5. Acidizing Damage.

Formation damage will almost always occur during an acid job, therefore, it is
necessary to make certain that the stimulation benefits outweigh the negative effects
of the created or existing damage, for the job to be successful. When designing an
acid job, the engineer must be aware the various types of damage that can occur
and take the necessary steps to prevent them. The most common types of formation
damage caused during acidizing are as follows :

• · Formation de-consolidation.
• · Fines mobilisation.
• · Reaction by-products.
• · Chemical incompatibilities.
• · Precipitation of iron compounds.
• · Emulsions and sludges.

5.1 Formation De-Consolidation.

The problems and damage resulting from formation de-consolidation can be very
severe. Reduced permeability due to the mobilisation of the formation material can
shut off production itself. Formation sand flowing into the wellbore causes numerous
problems with the production equipment that can be extremely costly.

The potential for damage due to de-consolidation depends upon the formation
geomorphology, acid strength and acid volume pumped. For example, if the
formation consists of 10.0 % carbonate material and this material is cementing the
sand grains together, it is undesirable to dissolve all of this material with acid.
Reduced HCl volumes and strengths should be used in this situation when preflushing
ahead of mud acids.

In the case where sand grains are cemented together with clay material, reduced
mud acid strengths and volumes should be considered. Full knowledge of the
formation mineralogy and geomorphology is essential.

5.2 Fines Mobilisation.

Release and mobilisation of clay and other silicate materials can severely damage a
wells productivity. Since a given volume of strong acid dissolves more formation than
the same volume of weaker acid, a greater volume of insoluble fines may be
released by the reaction. As the well is put back on production, the fines that have
been released can migrate and bridge in the near wellbore area. Released fines can
also act to stabilise emulsions. The use of non-ionic or anionic surfactants, or mutual
solvents such as INFLO-40 (EGMBE) will help to water-wet these fines, thus
preventing emulsion stabilisation. More importantly, if the fines become oil-wet, the
ability for these fines to migrate is increased. Consideration should also be given to
the use of suspending agents (MMR Acid), fines stabilising agents (FSA-1),
Sandstone Acid, or in the case of fracture treatments of limestones, gelled and
cross-linked acids.

5.3 Reaction By-Products.

When calcium sulphate in the form of anhydrite (CaSO4) or gypsum (CaSO4.2H2O)
is present in the formation, the problem of re-precipitation may arise. This occurs
because this sulphate is less soluble in spent acid than in live acid.

Since calcium sulphate has a maximum solubility in hydrochloric acid within the
range of 8.0 % to 12.0 %, its re-precipitation can be minimised by the use of highstrength
treating solutions. On entering the formation, the acid solution dissolves a
minimal amount of gypsum. As the acid reacts, its capacity to dissolve gypsum
increases. However, the calcium chloride (CaCl2) formed as a reaction by-product of
acid and limestone exerts an opposite effect, resulting in an over-all stabilisation of
the amount of gypsum dissolved.

In addition to decreasing the solubility of the CaSO4, calcium chloride increases the
viscosity of the spent acid. A 15.0 % solution of HCl, when completely reacted with
limestone, becomes an 18.9% solution of CaCl2. If the acid concentration had been
28.0%, the spent acid would contain 30.7% CaCl2. The viscosity of the latter solution
is about twice that of the first and about three times that of live 15.0% HCl. In a well
with a relatively low formation pressure this increase in viscosity could reduce the
rate of return flow into the wellbore, allowing insoluble material released from the
formation by the treatment to settle out in the fissures and porosity of the formation,
and subsequently reduce oil or gas flow.

Strong acids, when spent, will have a higher concentration of dissolved reaction byproducts
than a weaker acid. The solubility of other salts is usually lowered in strong
spent acid. If formation water with a high sodium chloride content is encountered,
precipitation of the salt may occur.

There are many reaction by-products that can form when certain minerals are
dissolved by hydrofluoric acid. The amount of precipitates actually formed is highly
dependent upon the bottom hole static temperature and the acid contact time in the
formation.

The most well known precipitate is calcium bifluoride which is a by-product formed
by the reaction of live hydrofluoric acid with calcium carbonate material found in the
sandstone matrix.



Hydrofluoric acid reacting with clay materials, can form by-products such as
fluosilicic acid (H2SiF6) and fluoaluminic acid (H3AlF6). These acids will react further
with carbonate materials to form hydrated silica and aluminium respectively. These
hydrated compounds will precipitate out of solution in volumes that are much greater
than the volume of the of the original formation material dissolved, thus significantly
increasing the damage potential.



The Feldspar content of a sandstone is often overlooked. Hydrofluoric acid reacting
with potassium feldspar will form a precipitating by-product of potassium
hexafluosilicate. Sodium hexafluosilicate will also precipitate where a high
concentration of hydrofluoric acid is reacting with sodium feldspar.



Amorphous hydrous silica (silicon tetrafluoride) will always be a by-product from the
reaction of hydrofluoric acid with sandstone formations. This cannot be prevented,
but the damage caused by it and other precipitates can be minimised with a well
designed and executed acid job.



The following are general guidelines that can be used to minimise the damage
associated with precipitates formed as reaction by-products with hydrofluoric acid :

• · Use chelating and sequestering agents based on the mineralogical properties of the formation.
• · Determine the hydrochloric acid (HCl) preflush and Hydrofluoric Acid (HCl:HF) volumes from formation solubility analysis, permeability and porosity.
• · Overflush the acid treatment to four or five feet away from the wellbore.
• · Minimise acid contact times to four hours.
• · Acid strengths should be determined from the bottom hole static temperature.

5.4 Additive Incompatibility.

When choosing the additives to be included in an acid treatment, one must always
consider the compatibility of the additives with each other and with the acid.
Solubility, dispersibility and chemical compatibility should be checked in the
laboratory prior to pumping the acid system into the well.

5.4.1 Solubility.

Some additives are soluble in acid at low concentrations only. At high
concentrations, these additives will flocculate out. If the additive is oil soluble, it will
float to the top.

5.4.2 Dispersibility.

If an oil soluble additive is to be used, a dispersant must be added to the acid
system. A good example of this is the use of xylene in acid. Without a dispersant,
the xylene would simply float to the top of the acid. The dispersant must be strong
enough to keep the xylene dispersed for a sufficient time for the acid to be pumped
into the formation.

5.4.3 Chemical Compatibility.

The most common problem encountered here is the mixing of an anionic additive
with a cationic additive. This can sometimes cause a precipitate to form. At times it is
necessary to mix cationics with anionics, for example, retarded acids often use
anionic surfactants to emulsify the acid, whilst most corrosion inhibitors are cationic.
The same applies to anti-sludging agents. In these cases consideration should be
given to the use of pre-flushes containing diesel or solvent to contain one of the
additives.

5.5 Iron Compounds.

Precipitation of iron hydroxides can severely damage a well. There are two forms of
iron hydroxide that need to be considered, ferrous (Fe2+) and ferric (Fe3+).
Ferrous hydroxide will precipitate out at a pH of 5.0 or more, whereas ferric
hydroxide will precipitate out at a pH of 2.2 or more, therefore ferric hydroxide is the
main one to be concerned with. Some iron control agents are designed to reduce
ferric iron (Fe3+) to ferrous iron (Fe2+), whilst others are designed to maintain a low
pH (Acetic Acid).

The most common source of iron problems in a well are the tubulars. New tubing is
covered with mill scale which is in the form of ferrous oxide (FeO) and ferric oxide
(Fe2O3). Acid will dissolve and dislodge this scale from the tubing as it is pumped
into the well and carry it down into the formation.

Currently used iron control agents can only effectively control up to 10,000 ppm iron.
Case studies have shown that as much as 100,000 ppm of dissolved iron can be
picked up by the acid in less than 9000 ft of tubing. For this reason tubing strings
should always be cleaned of iron scales with a "Pickling" treatment prior to pumping
acid through them and into the formation.

5.6 Emulsions and Sludge.

5.6.1 Emulsions.

Most crude oils contain natural chemicals which frequently act to stabilise emulsions
formed with acid or with spent acid during a treatment. In general the tendency to
form emulsions increases with the concentration of the acid. The viscosity of an
emulsion, being higher than that of either its components, means that its flow from
the formation into the wellbore is impeded. An added expense is the disposal of the
emulsions aqueous phase once it has been produced. When designing treatments
the following should be considered:

• · Emulsions can be prevented if tested.
• · Crude oil from offset wells can have different emulsifying tendencies.
• · Over-treating with surfactants can cause an emulsion.

Production is severely hindered due to the high viscosities inherent with emulsions.
Emulsions are usually very easy to prevent by selection of the correct surface acting
agents and can be easily determined by simple laboratory tests. Whenever possible,
emulsion tests should be carried out using crude oil samples from the well to be
treated and the proposed acid treating solutions. It is often assumed that if an acid
system does not form an emulsion with crude from one well in the field that it will not
form one with others. Unfortunately this does not always hold true. Crude oils from
offset wells can have very different emulsion forming tendencies.

5.6.2 Sludge.

Some crude oils react chemically with hydrochloric acid during stimulation
treatments to form solid or semi-solid particles called sludge, or asphaltene sludge.
This can restrict or completely plug the flow channels in the producing formation
reducing the effectiveness of the acid treatment. The following can be said of acid
sludges:

• · Form in wells that produce asphaltic crude oils.
• · Can be prevented if tested.
• · Low pH destabilises the asphaltic colloidal dispersion.
• · High aromatic solvents are required for removal. (Xylene or Toluene).
• · Form more readily with stronger acids.

The formation of sludge when acidizing can occur in any crude oil that contains
asphaltenes. In general it can be said that, if a crude oil has a tendency to sludge, it
is more likely to form with stronger acids and in greater volumes. Crude oils with this
tendency can be identified by simple laboratory tests and treatments can then be
designed to prevent their formation.

Sludges form when asphaltenes are precipitated out of the crude oil. Asphaltic
material exists in the formation as a colloidal dispersion of minute asphaltene
particles permeated by adsorbed maltenes. These maltene-asphaltene micelles are
stabilised by a double electrolytic bond. The low pH environment created by acids
disrupts this bond and causes destabilisation of the asphaltenes, thus allowing them
to aggregate and to precipitate out from the crude oil.

Unfortunately, sludge is extremely difficult to remove because it is insoluble in most
treating solutions, so most effort is directed towards prevention rather than
correction. Acid concentrations as low as 1.0% have produced sludge with
susceptible crudes, sludge prevention generally becomes more difficult as the
concentration of the acid increases.

Sludges are very viscous and usually require the use of a high aromatic solvent
(xylene or toluene) for removal. Sludge prevention procedures should be used when
acidizing wells that produce asphaltenic crudes.