out and enlarges existing
fissures and also creates new ones. Because of its viscosity, emulsified acid carries
sand effectively and can also be used as a fracturing fluid.
In an emulsion of acid and kerosene or diesel oil, the droplets of acid are
surrounded by a continuous body of hydrocarbon. This decreases the effective area
of contact so that less acid is reacting upon the formation at any moment in time.
When the acid at the surface of the formation has reacted, it must be replaced by
live acid brought there by diffusion and convection. These processes take place
more slowly through hydrocarbon than they would through a "more fluid" medium,
thus reducing the reaction rate of the acid.
An emulsion of one liquid in another is created by bringing the two liquids together
and physically breaking up the one to be dispersed by mechanical agitation. In well
stimulation, stable emulsions are relatively simple to produce. The continuous phase
(usually kerosene or diesel fuel) is placed in a tank with a stabilising surfactant that
may also serve to partly control the extent of retardation.
The acid is then jetted into the tank through a hose, producing an initial emulsion
that is relatively fluid. Further dispersion of the acid is accomplished by circulating
the emulsion through a pump and back to the tank. The final product has the
appearance of a rather thin mayonnaise. The viscosity of the emulsion increases as
the acid droplets are made smaller by agitation and as the proportion of acid is
increased.
BJ Services Emulsified Acid System and SRA-3 are emulsified acids used for
fracture stimulation of carbonate formations. Both have a very slow reaction rate with
medium to high viscosity for leak-off control.
10.9 Chemically Retarded Acid.
Chemically retarding Hydrochloric acid is accomplished by the addition of special
surfactants designed to give a retarded reaction rate on low or high temperature
carbonates.
Sta-Live acids are chemically retarded acids which have low viscosity (about the
same as that for regular hydrochloric acid). This type of system is recommended for
treatments where the following apply:
- · Highly soluble formations.
- · Wells with high bottom hole temperatures.
- · Where large treatment volumes are required.
- · Where low injection rates are indicated (matrix acidizing).
Super retarded acid systems are a mixture of hydrocarbon oil (kerosene or diesel),
15% hydrochloric acid, surfactant and corrosion inhibitor. The primary function of the
surfactant is to stabilise a film of oil at the interface between the acid and formation.
This film acts as a two way barrier through which the acid molecules migrate to the
formation and through which the molecules of the acid reaction products in turn pass
back to the body of the acid.
Sta-Live acid systems are chemically retarded systems designed for use with
carbonate formations. These systems retard acid reaction by the chemical
adsorption of a surfactant (SLA-48) on the formation face which delays the contact
with the acid. These acids have low surface tension and viscosity and are generally
used to treat dry gas wells where the use of hydrocarbon preflushes or acid mixtures
have proven detrimental to production.
10.10 Organic Retarded Acids.
Only two organic acids, acetic and formic, have been used to any extent in well
stimulation. Both these acids have the characteristic of relatively low reaction rates
without the addition of additives. However, due to the additional cost neither has
been widely used as a replacement for hydrochloric acid systems.
Acetic Acid.
Acetic acid is usually used in the range of 5.0% to 20% concentration . In this range
1.7 gallons of acetic acid will dissolve the equivalent of 1.0 gallon of hydrochloric
acid. Acetic acid has the advantage of low corrosion rates with steel, and at
temperatures below 200 °F (93 °C), no inhibitor is required where contact with the
pipe is less than three hours. With inhibitors, acetic acid is used as a breakdown
fluid and can be placed in the well prior to perforating. The low corrosion rate without
the need for inhibitors allows the use of this acid for stimulating water wells for
domestic consumption.
Formic Acid.
The properties of formic acid are generally between those of acetic and hydrochloric
acids of the same strength. Normally, formic acid is used in concentrations of 10%
or less due to the low solubility of reaction products formed. At a 10% concentration,
1.3 gallons of formic acid are required to dissolve the same quantity of carbonate as
1.0 gallon of 10% hydrochloric acid.
10.10.1 Mixtures of Organic acid and Hydrochloric acid.
Mixtures of acetic and hydrochloric acid (Super Sol, EQH acids) are used as a
compromise between the greater dissolving capacity of HCl and the slow reaction of
acetic acid. These delayed reaction acids are normally used in fixed ratios of
Hydrochloric to acetic acid (9:1, 8:2, 7:3, and 5:5). A ratio of 9:1 hydrochloric:acetic
acid is the fastest reacting of these mixtures. The dissolving ability of each
formulation is approximately equal to that of 15% HCl.
These acid mixtures provide retardation, with less corrosion at higher temperatures
(above 200 °F (93°C)), and have the additional benefit that they will sequester
dissolved iron after the acid spends in hot carbonate formations.
Formic acid is also used with HCl for high temperature applications where a slow
rate of reaction is required. When extremely high temperatures are encountered
mixtures of formic and acetic can be used.
10.11 Spearhead Acid Control.
Deeper penetration of acid can also be accomplished by using the technique of
"spearhead acid control" (SAC). With this technique, a fracturing fluid is pumped
ahead of the acid treatment to achieve the following:
· Generate wider fractures.
· Control leak-off by laying down some sort of filter cake on the fracture
faces.
· To cool down the formation.
These actions help to slow down the reaction rate and increase the penetration of
the acid treatment.
10.12 Gelled Acid.
Gelled Acid is used in fracture treatments of limestone formations. The viscosity
serves to retard the acid, reduce friction, reduce fluid loss and provide etching
properties. Wider fractures are created using this type of fluid improving the etching
pattern. Gelled acid, foamed with nitrogen can generate extremely stable foams and
further increase their retarded nature.
An additional, important aspect of Gelled Acid systems is their fines suspending
properties. Where “dirty” limestones produce large quantities of fines during
acidizing, these can plug the fracture network and reduce the conductivity of the
fracture. Using gelled acid systems allows these fines to be produced back from the
formation, suspended in the spent acid.
10.13 Cross-Linked Acid.
High viscosity cross-linked gelled acid systems have excellent retarding properties
for deep penetration into the formation, and are primarily used in the fracture
treatment of limestone formations. As with gelled acids, these fluids have excellent
leak-off and friction properties, foam forming and fines suspension characteristics.
In addition these fluids can be used to carry proppants for the fracture treatment of
sandstone reservoirs. This is particularly useful where the formation is sensitive to
water based fluids and low concentration acids are preferred.
10.14 Retarded Mud Acid Systems.
Self generating mud acid systems (Retarded Mud-Sol (RMS), SGMA) generate
hydrofluoric acid after the acid has entered the formation. The system is pumped
from surface with very little hydrofluoric acid present. Once the RMS enters the
formation reaction starts, generating hydrofluoric acid allowing deeper penetration of
live HF. With this system clays are more effectively removed throughout the zone of
acid contact, and a more productive stimulation results. RMS maintains a low pH
throughout the contact time thus preventing secondary precipitation.
10.15 Sandstone Acid
Sandstone Acid is a unique retarded acid system for sandstone formations. It is a
system for moderate to deep penetration which uses conventional HCl:HF acid
mixtures with an additional component “HY Acid”. This special blend of acids
provides powerful retarding properties, unlike conventional HCl:HF mixtures, which
react rapidly with clays yielding very shallow acid penetration. The main features of
this new acid system are as follows:
- · The ability to retard and limit the reaction with clay minerals.
- · The ability to increase reaction rates with quartz, thus improving overall permeability.
These features allow the use of stronger acids than would be used in conventional
systems, particularly where the formation contains large amounts of clays. Thus
strong acids can be placed deep into the formation without risk of de-consolidation
of the near wellbore region. In addition, the application of this acid can be extended
to it’s use in acid fracturing low permeability (2.0 to 10 md) sandstone formations.
10.16 Acid Strength.
The strength of acid used is dependent on the solubility of the formation, with some
basis placed on previous experience in a given area and common sense. (Refer to
Table 14, page 67)
If the formation has less than 10% solubility 3.0% to 15% hydrochloric acid is used.
Stronger hydrochloric acid strengths (15% to 28%) are used to obtain more live acid
further from the wellbore for deeper penetration. Where organic or mixed acids are
used, strengths equivalent to the dissolving power of hydrochloric acid are used.
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