03-05-2013, 03:22 PM
Sandstone Acidizing
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INTRODUCTION
Stimulation of petroleum wells by acid injection in sandstone reservoirs (almost all of our onshore fields) by mud acid injection is accomplished by selective dissolution of part of formation rock to reduce the resistance to fluid flow in the vicinity of the wellbore. Because of the radial flow geometry, the productivity of the well may be increased greatly.
Brief history of sandstone acidizing:
Sandstone acidizing with hydrofluoric acid (HF) was practiced in Texas in 1933 following the issuance of a patent to the Standard Oil Company; however, the field tests were not successful because of plugging of the formation. Commercial application of HF acidizing of sandstones occurred in the Gulf Coast of Mexico in 1940 when Dowell introduced mud acid, a mixture of HCl and HF. Dowell research indicated that the HCl helped maintain a low pH and decreased the precipitation of damaging precipitates. Following this event, the application of sandstone acidizing grew rapidly.
As the application of acidizing expanded, several chemical and mechanical problems were addressed. Numerous acid additives and systems were developed to solve the problems of acid sludging, acid-induced emulsions, spent acid cleanup, live acid penetration and fines migration. Parallel to this development was the development of methods to improve zone coverage during acidizing.
Technology and Application:
Matrix acidizing in sandstone reservoirs can be very beneficial to many damaged oil, gas and water injection wells, but not all matrix treatments are successful even when the well is severely damaged. A complete and accurate well and formation analysis, treatment design, well preparation, job supervision and follow up evaluation all are required to achieve maximum benefit from matrix acidizing. The words of great pioneers in the field, Mr P E Fitgerald of Dowell Inc, 1934, ‘The value of repeated acid treatments’ – It is recognized now that every well is a problem in itself and must be analyzed individually in order to obtain the best results’
Fluid Selection:
Hydrofluoric acid has been widely used in stimulation treatments since 1935, when mud acid was introduced to the petroleum industry. Originally, this hydrochloric-hydrofluoric acid mixture was intended to remove mud filter cake, but it has since been successfully applied to many other oilfield problems. Hydrofluoric acid’s reactivity with silica makes it unique in application. Other mineral acids such as hydrochloric, sulfuric or nitric are unreactive with most silicious materials, which comprise sandstone formations. A typical sandstone reservoir may contain 50 to 85 per cent sand or quartz. Chemical reactions of different sandstone minerals with basic mineral acids used in sandstone acidizing are given below.
Alcoholic mud acid:
Alcoholic mud acid formulations are a mixture of mud acid and isopropanol or methanol (up to 50%). The main application is in low-permeability dry gas zones. Dilution with alcohol lowers the acid-mineral reaction rate and provides a retarding effect. Cleanup is facilitated; acid surface tension is decreased by the alcohols while the vapor pressure of the mixture is increased, which improves gas permeability by reducing water saturation.
SGMA (self-generating mud acid):
The first retarded sandstone-acidizing system to be used extensively was developed by Shell Oil Company. It involves pumping ammonium fluoride and an organic ester, methyl formate, into the formation. (Methyl formate has a very low flash point and should be pumped with caution.)In time, ester hydrolysis produces formic acid. This acid reacts with ammonium fluoride to form HF, which then dissolves clays or any siliceous minerals it contacts.
Damage characterization and type of acid:
Selection of a chemical for any particular application will depend on which contaminants are plugging formation permeability. HCl will not dissolve pipe dope, paraffin, or asphaltenes. Treatment of these solids or plugging agents requires an effective organic solvent (usually aromatic solvents like toluene, xylene, or orthonitrotoluene). Acetic acid effectively dissolves calcium carbonate scale, however, it will not dissolve ferric oxide (iron oxide) scale. HCl dissolves calcium carbonate scale quite easily but has little effect on calcium sulfate scales. Calcium sulfate can be converted to calcium carbonate or calcium hydroxide by treatment with potassium hydroxide or sodium carbonate. HCl then can be used to dissolve the converted scale. Calcium sulfate also can be dissolved in one step with sodium salt of ethylene diamine tetra acetic acid (EDTA). HCl will not dissolve formation clay minerals or drilling mud. Hydrofluoric acid (HF) must be used to dissolve these aluminosilicates in rock pores around the wellbore.
Because different plugging solids require different solvents for their removal, there is no universal solvent for wellbore damage. It is important to know the specific material that is damaging the formation around the wellbore.
• Production increases are most significant for matrix acidizing of damaged formations. Production increases resulting from HF treatment of undamaged formations would not in most cases be significant enough to justify the cost of the stimulation treatment.
• In the formations with drilling mud damage resulting from clay particle invasion, volume of acid sufficient to remove only the clay contained within a 1 inch radius of the wellbore should yield the most economical production increases. This applies only if no natural damage has occurred as a result of mud filtrate’s contacting water sensitive clays.
Typical sandstone acid job stages
A preflush stage should be used ahead of the HCl especially when high sulfate ion or high bicarbonate ion concentrations exist in the formation connate water or seawater or when CaCl2, KCl or CaBr completion fluids have been used and calcium carbonate is a formation mineral. HCl dissolution of the calcite generates high calcium ion concentrations that mix with the incompatible formation water and generate scale (calcium sulfate or calcium carbonate).
Flowback and cleanup techniques:
Selection of the correct flowback procedure is critical. The flowback during multiphase transition periods can cause irreversible damage. The fines loosened during the acid job are invariably produced back into the near-wellbore area. These fines can be removed in diluted concentrations that pass through the completion if small, gradual pressure drops are created. The following are key factors to consider for flowback in sandstone formations:
• The fluids flowing back are more viscous than those injected. They are capable of carrying natural formation fines and other partially dissolved solids at lower velocities, which can cause plugging before the well cleans up completely.
• The spent acid usually has a higher density than the formation water. The tubing pressure should be lower than when connate water is produced, owing to the higher hydrostatic pressure of the spent acid.
• Spent acid has an equilibrium established of potential precipitants, held in place by dissolved gases and dissolved salts. Should these gases (e.g., CO2) be removed from the spent fluid as a result of creating an excessive pressure drop, precipitation will occur.
• A minimum velocity is necessary for liquid to be voided from the tubing without slippage occurring. The minimum velocity to the unload tubing can be calculated. The flow rate and tubing pressure in this calculation should include the heavier liquid density. The flow rate should be achieved gradually but sufficiently soon to avoid precipitation in the formation. The rate should then be maintained until all injected fluids are returned and both the tubing pressure and production rate are steady.
• HF systems should be flowed back immediately after injection of the overflush. The potential damaging precipitates that are generated form when the pH increases as the HCl is spent. If the acid is returned quickly, then the pH change may not reach the range for precipitation. Many iron precipitates also drop out when the pH increases. The exception is fluoboric acid treatments. The shut-in time required for complete HF generation and fines stabilization varies on the basis of temperature.
[attachment=53399]
INTRODUCTION
Stimulation of petroleum wells by acid injection in sandstone reservoirs (almost all of our onshore fields) by mud acid injection is accomplished by selective dissolution of part of formation rock to reduce the resistance to fluid flow in the vicinity of the wellbore. Because of the radial flow geometry, the productivity of the well may be increased greatly.
Brief history of sandstone acidizing:
Sandstone acidizing with hydrofluoric acid (HF) was practiced in Texas in 1933 following the issuance of a patent to the Standard Oil Company; however, the field tests were not successful because of plugging of the formation. Commercial application of HF acidizing of sandstones occurred in the Gulf Coast of Mexico in 1940 when Dowell introduced mud acid, a mixture of HCl and HF. Dowell research indicated that the HCl helped maintain a low pH and decreased the precipitation of damaging precipitates. Following this event, the application of sandstone acidizing grew rapidly.
As the application of acidizing expanded, several chemical and mechanical problems were addressed. Numerous acid additives and systems were developed to solve the problems of acid sludging, acid-induced emulsions, spent acid cleanup, live acid penetration and fines migration. Parallel to this development was the development of methods to improve zone coverage during acidizing.
Technology and Application:
Matrix acidizing in sandstone reservoirs can be very beneficial to many damaged oil, gas and water injection wells, but not all matrix treatments are successful even when the well is severely damaged. A complete and accurate well and formation analysis, treatment design, well preparation, job supervision and follow up evaluation all are required to achieve maximum benefit from matrix acidizing. The words of great pioneers in the field, Mr P E Fitgerald of Dowell Inc, 1934, ‘The value of repeated acid treatments’ – It is recognized now that every well is a problem in itself and must be analyzed individually in order to obtain the best results’
Fluid Selection:
Hydrofluoric acid has been widely used in stimulation treatments since 1935, when mud acid was introduced to the petroleum industry. Originally, this hydrochloric-hydrofluoric acid mixture was intended to remove mud filter cake, but it has since been successfully applied to many other oilfield problems. Hydrofluoric acid’s reactivity with silica makes it unique in application. Other mineral acids such as hydrochloric, sulfuric or nitric are unreactive with most silicious materials, which comprise sandstone formations. A typical sandstone reservoir may contain 50 to 85 per cent sand or quartz. Chemical reactions of different sandstone minerals with basic mineral acids used in sandstone acidizing are given below.
Alcoholic mud acid:
Alcoholic mud acid formulations are a mixture of mud acid and isopropanol or methanol (up to 50%). The main application is in low-permeability dry gas zones. Dilution with alcohol lowers the acid-mineral reaction rate and provides a retarding effect. Cleanup is facilitated; acid surface tension is decreased by the alcohols while the vapor pressure of the mixture is increased, which improves gas permeability by reducing water saturation.
SGMA (self-generating mud acid):
The first retarded sandstone-acidizing system to be used extensively was developed by Shell Oil Company. It involves pumping ammonium fluoride and an organic ester, methyl formate, into the formation. (Methyl formate has a very low flash point and should be pumped with caution.)In time, ester hydrolysis produces formic acid. This acid reacts with ammonium fluoride to form HF, which then dissolves clays or any siliceous minerals it contacts.
Damage characterization and type of acid:
Selection of a chemical for any particular application will depend on which contaminants are plugging formation permeability. HCl will not dissolve pipe dope, paraffin, or asphaltenes. Treatment of these solids or plugging agents requires an effective organic solvent (usually aromatic solvents like toluene, xylene, or orthonitrotoluene). Acetic acid effectively dissolves calcium carbonate scale, however, it will not dissolve ferric oxide (iron oxide) scale. HCl dissolves calcium carbonate scale quite easily but has little effect on calcium sulfate scales. Calcium sulfate can be converted to calcium carbonate or calcium hydroxide by treatment with potassium hydroxide or sodium carbonate. HCl then can be used to dissolve the converted scale. Calcium sulfate also can be dissolved in one step with sodium salt of ethylene diamine tetra acetic acid (EDTA). HCl will not dissolve formation clay minerals or drilling mud. Hydrofluoric acid (HF) must be used to dissolve these aluminosilicates in rock pores around the wellbore.
Because different plugging solids require different solvents for their removal, there is no universal solvent for wellbore damage. It is important to know the specific material that is damaging the formation around the wellbore.
• Production increases are most significant for matrix acidizing of damaged formations. Production increases resulting from HF treatment of undamaged formations would not in most cases be significant enough to justify the cost of the stimulation treatment.
• In the formations with drilling mud damage resulting from clay particle invasion, volume of acid sufficient to remove only the clay contained within a 1 inch radius of the wellbore should yield the most economical production increases. This applies only if no natural damage has occurred as a result of mud filtrate’s contacting water sensitive clays.
Typical sandstone acid job stages
A preflush stage should be used ahead of the HCl especially when high sulfate ion or high bicarbonate ion concentrations exist in the formation connate water or seawater or when CaCl2, KCl or CaBr completion fluids have been used and calcium carbonate is a formation mineral. HCl dissolution of the calcite generates high calcium ion concentrations that mix with the incompatible formation water and generate scale (calcium sulfate or calcium carbonate).
Flowback and cleanup techniques:
Selection of the correct flowback procedure is critical. The flowback during multiphase transition periods can cause irreversible damage. The fines loosened during the acid job are invariably produced back into the near-wellbore area. These fines can be removed in diluted concentrations that pass through the completion if small, gradual pressure drops are created. The following are key factors to consider for flowback in sandstone formations:
• The fluids flowing back are more viscous than those injected. They are capable of carrying natural formation fines and other partially dissolved solids at lower velocities, which can cause plugging before the well cleans up completely.
• The spent acid usually has a higher density than the formation water. The tubing pressure should be lower than when connate water is produced, owing to the higher hydrostatic pressure of the spent acid.
• Spent acid has an equilibrium established of potential precipitants, held in place by dissolved gases and dissolved salts. Should these gases (e.g., CO2) be removed from the spent fluid as a result of creating an excessive pressure drop, precipitation will occur.
• A minimum velocity is necessary for liquid to be voided from the tubing without slippage occurring. The minimum velocity to the unload tubing can be calculated. The flow rate and tubing pressure in this calculation should include the heavier liquid density. The flow rate should be achieved gradually but sufficiently soon to avoid precipitation in the formation. The rate should then be maintained until all injected fluids are returned and both the tubing pressure and production rate are steady.
• HF systems should be flowed back immediately after injection of the overflush. The potential damaging precipitates that are generated form when the pH increases as the HCl is spent. If the acid is returned quickly, then the pH change may not reach the range for precipitation. Many iron precipitates also drop out when the pH increases. The exception is fluoboric acid treatments. The shut-in time required for complete HF generation and fines stabilization varies on the basis of temperature.