3. Acidizing Limestones, Dolomite and Sandstone Formations.

Much of the worlds oil and gas comes from limestone (CaCO3) and dolomite
(CaMg(CO3)2) formations, either in their relatively pure form or in the form of
carbonate or siliceous sands cemented together with calcareous materials (CaCO3).
Dolomites are similar to limestones with the exception that they generally react more
slowly with hydrochloric acid.

The primary method of stimulating wells drilled into these formations is to inject an
acid treating solution. The acid dissolves part of the formation and may also dissolve
other acid soluble material (mud damage, scales etc.), which is restricting or
blocking the flow of oil or gas from the formation. Matrix acidizing increases the flow
capacity of a producing formation when these restrictions are removed.

3.1 Limestone and Dolomite.

When either limestone and/or dolomite formation are stimulated, acid enters the
formation through pores in the matrix of the rock or through natural or induced
fractures. The type of acidizing used depends on, the injection rate and the number
and size of the fractures present. Most limestone and dolomite formations produce
through a network of fractures, though both formations can exist in an unfractured
state. Normally, an interval will accept acid through the fractures more readily and at
lower pressure than through the pore spaces. The acid solution reacts with the walls
of the flow channels, increasing the width and conductivity of the fractures.

Most limestones and dolomite formations vary in acid solubility. Acid will attack the
surface of the formation at varying rates, leaving an unevenly etched face. The
existence of natural fractures, that occur at random intervals and in random sizes,
contribute to the final uneven etching configuration.

The type of acid and strength are equally important factors in influencing the etch
pattern. The amount of limestone dissolved by 1000 gallons hydrochloric acid at
different strengths is shown in Figure 1. The use of various types of acid (such as
chemically retarded or emulsified acid), ensure that the volume of limestone or
dolomite dissolved, will occur in an uneven pattern across the face of the fracture.
Gelled and cross-linked acids can also be used effectively. These fluids will create
wider fractures and have reduced leak-off, resulting in less “worm holing” and
deeper penetration due to the retarded reaction of the acid.

Chemically retarded acids are made effective by preceding the acid treatment with a
hydrocarbon preflush containing an oil-wetting surface acting agent (surfactant) Due
to the variable composition of the rock, the surfactant leaves a discontinuous oil film
on the fracture face. The resulting acid break-through is irregular, creating an
improved etch pattern.

With emulsified acid, the resulting etch patterns are influenced by the rate at which
acid penetrates the hydrocarbon outer phase of the emulsion and reacts with the
formation face.


The temperature of the formation should also be considered to ensure that the
selection of either chemically retarded acid or delayed reaction acid is the one that is
most suitable for the treatment recommended. Desired acid strengths for different
temperatures are shown in Table (page 21).

Acid volume and pump rate determine the acid contact time, during which the
fracture faces are exposed to live acid. Contact time has a direct bearing on the
amount of etching obtained. However, increasing the volume of an acid treatment
does not appreciably increase the depth of penetration.
Thus, the benefit of a attributed to acid etching, which results in additional flow conductivity.
The "shut-in time", or the length of time a well is closed in after a stimulation
treatment, is determined by the type of acid used and by such downhole factors as:

• · Type of formation.
• · Bottom-hole temperature.
• · Bottom hole pressure.

After an acid solution has been neutralised by reaction with the formation, it is no
longer a stimulation agent. However, it may become harmful to the formation
permeability if allowed to remain downhole.

Hydrochloric acid reacts so rapidly with limestone formations that it is essentially
neutralised by the time the acid has been completely placed. This neutralisation
generally occurs at all ranges of temperature and pressure. Limestone formations
incorporate varying amounts of insoluble impurities, which can plug permeability if
allowed to come to rest. Therefore, it is important to remove the neutralised
hydrochloric acid as soon as possible. The shut-in time with such formations is zero.
Figures 2 to 5 show the relative reaction rates of 15% hydrochloric acid with
limestone and dolomite formations at different temperatures.

When chemically retarded acids like super retarded acids (SRA), delayed reaction
systems (Super Sol Acid (EQH)), Sta-Live and emulsified acids like SRA-3 are used,
the reaction time exceeds the displacement time. This is also true for gelled and
cross-linked acids (Gelled Acid, Gelled Acid XL, XL Acid II). Here, the shut-in time
may be extended if there is sufficient bottom-hole pressure to promote rapid cleanup.
For reaction times of retarded acids consult the engineering product bulletin
pertaining to the acid system used.








3.2 Sandstone Acidizing.

The primary purpose of sandstone acidizing is to stimulate the permeability of the
formation. Matrix type treatments are used in most cases. Limestone and dolomite
formations react at high rates with hydrochloric acid and at moderate rates with
formic and acetic acids. Sandstone formations, however, react little, if at all, with
these three acids.

Most sandstone formations are composed of quartz particles, silicon dioxide (SiO2)
bonded together by various kinds of cementing materials, chiefly carbonates, silica
and clays. The amount of reaction with hydrochloric, formic and acetic acids is
limited to the amount of calcareous material present in the formation. However, the
silicon dioxide and the clay will react with hydrofluoric acid, even though the reaction
rate is slow compared to the reaction of hydrochloric acid with limestone.

Since hydrofluoric acid reacts with sands (silica), silt, clay and most drilling muds, it
has been found to be effective in stimulating, and removing formation damage from
and in stimulating sandstone reservoirs. Hydrofluoric acid is normally used in
combination with hydrochloric acid in mixtures which range in strength from 6.0%
HCl with 0.5% HF to 28.0% HCl with 9.0% HF. The most common strength used is
12.0% HCl with 3.0% HF, and is usually referred to as Regular Mud Acid (RMA) or
mud acid.

Some situations may require 15.0% HCl with 3.0% or 4.0% HF for effective
sandstone stimulation. The best ratio or concentration of HCl:HF strength should be
determined by laboratory core tests. HCl:HF acid strengths above the 4.0% HF
concentration should be avoided because disassociation of the formation can occur.
Other common HCl:HF strengths are listed below:


preferred, to the use of liquid hydrofluoric acid, for two reasons :

• · Liquid hydrofluoric acid is extremely hazardous to handle.
• The ammonium ions, produced in solution, act as a buffer that
  minimises the formation of precipitates

 The hydrochloric acid in these formulations has three purposes:

• · It acts as a converter to produce hydrofluoric acid from the ammonium bifluoride salt.
• · It dissolves the hydrochloric acid-soluble material and thus prevents the hydrofluoric acid from spending too rapidly.
• · It prevents the precipitation of Calcium Bifluoride (CaF2).

The basic factors controlling the relative reaction rate of hydrofluoric acid within the
matrix are; temperature, acid concentration, pressure, chemical composition of the
formation rock, and the ratio of rock area to acid volume.

Temperature has a marked effect on the reaction rate of hydrofluoric acid with sand
and clay. The rate of reaction approximately doubles for each 50° F (28° C) increase
in temperature. Table 4 shows the recommended maximum acid strengths for use
at different temperatures



Surprisingly, reaction rate also increases with pressure, even though most reactions
that produce a gas (such as the reaction of silicates with hydrofluoric acid) are
retarded by pressure. The formation of fluorosilicic acid (H2SiF6) from evolved gas,
silicon tetrafluoride (SiF4), contributes to the overall reaction of the formation, which
could explain the increased reaction rate of hydrofluoric acid under pressure.

The rate of reaction also doubles as the concentration doubles; for example, a
12.0% : 4.0% solution of hydrofluoric acid reacts twice as fast as a 12.0% : 2.0%
solution, with clays and silicates.
The relative amounts of sandstone, clay, silt and calcareous materials in any given
formation also affect the reaction rate. Each material has its own characteristic
reaction rate with hydrofluoric acid. For example, hydrofluoric acid reacts with clay at
a faster rate than with sand, and with calcareous material at a faster rate than with
clays.
3.2.1 Optimising HCl:HF Acid Strength from Core Flow Studies.
To optimise the strength of HCl:HF mixtures used in sandstone stimulation, tests are
carried out with several hydrochloric and hydrofluoric acid mixtures. These tests are
run using sandstone cores at simulated bottom hole temperatures. The hydrofluoric
acid in the acid mixtures serves two essential purposes:
· Dissolves and disperses clays present in the sandstone.
· Dissolves the silica coating that covers many carbonate deposits
present in the formation allowing the hydrochloric acid present to react
with these deposits.
Removal of the clays can lead to large increases in the flow improvement ratio,
whilst removal of the silica coating, allowing dissolution of the carbonate deposits
increases formation solubility. The overall effect of these two actions is significant
increases in reservoir productivity.
To simulate actual flow conditions in a reservoir, initial permeability of the core is
established by flowing brine through the core sample. Acid stimulation fluids are then
flowed through the core in the opposite direction. Core permeability after acidizing
(return permeability) is then measured by flowing brine or other fluids in the original
direction. In this way flow of fluids to and from the wellbore are simulated as they
would occur in the producing formation.
From the test results obtained, core permeability after stimulation (final permeability,
Kf) can be compared with the initial permeability (Ki), and expressed as a flow
improvement ratio:



Figure 6 shows the effect of various HCl:HF acid concentrations on the flow
improvement ratio of Berea Sandstone (a universal laboratory testing medium).
Clearly the maximum flow improvement ratio was obtained with a mixture of 15.0%
HCl and 4.0% HF acid.

From the data produced with Berea Sandstones, it can be seen that acid
concentrations of less than 15.0% HCl and 4.0% HF are not as efficient at dissolving
clay and silicates, therefore the flow improvement ratios are lower.


Hydrofluoric acid concentrations above 4.0% should not be used. As can be seen in
Figure 6 above, the 15.0% HCl to 7.0% HF mixture, deteriorates the core causing a
decrease in permeability.

The use of high concentrations of hydrofluoric acid cause sand formations to
become unconsolidated, and can create problems by promoting the production of
sand. This process is caused by the removal of too much of the silica and carbonate
cementing materials present in the formation.

Generally a few pore volumes of 15.0%:7.0% mix of HCl:HF acid will unconsolidate
a core, whereas many pore volumes of the 15.0%:4.0% mixture will leave the same
core intact. In addition, a 15.0%:7.0% mix of hydrofluoric acid will form a large
volume of precipitates. This is particularly true where the solution is made up from
liquid hydrofluoric acid as opposed to ammonium bifluoride. The reason for the
lesser problem with the ammonium salt is that, when the ammonium ions are
dissociated and in solution they act as a chemical buffer which helps maintain a low
pH thus minimising precipitation.

If representative cores are not available, the optimum volumes and concentrations
should be determined by using local experience and guidelines presented in this
manual, such as the Berea sandstone curves given in Figure 6. Since the ratios for a
given reservoir can vary substantially, no generalised set of flow improvement ratios
are presented for various formations.

3.2.2 Prevention of Precipitation of Reaction By-Products.

Because fluorine is a very reactive element and because the composition of
sandstone is varied, many reaction products are formed when sandstone formations
are stimulated with hydrofluoric acid. For example calcium bifluoride (CaF2) is
formed when hydrofluoric acid reacts with calcium carbonate (CaCO3).

As long as live HCl:HF acid is present, the calcium fluoride (an undesirable product),
remains ionised and in solution. However, in the absence of hydrofluoric or
hydrochloric acid, calcium bifluoride may be precipitated. Maintaining a low pH and
using a short shut-in time ensures against the deposition of calcium bifluoride. A
preflush of hydrochloric acid is also used to react with and remove the calcium and
magnesium carbonates in the formation.

Sodium and potassium ions that may be present in the formation water can react
with hydrofluoric acid to form insoluble precipitates, such as sodium or potassium
hexafluosilicate (Na2SiF6 or K2SiF6).
When this possibility exists, a preflush of hydrochloric acid should always be used
ahead of the hydrofluoric acid treating solution to displace the formation water.
Brines and sea water should never be used to prepare this treating fluid, as the
metal ions present in solution, can react to form precipitates with hydrofluoric acid.
The use of 15% HCl as a preflush serves three purposes:

• · It removes calcium and magnesium carbonates.
• · It minimises the loss of the hydrofluoric acid used in the second phase of a treatment.
• · It serves as a spacer between the HCl:HF acid and the formation brine.

Other preflushes and fluids which can be used to provide a barrier include:

• · Ammonium Chloride (2.0% to 4.0%). Also acts as a chemical buffer to prevent formation of precipitates.
• · Diesel oil.
• · Kerosene.
• · Clean Lease oil.

A post-flush of 3.0% to 15% HCl should be used as a pad to separate the HCl:HF
acid from the displacement fluid. This post-flush will prevent the formation of
precipitates, by preventing brine from mixing with the HCl:HF acid during
displacement, and act to maintain a low pH as the spent acid is produced back.
Sufficient volume should be used to displace the HCl:HF acid out into the formation
and reduce the risk of damage from precipitation in the near wellbore area. Other
post-flushes include:

• · Ammonium Chloride (2.0% to 4.0%). Also acts as a chemical buffer to prevent formation of precipitates.
• · Diesel oil.
• · Kerosene.
• · Clean Lease oil.

Shut in times should be kept to a minimum to reduce the possibility of precipitation
of reaction by-products that might reduce the effectiveness of the stimulation
treatment.