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Petroleum Engineering Handbook
Larry W. Lake, Editor-in-Chief
Volume IV - Production Operations Engineering
Joe Dunn Clegg, Editor
Copyright 2006, Society of Petroleum Engineers
Chapter 7 – Matrix Acidizing
This chapter is organized to help perform acidizing on a well candidate in a logical step-by-step process and then select and execute an appropriate chemical treatment for the oil/gas well. The guidelines are practical in intent and avoid the more complicated acid reaction chemistries, although such investigations and the use of geochemical models are recommended for more complicated formations or reservoir conditions. Effective acidizing is guided by practical limits in volumes and types of acid and procedures so as to achieve an optimum removal of the formation damage around the wellbore.
Most of this chapter is an outgrowth of field case studies and of concepts derived from experimental testing and research. Justification for the practices and recommendations proposed herein are contained in the referenced documents. The reader is referred to the author's previous papers on matrix acidizing for references published before 1990. Concepts and techniques presented have been examined during repeated presentation of the Society of Petroleum Engineering (SPE) Short Course titled "Matrix Acidizing to Improve Well Performance."  Recent research has fine-tuned many of the concepts and acid types that are incorporated into proprietary software of various service companies. These programs are available through service company stimulation specialists who can assist with particular formation characteristics and reservoir conditions. The reader should use this chapter as an introduction to significant and necessary concepts and practices. Improved procedures and products can be selected by the company engineer in partnership with the stimulation specialist using proprietary software. The objective in the following discussion is to provide reasonable procedures and guidelines and to offer cautions suggested by particular formation compositions and reservoir conditions.
- 1 Two Basic Acidizing Treatments
- 2 Purposes/Applications
- 3 Effects of Acidizing: Undamaged Well
- 4 Selecting Successful Acidizing Candidates
- 5 Production History Plots
- 6 Offset Well Comparison
- 7 Pressure Buildup Tests
- 8 Formation Damage Diagnosis
- 9 Identify Extent/Type of Damage
- 10 Damage Removal by Chemical Solvents
- 11 Formation Response to Acid
- 12 Formation Properties
- 13 Formation Matrix Properties
- 14 Formation Mineralogy
- 15 Methods of Controlling Precipitates
- 16 Acid Treatment Design
- 17 Matrix Acidizing Design Guidelines
- 18 Acid Type and Concentration
- 19 Retarded HF Acids
- 20 Geochemical Models
- 21 Acid Placement and Coverage
- 22 Mechanical Techniques
- 23 Particulates
- 24 Viscous Acid
- 25 Advances in Acid Diversion
- 26 Horizontal Wells
- 27 Acid Additives
- 27.1 Corrosion Inhibitor
- 27.2 Surface Active Agents
- 27.3 Iron-Control Agents
- 27.4 Iron-Complexing Agents
- 27.5 Iron-Reducing Agents
- 27.6 Hydrogen Sulfide Control
- 27.7 Other Additives
- 27.8 Mutual Solvents
- 27.9 Clay Stabilizers
- 27.10 Calcium Sulfate Inhibitors
- 27.11 Gelling Agents
- 27.12 Summary Remarks
- 28 Job Supervision
- 29 Safety and Environment Protection
- 30 Well Preparation
- 31 Quality Control
- 32 Injection-Rate Control and Monitoring
- 33 Pressure Behavior During Acid Injection
- 34 On-Site Evaluation of Acid Treatment Effectiveness
- 35 Spent Acid Production Control
- 36 Produced Fluid Sampling
- 37 Evaluation of Acid Treatments
- 38 Continuous Improvement
- 39 Summary
- 40 Nomenclature
- 41 References
- 42 SI Metric Conversion Factors
Two Basic Acidizing Treatments
Acidizing is used to either stimulate a well to greater than ideal matrix reservoir flow or to remove damage. These are two distinct and different purposes, the field applications and results of which are often merged or confused. Basically, there are two types of acid treatments that are related to injection rates and pressures. Injection rates resulting in pressures below fracture pressure are termed "matrix acidizing," while those above fracture pressure are termed "fracture acidizing."
Fig. 7.1 shows the increase in pressure linearly with rate until parting pressure is attained, at which time rate can continue to increase with little change in pressure above parting pressure. Matrix acidizing is used primarily for damage removal, while fracture acidizing is used to enlarge the effective wellbore by creating an acid-etched fracture deep into the wellbore for relatively low-permeability formations to improve well productivity several-fold. This chapter focuses on matrix acidizing.
Fig. 7.1—Matrix acidizing injection rates below fracturing pressure.
A matrix treatment restores permeability by removing damage around the wellbore, thus improving productivity in both sandstone and carbonate wells. Although the acid systems used in sandstone and carbonate differ, the same practices apply to both. In the absence of damage, the large volume of acid that is required to improve the formation permeability in the vicinity of the wellbore may not justify the small incremental increase in production, especially in sandstone. In carbonate rock, hydrochloric acid enlarges the wellbore or tends to bypass damage by forming wormholes. The permeability increase is much larger in carbonate than in sandstone. The effect of damage on well productivity and flow is illustrated in Figs. 7.2 and 7.3.
Severe damage (kD/k less than 0.2) is usually close to the wellbore, within 12 in., as in Fig.7.2. More moderate damage (kD/k greater than 0.2) may occur much deeper (3 ft from the wellbore or more), as described in Fig. 7.3. Oilwell flow behavior is greatly affected by the geometry of radial flow into the wellbore; 25% of the pressure drop takes place within 3 ft of the wellbore if no damage is present, as shown in Fig. 7.4.  Because of the small flow area, any damage to the formation at that point may account for most of the total pressure drop (drawdown) during production and, thereby, dominate well performance.
Effects of Acidizing: Undamaged Well
Matrix acidizing is applied primarily to remove damage caused by drilling, completion, and workover fluids and solids precipitated from produced water or oil (i.e., scale or paraffin). Removal of severe plugging in carbonate or sandstone can result in very large increases in well productivity. On the other hand, if there is no damage, a matrix treatment seldom increases natural production more than 50%, depending on the size of the treatment and the penetration depth of live acid, as demonstrated in Fig. 7.5. 
Fig. 7.5—Effects of acidizing an undamaged well.
Wormholes are small, continuous channels formed by acid preferentially enlarging pores in carbonate, usually around 2 to 5 mm in diameter. In radial flow, wormholes form a dendritic pattern, like the roots of a tree. Gdanski developed a practical model for wormholing during matrix acidizing in carbonates, which shows that practical limits for effective penetration of hydrochloric (HCl) acid varies from about 1 to 5 ft. Penetration is limited by injection rate and volume. The maximum rate allowed is a function of the carbonate permeability. Radial penetration is so limited in low-permeability carbonate that it is a better candidate for fracture acidizing.
When there is no damage present, improper or poorly executed acid treatments can reduce the natural formation permeability and reduce well productivity, as in new wells with low reservoir permeability. Gidley presented the results of an extensive statistical review of one company's acidizing success in sandstone reservoirs in the U.S. He found that only 54% of 507 wells increased in production following hydrofluoric (HF) acid stimulation. More recently, Nitters et al. stated that past programs resulted in only 25% success. Where better evaluation and quality control have been implemented, the percentage of successful treatments has improved to 75 to 90%. Such a program was developed by Brannon et al.,  who successfully acidized 35 of 37 wells (95% success) for an average production increase of 343 BOPD. Other areas and formations still suffer from poor acidizing responses, which implies that opportunities for technology development still exist.
Selecting Successful Acidizing Candidates
Wells may perform poorly or less well than expected because of three different factors: (1) an inefficient mechanical system (wrong size tubing in a flowing well or inefficient artificial lift equipment for pumping or gas lift wells), (2) low reservoir permeability, or (3) wellbore restriction because of formation damage or incomplete perforating. A good matrix acidizing candidate is any well producing from a formation with permeability greater than 10 md and the permeability of which in the near-wellbore or near-perforation region has been reduced by solid plugging. This plugging is either mechanical or chemical. Mechanical plugging is caused by either the introduction of suspended solids in a completion or workover fluid or the dispersion of in-situ fines by incompatible fluids and/or high interstitial velocities. Chemical plugging is caused by mixing incompatible fluids that precipitate solids. If formation damage is the cause for poor production, the well is a good candidate for acidizing. Several methods can be used to evaluate the presence of damage: production history plots that show sudden change, slope change, and gradual change; offset well comparison; pressure buildup tests; and well performance analysis.
Production History Plots
Production rate/time plots are normally available for oil/gas wells that show change of rate with time and that note significant events such as workovers and stimulation treatments. Damage is revealed by at least three different characteristics as previously listed. The first is a sudden change in productivity following an event like a workover, as shown in Fig. 7.6.  An unfiltered produced brine was used to kill the well during a workover to repair a tubing leak. In this example, formation damage is obvious in the reduced productivity immediately after the workover. This lowered productivity persisted until an acid treatment removed the damage. Many times the analysis of a damaged condition is not so obvious.
Fig. 7.6—Production history graph-sudden chage (workover).
A depletion-type history curve may decline at a certain rate, as shown in Fig. 7.7.  This well followed a certain decline rate and then began to decline faster as shown by the change in slope. This is often characteristic of scale buildup around the wellbore from produced water. This well was diagnosed and treated with HCl acid to dissolve calcium carbonate scale, and production rate was restored.
Fig. 7.7—Production history graph-change in slope:scale buildup (after Farina).
Some changes occur so slowly over time that productivity change is difficult to detect. Overlaying history curves of different wells will reveal this change in productivity. Fig. 7.8 shows this overlay for two California wells. Increasing water production called attention to one well, and testing revealed a casing leak in this well. 
Fig. 7.8—Production history graph-overlaying graphs to detect damage.
Offset Well Comparison
Often acidizing candidates are selected on the basis of offset well comparisons. The productivities of offset wells are compared, and the poorer-performing wells are selected for acidizing. Many times, this selection is made without sufficient well testing. Pressure buildup testing may be too expensive in terms of lost production during long shut-ins, or well interference may circumvent reliable long-time pressure data. Table 7.1 shows such an offset comparison. 
On the basis of production only, three wells are acidizing candidates. However, when one compares the formation potential through log analysis, as expressed by net porosity feet, only one well is a reliable acidizing candidate: Well B-1. Acidizing all three wells on the basis of production rate alone may provide only a 33% success. In waterfloods, it is also important to compare effective reservoir pressures around each well or to compare the injection rates from adjacent water injection wells. If a well's water injectivity is low, production will be less in the offset producing well.
Pressure Buildup Tests
Where wells flow naturally, as in natural gas wells or new oil wells, pressure buildup tests provide a reliable measure of reservoir permeability and wellbore condition (skin factor, S). The skin factor, S, when positive, indicates restricted flow; however, the restriction is not necessarily formation damage. A skin factor of 5 to 20 or more can result from inadequate perforation size and/or low shot density when combined with either non-Darcy or two-phase fluid flow. Two-phase flow effects and non-Darcy flow cause high skin factors by themselves and can amplify the restriction caused by limited perforating. Such an example is shown in the buildup test in Fig. 7.9.  See the chapter on fluid flow in the reservoir engineering section of this handbook for more details on this type of plot.
Fig. 7.9—Pressure buildup of a south Texas gas well.
This gas well was perforated with sufficient underbalance to achieve clean undamaged perforations, yet the skin factor from the pressure buildup test was 11. Well flow analysis showed that this skin was caused mainly by high-velocity flow of gas into small perforations created by the small through-tubing perforating gun used in this well.
Other wells have been identified with high skin factors that were the result of limited perforating and two-phase-flow effects. One gas condensate well had a skin factor of 29, which was the result of liquid saturation buildup and non-Darcy flow around the wellbore after a compressor was installed to pull the well harder. Another well in a deep, overpressured oil reservoir had a positive skin factor even after fracturing because of a solution gas/oil ratio (GOR) over 1,200 scf/bbl and a high pressure drawdown. Acidizing such wells have caused productivity decreases because acidizing sometimes produces damage where no damage existed before acidizing; therefore, use the checklist shown in Table 7.2 before selecting acidizing candidates on the basis of high skin factors alone. 
A skin factor can be analyzed by well flow analysis to show when it is caused by the previously described effects or when it is the result of permeability damage. An example of such a damaged well is shown in Fig. 7.10.  This figure shows predicted gravel-pack pressure drop vs. flow rate for different effective shots per foot (perforations). This well was perforated adequately and should have produced much better after completion. Review of the completion procedure showed that formation damage probably occurred during completion, and a standard acidizing treatment was used to dissolve the damage. Performance significantly improved, as shown by the reduction of completion pressure drop and increase of flow rate in this gas well.
Fig. 7.10—Well completion analysis.
Formation Damage Diagnosis
Well testing and well test analysis generate a skin factor and well completion efficiency. This is insufficient alone for formation damage diagnosis. Well performance analysis has provided a beneficial tool to identify the location and thickness of damage at flow points in the near wellbore area. Models of flow into perforations and gravel-packed tunnels provide a way to relate the location and severity of damage to the completion procedure that preceded it.
Well diagnosis is not just an evaluation of whether a well is damaged. Picking a potentially successful acidizing candidate involves not only the fact that a well is damaged but what kind of damage and where it is located around the wellbore. Damage is often most severe and localized at the point of flow entry into the wellbore. The improvement in damage analysis through well performance is rather recent, as evidenced by the work of several authors.  Most of this occurred through emphasis on improving gravel-packed completions in high-rate oil wells by means of multirate testing and improved wellbore models. Some of this work has focused on identifying specific damage mechanisms. 
Identify Extent/Type of Damage
To select the appropriate acid, one must diagnose the probable type of damage and the extent of penetration into the formation. Drilling solid infiltration is shallow (less than one in.); drilling fluid filtrate can invade the formation 3 ft or more. Perforation damage is shallow and varies in severity according to the perforating procedure. Water injection well damage can be quite deep when moderately clean fluids are injected over long periods of time with small unfiltered solids in the fluid. Likewise, incompatible fluids may precipitate deeper in the formation. Repeated acid treatments also may leave damage deeper in the formation. Shallow damage can be quite severe in that thin filter cakes or internal bridging under high differential pressure can have very low permeability. Deep damage is usually more moderate but can be quite difficult to reach with reactive fluids like acid and, thus, may require deep treatments like hydraulic fracturing or acid fracturing.
Familiarity with all sources of damage and damaging operations is a requisite tool for an engineer selecting the best remedial acid treatment and is beyond the scope of this chapter. Sparlin and Hagen provide good information on damage mechanisms and damage analysis in their SPE Short Course on formation damage. McLeod provides a damage check list. More information on damaging mechanisms and analysis is provided in the chapter on formation damage in this handbook. Recent examples of damage analysis and removal are provided by Fambrough et al.,  Zhu et al.,  and Guoynes et al. A recent article concerning well completion post-audits provides a means of pinpointing the time of occurrence and the operation that caused damage in a particular completion by analysis of fluid loss and injection data. 
Damage Removal by Chemical Solvents
Selection of a chemical for any particular application depends on which contaminants are plugging the formation. HCl acid and other acids do not dissolve pipe dope, paraffin, or asphaltenes. Treatment of these solids or plugging agents requires an effective organic solvent (usually an aromatic solvent like toluene, xylene, or orthonitrotoluene). Acetic acid effectively dissolves calcium carbonate scale; however, it does not dissolve ferric oxide (iron oxide) scale. HCl acid dissolves calcium carbonate scale quite easily but has little affect on calcium sulfate scales. Calcium sulfate can be converted to calcium carbonate or calcium hydroxide by treatment with potassium hydroxide or sodium carbonate. HCl acid then can be used to dissolve the converted scale. Several cycles of such treatment may be necessary to remove all the scale. Calcium sulfate also can be dissolved in one step with the sodium salt of ethylene diamine tetra acetic acid (EDTA), but at a higher cost. HF acid must be used to dissolve formation clay minerals or drilling-mud solids when they plug pore throats in the formation.
Because different plugging solids require different solvents for their removal, there is no universal solvent for wellbore damage. Treatment based on such a premise often yields disappointing results. Never pump solvent or acid into a well until the probable causes of damage and the best chemical to remove the damage have been defined. A summary solvent selection table is given in Table 7.3 for the type of damage. 
Formation Response to Acid
Even though damage has been identified and an appropriate acid or other cleaning agent is available to remove the damage, one must evaluate the probable response of the formation (its fluids and minerals) to either the acid or spent acid. There are many incompatibilities possible in acidizing various formations. These incompatibilities result in solid precipitates, which can plug pore throats so as to offset the improvement by acid dissolving pre-existing, damaging solids. Results can range from no bad effects and complete cleanup of damage to less than optimum improvement to plugging of the formation with acid-generated precipitates. As an example, a gas well producing 4 MMft3/D from a sandstone reservoir was acidized to improve production. The well flowed only 2 MMft3/D after acidizing. Post-treatment analysis showed that production was restricted by the small perforations (small inflow area) created with a through-tubing gun in underbalanced perforating; however, no permeability damage was present. Subsequent detailed petrographic core analysis indicated that a combination of acid-released fines and spent-acid precipitates damaged the formation during the acid treatment. Such incompatibilities are discussed next.
One can prevent acid-induced damage by predicting and dealing with formation response before acidizing. While it is sometimes easy to dissolve plugging solids, the real test of success is dissolving the solids without injecting or creating other damaging solids in the process. If potential incompatibilities between acid and formation solids or fluids are identified, precipitation of reaction products in the formation can be prevented or controlled.
Three properties of the formation are important: (1) Formation fluid analysis helps select appropriate displacement fluids to isolate formation fluids that are incompatible with either the acid or the spent acid products. (2) Formation matrix characterization identifies potential problems with acid treatments. (3) Formation mineralogy helps select the type of acid and its concentration.
Formation Fluid Compatibility
Formation fluid compatibility with both acid and spent acid must be considered in the treatment with acid. Formation water analysis is a standard test in laboratories, and chromatography is standard to identify gas compositions. Crude-oil analysis is much more complicated, so emulsion tests and sludge tests have been developed to identify incompatible crude oils.
Sulfate Ion Content
High sulfate-ion content exists in some formation waters. Spending HCl acid on carbonate generates a high concentration of calcium ions, which precipitates calcium sulfate when spent acid mixes with formation water containing more than 1,000 ppm sulfate ion. This can be prevented by preflushing the formation water away from the wellbore. In limestone acidizing, KCl or NaCl brines will work. In sandstone acidizing, NH 4 Cl brine must be used (KCl and NaCl are incompatible with spent HF acid). Such a preflush, combined with quick return of spent acid from the formation by swabbing, has improved response to acidizing in the San Andres dolomite formation in eastern New Mexico.
Bicarbonate Ion Content
High bicarbonate-ion content in formation waters causes precipitation of acid-dissolved scale. Treatment with an acid form of EDTA both removes calcium carbonate scale and prevents the recurrence of the scale for several months.
Crude-Oil Incompatibility (Sludge and Asphaltenes)
Some oils, particularly black asphaltic oils (less than 30°API), react with acid to form either damaging sludge (precipitated asphaltenes) or stable emulsions. Sometimes sludge preventers and emulsion breakers cannot prevent the formation of stable emulsions. Dissolved iron also creates more stable sludge and emulsions with these crude oils. Some difficult crudes need a preflush buffer of hydrocarbon solvent between crude oil and acid that is mutually compatible with both the crude oil and the acid. The buffer reduces contact between acid and the oil and prevents or reduces the problems with sludge and emulsions. Using this technique in one Wyoming oil field increased treatment success from 25 to 75%. Asphaltene particles can precipitate during production, and aromatic solvents can loosen and partially or completely dissolve them and also help acid dissolve solids. Presoaks with an aromatic solvent and producing back before acidizing have been helpful in treating wells drilled with oil-based mud. Organic skin damage in oil-producing wells is a major factor in the loss of productivity and revenue. pararffin and asphaltene deposition in the formation around the wellbore creates a barrier to oil flow. Better methods of problem identification and programs to remediate these problems have been developed in recent years. The potential sources of organic damage, problem identification test techniques, chemical selection, and application methods are discussed. 
Hydrogen sulfide can be present in the oil, gas, and/or water in any producing or injection well. Sulfide scavengers are effective in preventing incompatibilities and precipitation of iron sulfide. 
Formation Matrix Properties
Formation matrix analysis is more involved and can be critical to acidizing success. The most significant properties are the grain size distribution, cementation, and clay content, which control permeability. Formation permeability is needed to estimate the matrix injection rate and the risk of acid fracturing. Clay distribution is also important, as illustrated in Figs. 7.11 and 7.12. 
Fig. 7.11 depicts clean sand, dispersed shale or clay, laminated shale, and structural shale. The preferred formation is a clean, uniform size, pure quartz sand that is the simplest to acidize because no incompatibilities exist, and acid mostly dissolves damage like drilling mud or other solids. Dispersed clay exists as grain coatings, bridging clays, or pore-filling clays, as illustrated in Figs. 7.12 and 7.13.  These clays are highly reactive with HF acid and sometimes HCl acid (chlorite clay). All clays are much more reactive above 250°F. Clays control the HF acid spending rate and the undesired secondary and tertiary reaction products that are characteristic of HF acidizing in clay-rich sandstone. Laminated shale or clay is more isolated from HF reaction because it is impermeable. It prevents vertical flow of acid from perforations and also restricts near-perforation flow. Structural shale is rare but is present in some Pleistocene or recent sands and can cause matrix collapse and reduced permeability when acid softens the shale grains.
Fig. 7.11—Clay minerals in sandstone.
Fig. 7.12—Forms of shale by distribution.
Fig. 7.13—Three general types of dispersed clay.
The distribution and type of clay are characterized by petrographic analysis: thin sections, scanning electron microscopy, and x-ray diffraction analysis.  These tests are standard with most core-analysis companies and stimulation-service companies. When no cores are available, analyses are possible using drill cuttings. Permeability may also be analyzed with mercury injection testing of drill cuttings, and estimates of permeability can be made by statistical analysis of thin sections and scanning electron microscope (SEM) photographs. Permeability may also be estimated by certain log analysis programs and are based on porosity and clay content and water saturation (as an indicator of grain size).
Carbonates usually have no formation-compatibility problem because HCl acid dissolves carbonate easily and leaves a formation compatible brine as a reaction product. However, where anhydrite (a lower water content than gypsum) occurs in certain dolomitic carbonates, anhydrite dissolves in proportion to HCl-acid concentration and precipitates as acid spends. Even though a weaker HCl-acid concentration to reduce dissolution of anhydrite or calcium sulfate inhibitors are used, fluid recovery after treatment still must be rapid. Sandstone is more complicated because many minerals may exist with different precipitating products.
In sandstone acidizing, formation mineral content is important to the design of the HCl acid preflush, HF acid treatment, and overflush. Where high HCl-acid solubility exists (20% or more), HF acid should not be used. Formation damage often can be loosened by dissolving HCl-acid soluble compounds producing the released insoluble compounds. The use of HF acid in sandstone with a high-carbonate content produces voluminous solid precipitates. Gdanski and Schuchart questions HF acid use in formations with more than 10% carbonate.
Compounds of calcium carbonate, magnesium carbonate, and iron compounds are soluble in hydrochloric acid. Sufficient volumes of hydrochloric acid must be injected ahead of HF acid to dissolve all these acid-soluble materials before the HF acid or spent HF acid reaches them. The HF acid concentration is selected to prevent or reduce damaging precipitates as guided by recommendations in Table 7.4. 
Some minerals such as sodium feldspar will automatically precipitate fluoride compounds when more than 3% HF acid is used. Potassium fluosilicate will precipitate when more than 1.5% HF acid reacts with potassium feldspar. When HF acid is used in clay containing sandstone, hydrous silica precipitates. An overflush (displacement by compatible brine) displaces precipitated hydrous silica 3 to 5 ft away from the wellbore, where it will do the least amount of damage. As long as the precipitates move, the likelihood of permanent damage is reduced. Shutting in a well after HF-acid injection can result in the formation of more silica gel. When the well is returned to flow soon after the acid treatment, some of the precipitate near the wellbore may be produced and help clean up the formation. If too little hydrochloric acid preflush is used in formations with 5 to 15% carbonate, residual carbonate near the wellbore will react with spent HF acid (fluosilicic acid or aluminum fluoride) and cause excessive precipitation. These hydrated precipitates occupy more volume than that of the original clay and carbonate dissolved.
Dissolved iron minerals can precipitate in the formation. Ferric iron precipitates before acid spends to its normal pH of about 4. The precipitation of up to 10,000 ppm iron in solution may be prevented by adequate treatment with a complexing agent such as NTA, EDTA, citric acid, or combinations of acetic and citric acid. Damage from precipitated iron minerals is compounded by the high iron concentration that comes off the surface of the tubing during acid injection. New manufactured tubing has a crust of mill scale or magnetite, which is a form of ferric/ferrous oxide. This mill scale is loosened by the acid during acid injection. Particles of mill scale can then be injected into the perforations and may be trapped there. Injected acid continues to dissolve the mill, scale creating ferric chloride that enters the formation. This iron combines with iron from iron-oxide minerals, iron-rich chlorite clay, or other iron compounds in the formation to create more iron-hydroxide precipitates. This damage is lessened by pickling new tubing to remove mill scale and then circulating the pickling acid back out of the well before acidizing the formation. Older steel tubing stored outdoors (especially in coastal or marine environments) develop a coating of iron oxide (rust), which dissolves much faster in hot acid than does mill scale (iron magnetite).
Methods of Controlling Precipitates
Methods to control the precipitates caused by acidizing are acid staging, lower acid concentrations, and overflushing.
Preflush with either 5 to 15% HCl or 5 to 10% acetic acid. In formations with over 1% carbonate, an HC1 or acetic acid preflush dissolves the carbonate to prevent waste of HF acid and formation of the insoluble precipitate calcium fluoride. Calcium and sodium chloride workover brine also must be flushed away from the wellbore with HCl acid or ammonium chloride brine. Preflushes also displace and isolate incompatible formation fluids (either brine or crude oil). Higher concentrations of ammonium chloride (> 3%) are recommended where swellable smectite and mixed layer clays are present. 
Treat with an adequate volume of proper concentration HF acid. For successful HF acidizing, more than 120 gal/ft of HF/HCl acid is usually required. Less may be used where only shallow, moderate damage exists (e.g., 25 to 75 gal/ft is sometimes used on new perforations to remove damage or as a spearhead treatment in perforation breakdown prior to hydraulic fracturing in tight sandstone). The concentration, 3% HF to 12% HCl acid (often referred to as regular mud acid), is the usual concentration for damage removal in clean, quartzose sands. Concentrations of 0.5 to 1.5% HF are more effective in other clay containing sands. When the combined percentage of clay and feldspar is more than 30%, use 1.5% HF or less. In some low-permeability sandstone, HF concentrations as low as 0.5% HF have been used (e.g., the Morrow formation in Texas and New Mexico). If in doubt, consider an acid response test on a typical core or a geochemical acidizing simulator. See Table 7.4 for suggested acid concentrations that may be modified according to the information presented in the following sections.
Postflush or OverflushAn overflush displaces unreacted HF acid into the formation, displaces HF-acid reaction products away from the wellbore, cleans corrosion inhibitors to restore a water-wet condition and good oil/gas effective permeability, and re-establishes oil/gas saturation near the wellbore.
Typical overflushes for HF acid treatments are 3% ammonium chloride brine, weak acid (3 to 7.5% HCl acid) and filtered diesel oil or aromatic solvent (oil wells only) or nitrogen (gas wells only). The volume of overflush should be equal to or greater than the HF acid stage volume. For most wells, an overflush of at least 200 gal/ft displaces spent acid past the critical flow radius of 3 to 5 ft. This large overflush reduces near wellbore precipitation of amorphous silica. At formation temperatures of 200°F or more, this precipitation occurs while the HF acid is being pumped into the formation. This precipitate is somewhat mobile at first but may setup as a gel after flow stops. Overflushing with 3% ammonium chloride or weak acid dilutes and disperses precipitate away from the wellbore. Often, the overflush is 3% ammonium chloride with 10% ethylene glycol monobutyl ether (EGMBE) and a polyquarternary amine clay stabilizer. However, high-cation capacity clays may swell as a result of injecting preflushes or overflushes of brines or acid with concentrations lower than 4%. Where significant quantities of smectite and mixed layer clays are found, Gdanski and Schuchart recommend the use of 5% ammonium chloride brine. This is supported by the work of Al-Anazi et al. Gidley et al. state that carbon dioxide preflushes and overflushes also have proven effective in some wells. Other chemicals can be added to acid to prevent or reduce the precipitation of some compounds (e.g., iron complexing agents, sulfate scale inhibitors, and sludge preventers). Table 7.5 summarizes the steps to prevent or control incompatibilities in acidizing different formations and formation fluids. 
Recent work has provided additional field cases of new types of acid damage from minerals in the formation such as zeolite,  chlorite,  and carbonate minerals precipitating aluminum fluoride complexes created by HF acid.  The experimental works of Shuchart and others provide a better understanding of HF acid chemistry and precipitation of HF acid reaction products. Shuchart summarized HF acid reactions into primary, secondary, and tertiary reactions. The primary reaction for HF acid dissolves damage and whole clay with no precipitation.
In the secondary reaction, fluosilicic acid (a product of the primary dissolution of clay or silica by HF acid) dissolves clay in formation and precipitates hydrous silica. This reaction can reduce clay damage deeper in the formation. Stronger acid (12% HCl and 3% HF acid) creates higher silica concentrations from the primary dissolution of clays and silica, which precipitate in subsequent reactions deeper in the formation. In higher-temperature formations, this silica precipitates closer to the wellbore and reduces permeability.
In the tertiary reaction, HCl acid and aluminum fluoride complexes react slowly to dissolve clays and precipitate hydrous silica but proceed faster at temperatures in excess of 00°F. This reaction exacerbates post-acid scale precipitation. The slower tertiary reactions occur in most acid treatments in the 8- to 24-hour time period that the acid system typically remains in the formation.
Acid Treatment Design
Once you determine that a well is a good candidate for matrix acidizing and have selected appropriate acids, you are ready to design the treatment. Essentially, the design process is a systematic approach to estimating and calculating injection pressure and rate, volumes, and concentrations. Live HF acid usually penetrates only about 6 to 12 in. into the sandstone before spending. If acid can easily reach nearby plugging solids, small volumes of 25 to 50 gal/ft of HF-type acid can dissolve this damage; however, with more severe damage, more time and volume are needed to reach the plugging solids. Effective acid diversion reduces acid volumes needed.
Matrix Acidizing Design Guidelines
The recommended steps in treatment design are given next.
- Estimate safe injection pressures: determine present fracturing gradient, determine present bottomhole fracturing pressure, and determine allowable safe injection pressure at both the wellbore (at least 200 psi below fracturing pressure) and at the surface (tubing and wellhead pressure limitations).
- Estimate safe injection rate into the damage-free formation.
- Estimate safe injection rate into damaged formation.
- Select stages required for fluid compatibility.
- Calculate volume of each stage required: crude oil displacement, formation brine displacement, acetic acid stage, hydrochloric acid stage, hydrofluoric acid (HF and HCl acid) stage, and overflush stage.
- Select acid concentrations according to formation mineralogy. More detailed procedures with a calculated example are available in McLeod. Table 7.6 provides a one-page summary and guide to selecting fluid stages and volume.
Acid Type and Concentration
Permeability and mineralogy determine the compatible concentration of HCl or acetic acid in the preflush stage and HF and HCl acid in the HF-/HCl-acid stage. Guidelines for proper concentrations are provided in Table 7.4. The background for the acid-use guidelines in Table 7.4 is given in McLeod. These guidelines are not absolutes and probably should be modified according to more recent research. These guidelines were provided as a fairly conservative approach to avoid problems that could occur with 12% HCl and 3% HF that were regularly used prior to 1985. These guidelines helped when no previous experience existed in acidizing a particular formation. Evaluated experience provides the most reliable information. Acid flow tests with cores are reliable when long cores are used.  These tests are expensive and, therefore, seldom performed.
Gdanski recommends 13.5% HCl to 1.5% HF acid for high-feldspar sandstone and 9% HCl to 1% HF acid for clay-rich formations to prevent unwanted precipitation of fluoride scales. With more reactive clays and a higher carbonate content, acetic acid must be added to the acid mixtures to maintain a lower pH and reduce the amount of post-acid precipitation. For chlorite-rich sandstone, Simon and Anderson show the benefit of preflushing with 10% acetic acid and dissolving chlorite with 10% acetic and 1% HF acid. At temperatures higher than 200°F, Wehunt et al. recommend decreasing HF-acid concentration to 0.1% HF in 10% acetic acid at 380°F. However, at low temperature (less than 125°F), stronger acids are required to remove damage, and secondary and tertiary reaction precipitates are minor.
The guidelines in Table 7.4 do not specifically address permeability between 10 and 100 md, a range where field results have been erratic. Some treatments are very successful, and some result in little or no change. Proper selection is assisted by detailed petrographic studies, realistic core flow studies and/or reliable geochemical modeling. Pore throat sizes in these moderate-permeability formations are small enough to screen dispersed, undissolved clay-sized fines or spent acid precipitates and cause internal pore plugging. Recent research has helped to better define formation response to acids; however, as a practical matter, small hydraulic fracturing treatments are simpler and more cost-effective than matrix acidizing in some of these formations with permeability less than 50 md.
The guidelines for low permeability (less than 10 md) were based on treatments in which breakdown with acid probably occurred to open damaged perforations. The lower concentrations prevented massive precipitation in the formation and damage to the isolating cement yet were sufficient to clean up some perforation damage. Such treatments are probably obviated now by the advent of tubing-conveyed perforating.
Retarded HF Acids
Retarded HF (RHF) acids offer alternatives to the acids in Table 7.4, are less reactive with sandstone, and normally result in deep acid penetration into the formation. Three RHF acids that are based on boric acid, aluminum chloride, and a phosphoric acid were examined recently with guidance for their use.  A newer retarded sandstone acid is based on fluosilicic acid for deeper clay dissolution.  Fluosilicic acid can be injected by itself into a sandstone reservoir without causing any damage as long as it is blended into HCl acid or an organic acid. These acid mixtures improved the performance of two Brazilian water-injection wells by removing deep clay damage. A preflush of HCl or acetic acid must be used to dissolve carbonates ahead of the fluosilicic acid to prevent tertiary precipitation of calcium/aluminum fluoride complexes. In sandstone formations with more than 1% carbonate, the cost of sufficient acid preflush may prohibit treatment of damage beyond 2 ft in depth.
Several geochemical models exist today that provide guidance on acid type and concentration. The acidizing model of Thomas and Fannin predicts dissolution of rock to increase porosity and permeability and incorporates the resistance of a diverting agent to ensure good acid coverage in a layered sandstone formation. The model does not consider precipitation and relies on an expert system to choose appropriate acid types and concentrations. The model of Davies et al. is based on equilibrium chemistry and predicts the improvement in porosity and permeability by rock dissolution. It also predicts the porosity decrease by precipitation of species and the final permeability of the rock around the wellbore as a result of net dissolution. It helps select the volumes of acid required and the optimum acid types and concentrations to maximize well performance.
Gdanski and Schuchart developed a geochemical model for sandstone acidizing that is helpful to engineers dealing with acidizing of sandstone containing sensitive minerals like zeolite and chlorite clay and for formation temperatures above 200°F. Above 200°F, various organic acids are recommended for certain minerals.
Quinn et al. report on the application of a complex kinetic geochemical model to explore the importance of the formation minerals, mineral precipitation, and the effect of acid and injection rate. A new permeability prediction model relates the permeability of a permeable medium to the porosity, grain-size distribution, and the amounts and identities of all detrital minerals present and predicts productivity improvement. The optimal matrix stimulation is a compromise between maximizing the dissolution of the damaging minerals and minimizing secondary precipitation.
An integrated matrix stimulation model by Bartko et al. for sandstone and carbonate formations assists in determining formation damage, selection, and optimization of fluid volumes; provides a pressure skin response of the acid treatment; and forecasts well productivity.
Acid Placement and Coverage
A leading cause of unsuccessful acid treatment is failure to contact all the damage with the acid. Fluids pumped into a formation take the path of least resistance. In a typical treatment, most acid enters the formation through the least damaged perforation tunnels, as the schematic in Fig. 7.14 shows. 
Fig. 7.14—Acid entry into formation through perforations.
When this happens, it is easy to conclude that acidizing is very expensive and does not work well. Acidizing works well to remove damage when the type of damage is known, the treatment is designed properly, and it is properly executed. Extreme damage may require more than what is discussed. Actions required may include a chemical soak and swabbing the soak back before acidizing or reperforating, and/or fracturing to bypass damage.
Numerous methods help control acid placement. Selection is based on wellbore hardware, formation characteristics, and field experience. Additional guidelines are provided in McLeod. The four main types of zone coverage techniques in matrix acidizing are mechanical, particulate, viscosity, and density segregation. These methods also can be combined in treatments.
Opposed Cup Packer or Perforation Wash Tool
This perforation wash tool allows selective injection of acid into closely spaced perforations in high-permeability formations. High rate and/or pressure should be avoided when using either this tool or closely spaced straddle packers. High pressures can cause the cups to leak or turn over or the tool to separate at the port (the weakest part). High pressure can also establish communication behind the pipe between the point of injection and nearby perforations without removing damage from the plugged perforation. This type of isolation is best used for removing damage from severely plugged perforations in high-permeability formations. A field example of this technique in a Gulf Coast sandstone is given by McLeod and Crawford. 
Squeeze Packer and Retrievable Bridge Plug
A good method of isolating perforated intervals is to use a retrievable bridge plug and a squeeze packer. The bridge plug is set in blank sections of casing between perforated sections. The treatment usually begins with the lower set of perforations and finishes with the upper set. Straddle packers may be used in a similar way and have been used successfully in the Permian Basin to better clean damaged perforations.
Ball sealers can be divided into two categories: those heavier (sinkers) and those lighter (floaters) than the fluid. Successful use requires a good cement job on the installed casing and round good quality perforation holes. Sinkers have been used the longest and usually require 200% excess ball sealers and a high pump rate (greater than 5 bbl/min). The high pump rate usually prohibits their use in sandstone matrix acidizing, but they may be used in fracture acidizing or perforation breakdown. Floaters, or neutral-density ball sealers, provide excellent mechanical isolation for matrix acidizing at injection rates of 1 bbl/min or higher. The density or specific gravity of these ball sealers is matched to the fluid being pumped so better ball action will take place. Surface flowback equipment must be modified to catch the floating ball sealers during flowback.
Ball sealers are limited in their use. They are not used in long intervals with high-perforation density, wells perforated with more than 4 shots/ft, low-rate treatments (¼ to ½ bbl/min), and gravel-packed wells. Regardless of the type of treatment or ball used, treatment will be more effective when density of the ball is very close to the density of the fluid used in the treatment.
Pregravel-Pack Acid Treatments
One effective way to divert acid in a treatment before gravel packing is to use slugs of hydroxyethylcellulose (HEC) gel and gravel-pack sand. Ammonium chloride brine mixed with HEC at a concentration of 90 lbm/1,000 gal can be mixed in 5-bbl batches with 100 lbm of correctly sized gravel-pack sand. The combination of viscosity and sand packing helps divert acid to other perforations. The unique feature of this method, as opposed to other "particulate diverters," is that the perforation tunnel is packed with gravel-pack sand instead of some other material that would prevent gravel-pack slurry from entering the perforations during later slurry placement.
Soluble Particulate DivertersSelection of the optimal particulate diverter is based on the kind of fluid injected and/or produced. The diverter must be temporary and easily removed; otherwise, there will be a new kind of damage to be treated and removed. Oil-soluble resin (OSR) is one of today's more common diverting agents. OSR is slowly soluble in toluene, xylene, condensate, crude oil, and EGMBE (mutual solvent). OSR should be mixed on site with a blender and immediately pumped or added to the acid "on the fly" with a chemical injection pump. If OSR diverters are mixed off location or are allowed to stand for an hour or more, they will clump and may cause pump failure or plug perforations. OSR diverters should not be used with solvent-acid mixtures, which dissolve the resin enough to reduce its effectiveness. The chart in Fig. 7.15 shows the application of high concentrations of OSR to achieve significant pressure increases by more effective diverter action. The annular pressure (static column of fluid between the well tubing and coil tubing) shows pressure increases when diverter concentration increases.  Please refer to Brannon, Netters, and Grimmer for a full explanation. Shown in Fig. 7.16 are gamma ray logs before and after using radioactive tracers with OSR diverters in a California well.  Such tracers are excellent diagnostic tools to find where the acid is going. In this case, radioactive intensity shows that most of the acid bypassed the preferred interval and went behind the casing and entered a thief zone behind the pipe.
Fig. 7.15—Pressure response to acidizing using OSR diverter.
Fig. 7.16—OSR diverter evaluation radioactive tracer.
Benzoic acid flakes or powder are soluble in toluene, xylene, alcohol, and some condensate fluids. They dissolve very slowly in water/gas. Benzoic acid is often used because it is soluble in the fluids normally encountered in oil/water wells; however, if not well dispersed or mixed, it will plug perforations. Benzoic acid plugs do not dissolve fast because not enough fluid can flow by it to dissolve the plug. One well took 6 months to return to normal productivity after being treated with caked benzoic acid powder delivered to the location.
Thickening the acid through use of soluble polymers, nitrogen and foaming agents, or dispersing oil (either as loose two-phase mixtures or with emulsifiers) is useful in high-permeability formations with deep damage. Design is difficult; therefore, experience and on-site flexibility are important for success. Excellent results have been obtained with staged foam slugs between acid stages in high-permeability Gulf Coast gas wells to remove near-wellbore damage. This technique is so promising because the diverter (gas and fluid) disappears when the foam breaks with little chance of damage as with slowly dissolving particulates. See Gdanski and Behanna for useful guidelines.
Fadele et al. show that diverters often need not be used in gas wells because of the natural viscous diversion. Water and acid are 100 times more viscous than gas, and this provides a natural diversion for acid entering a gas formation. This may be one reason acidizing works better in gas wells than in oil wells. Other recent papers offer further improvements with viscous acids and diverters. 
Other significant factors are the rathole below the lowest perforation and the space just above the top perforation and below the packer. Rathole fluid should be heavier than the acid, and fluid above the top perforation should be lighter than the acid. If not, acid can end up in the rathole rather than the formation. Acid left in the borehole can cause casing leaks below the treated interval. Spotting acid over the perforations before injecting is very important in low to moderate permeability (10 to 50 md), and density segregation must be planned to achieve the best contact of acid with damaged perforations in these formations. Concentric tubing helps to achieve accurate placement of the acid in the wellbore to take advantage of density segregation.
Concentric tubing is preferred for matrix acid treatments because it allows the rathole to be circulated clean, permits better placement for acid contact with all perforations, bypasses production or injection tubing debris, can be acid cleaned on surface before running into the hole, and limits pump rate to 0.5 to 1 bbl/min because of fluid friction pressure in small tubing (1 to 1.5 in.).
Advances in Acid Diversion
The design and implementation of diverting systems has been advanced by recent design techniques but still relies on guidelines and field experience. Hill and Rossen have provided a better means to compare diverting methods and design diverting treatments. Gdanski and Behenna have provided some appropriate guidelines for foamed acids or foamed-diverter stages.
Hill and Rossen compared the techniques of injection rate diversion, coined MAPDIR (maximum pressure differential and injection rates); particulate diverting agents; viscosified fluids; and foamed acid. MAPDIR results in effective treatment of lower-permeability layers but at the expense of much larger volumes of acid. It may also be limited in use by pump and tubing capacities. Wells can clean up faster because no particulates are used. Also, treatment time is less to achieve the same reduction in skin factor as other techniques. The particulate diverting is most efficient in terms of volumes of acid and, thereby, is generally more economic if treating time is not a large economic factor. Oil soluble resins are not completely oil soluble, and sometimes plugging by these resins may not be temporary. Better quality assurance/quality control (QA/QC) is required for successful implementation. Quality assurance is the pretreatment planning to ensure that proper materials and procedures are used. Quality control is on-site supervision and testing to ensure that quality treatment is performed. Foam diversion is nondamaging in that surfactants are soluble and removable in produced water and nitrogen is recovered. Foams are most difficult to design and are not completely understood in terms of their behavior in different formations; however, guidelines for designing and implementing foam treatments are provided by Gdanski and Behenna.  Foams tend to be more stable in high-permeability layers and, therefore, reduce the acid losses in these layers. They also tend to be more stable in water zones and less stable in oil layers, providing some selectivity in treating wells with high water cuts or nearby bottom water. Viscosified fluids are similar to foam but provide a more consistent fluid hydrostatic pressure when well pressure limitations are present. The viscous behavior of these fluids in different formations is not well defined. These systems may be combined with MAPDIR when rate is limited by equipment.
Horizontal wells are special cases, which have been covered by Frick and Economides.  They emphasize how damage control and removal is just as important in horizontal wells as in vertical completions. Moderate damage can reduce horizontal well productivity to that below the productivity of an undamaged vertical well. The authors provide a stimulation technique employing coiled tubing. They also provide a design strategy for calculating volumes of acid required and the rate of coiled-tubing withdrawal during acid placement. A method of optimization for completion and stimulation of horizontal wells is also presented. Other papers have further advanced the planning, design, diversion, execution, and evaluation of acidizing horizontal wells employing similar methods to those used in vertical wells. 
An acid additive is any material blended with acid to modify its behavior. Because acid is so naturally corrosive, the development of an additive to reduce acid attack on steel pipe was the first requirement for successful acidizing. Development of a suitable corrosion inhibitor started the acidizing service industry in 1932. Comprehensive testing and application of corrosion inhibitors is still necessary in successful acidizing. Many acid additives are available, but those that are usually necessary are corrosion inhibitors, surfactants, and iron control agents. Any other additives are optional and should not be used unless specific well conditions dictate their use and have been thoroughly tested for compatibility with the formation fluids and the necessary additives. A mutual solvent in the overflush may be beneficial.
By nature of its adsorption on solid surfaces, the corrosion inhibitor is a surface-active agent with a unique purpose—to protect pipe rather than to change acid behavior in the formation. Corrosion inhibitors do not stop corrosion; they greatly reduce the reaction rate of acid with steel. Proper selection and application of corrosion inhibitors also reduce pitting (the tendency of acid to corrode or dissolve metal deeply in specific sites). Corrosion inhibitors are cationic and oil wetters. This is the mechanism by which they adsorb (plate out) on a metal surface and form an oil-wet film to protect the iron from exposure to acid. Plating out and oil wetting also occur in the formation, especially on clay minerals. To compensate for this, other additives, such as surfactants and mutual solvents, are used to restore water-wetness and maximize permeability to oil.
Pitting corrosion is very detrimental to the integrity of pipe. Reasons for pitting are inhibitor breakdown with time and temperature, insufficient inhibitor for wellbore conditions, and metal impurities in pipe. Factors that affect corrosion are pipe metallurgy, type acid, acid concentration, temperature, inhibitor solubility in the acid, inhibitor concentration, contact time with steel, inhibitor aids, and compatibility with other acids and additives such as organic acid, surfactants, alcohol, and solvent in the acid.
Service companies perform extensive lab testing in combination with additives to provide data to estimate the time of protection of pipe during the course of acid exposure to tubing in an acid treatment. The type of inhibitors and conditions in which they are used are many and complex. The engineer works closely with the stimulation specialist to ensure the proper selection and use of corrosion inhibitors in oil/gas wells. Usually, less than 5 mils of tubing corrosion should be allowed by the inhibitor in an acid treatment (equivalent to 0.025 lbm/ft 2 of tubing surface area) at temperatures less than 200°F.
Surface Active Agents
Surface active agents are molecules composed of an oil-soluble group and a water-soluble group. These chemicals lower the interfacial tension between the immiscible fluids. They also adsorb on rock surfaces and can alter the natural wettability of rock. Surfactants are classified into four major groups depending on the nature of the water-soluble part of the molecule. These divisions are anionic (water-soluble end is anionic), cationic (water-soluble end is cationic), nonionic (do not ionize—one end of molecule is water-soluble, the other is oil-soluble), and amphoteric (water-soluble end may be anionic, cationic, or uncharged depending on the pH of the system).
The primary use of surfactants is in emulsion prevention in acid/oil interactions. Other uses are as wetting agents, penetrating agents, sludge preventers and foaming agents, acid solvent dispersant, mud dispersants, emulsion breakers, retarders, and suspending agents. Surfactants should be tested for performance as emulsion breakers for crude/oil acid systems in both live acid and spent acid.
Iron control uses several different products to keep iron in solution: iron complexing agents, iron reducing agents, and hydrogen sulfide scavengers.
Iron in solution has two forms: ferric and ferrous. Ferric iron is often called iron (III), and ferrous iron is often called iron (II). The oxidized form, iron (III), precipitates in spent acid around a pH of 1 to 2. Iron (II) does not precipitate as ferrous hydroxide until a pH of 7 is reached, well beyond the final equilibrium of spent HCl acid, which is around a pH of 5. Normally, the ferrous iron is not a problem in acid treatments; however, there are three exceptions. If acid is pumped into a new well that has been drilled with caustic water-based mud, the mud filtrate in the formation may still have a pH of 11 or higher. Mixing of spent acid with this mud filtrate precipitates ferrous hydroxide. Ferrous iron also precipitates in a sour environment where hydrogen sulfide is dissolved in the brine, oil, or natural gas. The only effective remedy to keep iron (II) in solution where hydrogen sulfide exists is to use a hydrogen sulfide scavenger to make the sulfide unavailable for precipitating ferrous sulfide at a pH of 2. Complexing agents do not prevent the precipitation of iron sulfide.  A third problem long term is the presence of iron (II) in the presence of undissolved calcium carbonate. Iron (II) can precipitate slowly as ferrous carbonate—a slowly forming carbonate scale. This usually does not impede flow in carbonate rocks but may in sandstone with excess carbonate because the sand grain matrix can screen the precipitate. Addition of acetic acid to the preflush maintains a low-pH environment to prevent the iron carbonate precipitation.
Ferric oxide and ferrous sulfide are frequently found in water-injection wells in surface pipe, tubing and borehole, and in the formation. The iron oxide is present from air contamination in the injected water. Iron sulfide is present from bacterial action in the injected water or formation. Ferric oxide is common in all acid treatments. The main source is a coating of mill scale or rust on the surface of the tubing or piping used in stimulation. This is usually the source of the most damaging iron concentrations in acid. Iron-complexing agents can only complex iron concentrations of up to 10,000 ppm. Acid can dissolve iron from tubing walls as high as 100,000 ppm. No complexing agent can complex this much iron. Two important steps in controlling iron in acidizing are pickling treating strings prior to acidizing and using iron reducing agents. Acid pickling treatments are covered later in the section on job execution; however, the purpose of pickling tubing is to clean the tubing of easily dissolved iron and bring it back to the surface for disposal. This procedure reduces the amount of ferric iron in solution during the subsequent injection of acid into the formation.
Iron-Reducing AgentsThe most common iron-reducing agent is erythorbic acid—a cousin to vitamin C. Erythorbic acid is added to the acid to reduce any ferric ion to ferrous iron before it enters the formation. The use of a reducing agent does not take the place of acid pickling the treating string. Even though pickling removes most of the easily dissolvable iron oxide from the tubing, enough iron oxide remains after pickling so that a reducing agent is still necessary during the acid treatment. Some formations contain iron oxide in the formation so that iron complexing agents are still needed along with the reducing agent as a safeguard. The complexing agents most commonly used are shown in Table 7.7.  One of the favorite iron-control agents is the combination of citric and acetic acid. Citric acid by itself is limited to 15 lbm/1,000 gal of acid because of limited solubility in the acid. Acetic acid permits mixing higher loadings of citric acid (up to 100 lbm/1,000 gal) and also maintains a low pH in spent acid to keep iron (III) in solution. Improved techniques and procedures have advanced the control of dissolved iron in acid treatments. 
Hydrogen Sulfide Control
Common chelating agents are ineffective for iron control in sour environments. Systems containing hydrogen sulfide contain only ferrous iron [iron (II)] species. The only effective method of preventing precipitation of iron sulfide during sour-well acid treatments is to remove hydrogen sulfide from the fluid with sulfide scavenger products. If there is any possibility of ferric iron [iron (III)] being injected from surface containers or pipe, a reducing agent should be added in the acid to reduce the dissolved iron (III) to iron (II).
The "other" category of additives consists of those that are optional for special conditions and are not commonly needed in all treatments. They should not be used unless they have been thoroughly tested for compatibility with all formation fluids. These additives are mutual solvents, clay stabilizers, acid diverting agents, calcium sulfate scale inhibitors, and gelling agents.
Mutual SolventsA mutual solvent is soluble in either oil or water. For this reason, it is very effective in sandstone acidizing, in which it is important to keep all solids water-wet. Mutual solvents are either EGMBE or other modified glycol ethers. They improve the solubility of corrosion inhibitors in the spent acid in the formation and compatibility of inhibitors with emulsion preventers and other additives. The most important property is to reduce the adsorption of corrosion inhibitors on residual clay particles in the formation and to help maintain water-wetting for maximum oil/gas flow after acidizing. A mutual solvent also reduces residual water saturation (spent acid) following a treatment. Gas wells clean up better by keeping surfactants in solution rather than adsorbing on sand and clay too near the wellbore.
Alcohol. Methyl alcohol and isopropyl alcohol have been used for many years to aid in cleaning up water-blocked gas wells. On occasion, 10 to 20% alcohol is used in acid to stimulate moderately low-permeability (5 to 50 md) gas sands to speed the cleanup of spent acid. The normal concentrations of mutual solvents and alcohol are listed in the Table 7.8. 
Clay minerals or other fines may move in the formation, particularly during water production. Also, some clays can be dispersed or swell when contacted with fresh water or low-salinity brines.Cationic polymers are sometimes used in brine or acid to stabilize clays. These cationic polymers do not oil-wet sands because the end of the molecule projecting from the adsorbed end is water soluble. Clay stabilizers used include polyquaternary amines, polyamines, and cationic surfactants. Polyquaternary amines have been the most effective, with polyamines second. The use of cationic surfactants for clay control is not recommended except in water-injection wells in water-sensitive formations. A wide variance in opinion exists as to how to best apply these products. Clay stabilizers are most often used in the overflush following an HF-acid treatment in sandstone formations. Most of the clay stabilizers are not affected by HCl acid but are dislodged by HF acid. It is not recommended to use more than 20 gal/1,000 gal.
Acid Diverters. Diverting agents (discussed earlier) are best used in acidizing damaged perforations so that acid is distributed more evenly to all perforations regardless of the degree of plugging or variations in permeability. The diverting agents should ideally be either degradable or partially soluble in produced oil and/or water. Uses in gas wells are limited and difficult to clean up; foamed acid is a better means of diversion in gas wells. Some guidelines for diverter use are listed in Tables 7.9and 7.10.
Calcium Sulfate Inhibitors
When acidizing formations with a high-sulfate-ion content in the formation water (usually greater than 1,000 ppm) or rock containing anhydrite, it is advisable to include a calcium sulfate inhibitor in the acid. The inhibitor is usually phosphonic acid, polyacrylate, or other material.
Acids may be thickened for diversion during acidizing with soluble polymers such as xanthan (a biopolymer) or acrylamide polymers. Higher viscosity may be obtained with crosslinking metal ions or ligands. Certain surfactants may be used to thicken acid through the formation of surfactant micelles.
In 1999, Coulter and Jennings updated industry experience in the use of acids and additives. Many chemical additives are proprietary compositions, but the service company has detailed instructions for mixing and use. It also has facilities and personnel to carry out acid and additive testing for well treatment. The operating engineer's knowledge of the well and the reservoir and the service company engineer's knowledge of chemical products and treatment processes are required to recommend appropriate treatment fluids. This partnering improves the quality of acid treatments.
The key to successful job execution is thorough and effective job supervision. The operating company responsible for supervising the job must prepare the well before the service company administers the acid treatment; monitor the progress of the project before, during, and after the treatment; and properly evaluate the results. The most important tasks associated with job supervision are those related to safety, well preparation, and quality control.
Safety and Environment Protection
The main safety precautions for those on site during an acid treatment concern detection of leaks and proper handling of acid. Pressure tests are performed with water or brine to ensure the absence of leaks in pressure piping, tubing, and packer. Leaks on the surface can endanger service personnel, and subsurface leaks can cause subsequent corrosion of tubing and casing in the annulus. Anyone around acid tanks or pressure connections should wear safety goggles for eye protection. Those handling chemicals and valves should wear protective gauntlet-type, acid-resistant gloves. Fresh water and spray washing equipment should be available at the job site. In case of acid contact with the eyes, immediately flush eyes with clean water and consult a physician. If acid contacts the skin, wash the area of contact with water for 15 minutes. Consult a physician immediately after flushing if hydrofluoric acid comes in contact with skin or eyes. Wear self-contained, full-face, fresh-air masks when potential hydrogen sulfide gas hazards exist. Also, testing equipment and appropriate safety equipment should be on hand to monitor the working area and protect personnel in the area. Special scrubbing equipment may be required for removal of toxic gases. Further information on safety with acid can be found in API Bull. D15, Recommendations for Proper Usage and Handling of Inhibited Oilfield Acids and in Data Sheet 634, Safe Well Stimulation by Acidizing from the National Safety Council. 
Proper handling and disposal of acid and spent acid products should be observed. Often, environmental hazards can be reduced or prevented by the proper choice of chemical additives at optimum concentrations. The acid flowbacks are normally processed in a test separator. Oil goes to the water/oil separation system, and the aqueous phase is filtered and treated with activated carbon for overboard disposal in accordance with regulatory guidelines of oil and grease measurements. This process, used in many offshore operations, is described in an article by Ali.  Regulatory guidelines are available to control and monitor discharges of well workover fluids containing oil or grease. Overboard discharges must meet 42 mg/L daily maximum and 29 mg/L monthly average oil and grease limits. There are no acute and chronic toxicity measurement requirements at present.
Treating fluids must leave surface tanks, travel through surface pipe and well tubing, enter a wellbore, and pass through the perforations into the formation so that the solvent can react with the damaging solids. Each of these components through which the fluid travels must be properly cleaned before pumping acid into the formation. Surface tanks must be cleaned before being filled with acid. The best tanks are rubber lined and cleaned of any formerly contained materials before the new acid and additives are added to the tank. Surface lines through which the acid is pumped should be cleaned with acid before the treatment. A small amount of acid can be flushed through the lines and into waste containment before final hookup for the well treatment. This also can be accomplished in the step for acid cleaning well tubing.
The well should be adequately prepared before the service company arrives on site to perform the acid treatment. If possible, wellbore fill should be circulated out to remove any solids and sludge that have accumulated in the rathole and/or isolated by placing a heavy brine in the rathole prior to acidizing. If the formation pressure is very low, care must be taken to prevent the loss of accumulated sludge and other materials to the formation. Any fluid-loss additives selected should dissolve in the produced well fluids, such as oil-soluble resins or benzoic acid particulates.
Fluids used to load the well prior to injecting acid should be filtered to a "superclean" state to prevent any damage during injection testing before acidizing—typically to less than 50 ppm for solids and less than 2 microns for size. No produced lease water should be used because these produced waters usually are contaminated with emulsion breakers or corrosion inhibitors often found in water/oil separation facilities and may also contain suspended solid hydrocarbons and clay particles. Emulsion breakers and corrosion inhibitors in produced water can oil-wet the formation and reduce productivity, and suspended solids are very damaging.
Acid Cleaning TubingIn addition to borehole cleanout, acid clean the tubing and surface piping before injecting acid into the formation to prevent plugging of the perforations by solids released from the tubing. Fig. 7.17 shows the characteristics of acid being pumped down tubing in a well. 
Fig. 7.17—Cleaning tubing with acid.
Pumping acid through tubing releases solids deposited on the pipe surface. Acid-insoluble solids like pipe dope, pararffin, asphalt, and gypsum or barite scales may plug the perforations and even fill the wellbore. Acid-soluble solids like calcium carbonate may just spend the acid, whereas dissolved iron oxide or iron sulfide may precipitate as the acid spends on other minerals in the formation. Either acid cleaning the tubing and reversing to surface containment or bypassing the production tubing with an acid-cleaned concentric tubing string prevents perforation plugging from tubing deposits.
The dissolution of mill scale and/or rust in the tubing can theoretically lead to concentrations as high as 75,000 ppm in acid, and field acid cleaning tests confirmed this. Iron complexing agents can prevent ferric hydroxide precipitation from acid with up to 10,000 ppm iron.
For high-pressure reservoirs, acid may be pumped down the tubing close to the bottom and then flowed back to the surface containment. If the reservoir pressure will not hold the acid hydrostatic column, foamed acid may be used to clean the tubing, or a work string can be run with a packer, isolation valve, and circulating tool to isolate the formation while acid cleaning the tubing. If a work string is not used and if the production tubing cannot be cleaned properly, it should be bypassed using a concentric tubing string to pump the acid.
A concentric tubing string can be used to circulate accumulated sludge below the perforated interval with clean brine before acid injection. Injection wells may have accumulated corrosion deposits and/or bacterial slimes. Producing wells may have loose scale deposits, hydrocarbon solids, or produced formation fines. Recent papers have provided additional guidance on tubing cleaning and pickling.
Quality control checks before, during, and after pumping increase the probability of acidizing success. Onsite supervisors are encouraged to check the equipment.
- Inspect all tanks that will be used to hold acid or water. The tanks must be clean. Small amounts of dirt, mud, or other debris can destroy any acid job.
- Make sure the service company has the equipment to circulate the acid tank prior to pumping. This must be done to avoid emulsion problems and to protect the tubing. Acid corrosion inhibitors and other additives can separate to the top of the tank in as little as 2 hours.
- The line to the pit or tank should be laid and ready to connect to the wellhead so the acid can be backflowed immediately after the end of the overflush.
When in doubt that the formation will take acid, inject a compatible "superclean" filtered brine to test the ability of the formation to take fluid. If the test shows severe damage, the operation may be changed to include an acid minisqueeze prior to the main acid job to make sure that the formation is open to fluid. Zhu and Hill showed that a pretreatment test could be used to evaluate permeability and skin factor prior to treatment. The monitoring program followed evolution of skin even with diversion effects. The program is reliable and flexible for acquiring and processing data, calculating skin, and diagnosing matrix acidizing treatments.
Sampling and Titration
Sampling of all pumped fluids for solids content and acid titration for HCl- and HF-acid concentration should be performed on site as a quality control measure. Samples of spent acid should be analyzed for pH immediately and then kept in airtight containers for chemical analysis. Large variations in acid concentrations delivered to the well site have been found. Delivered acid concentrations are usually more accurate and consistent when a known on-site titration program is to be used. Premixed acid should be rolled and circulated to make sure that all additives are properly dispersed and that none, especially corrosion inhibitors, have separated and floated to the top of acid tanks or have sunk to the bottom. Titration of acid is an excellent test to see whether acid is well mixed. In one case, 15% HCl acid was sampled and titrated to show 6% HCl acid. The acid tank was "rolled" to mix well and titrated again. This time, it titrated as 15% HCl acid. Poorly-mixed acid can result in highly varied acid concentrations (5 to 25% in an average 15% HCl-acid mix) with similar variations in corrosion inhibitors and other additives. Such a variable mix will exacerbate corrosion, emulsion problems, and acid/formation interactions. Also, high acid strength can harm tubing and certain formations. Surfactants should be checked to ensure that they leave the rock minerals in a water-wet condition for optimum oil flow.
Injection-Rate Control and Monitoring
The main acid job should be circulated in place with HCl acid placed across the formation before the packer is set or before the bypass valve is closed. All perforations should be covered by acid before injection starts. Injection should start at a predetermined injection rate and the pressure observed to determine the condition of the wellbore. If the pressure rises close to the pressure limit, the rate should be cut in half until the pressure stabilizes at a level below the formation fracturing pressure. When the HF acid stage reaches the formation, a pressure drop is normally observed. The rate should not be changed as long as a positive pressure is observed at the wellhead. If the well goes on vacuum, the rate should be instantly raised until a positive pressure is observed at the wellhead. Hold the new rate steady as the acid is injected. Nevertheless, the constant injection rate of HF acid into the wellbore should not exceed an optimum ½ bbl/min unless the perforated interval is greater than 25 ft. If the formation is very thick, the rate can be 0.02 bbl/min per foot of net pay. Other authors have different opinions on allowable injection rates, as discussed later.
Pressure Behavior During Acid Injection
Two pressure responses are often observed during acid treatment. Fig. 7.18 shows one response.  In this well, when acid hit the formation, pressure dropped immediately. As the pressure dropped, the rate was increased; then the pressure began to rise. The rate was reduced, and then the well was shut in while another batch of acid was mixed on site. Injection was restarted at a rate of 2 bbl/min, then cut back to 1.5 bbl/min and stabilized at 2 bbl/min for the final injection of overflush. Rate should be held constant for a period of time at least until the pressure stabilizes. Haphazard changes in rate make it impossible to determine on site what the quantitative response of the well is to the acid treatment, unless newer computer models and monitoring equipment are available, as discussed later. A better-controlled acid treatment is shown in Fig. 7.19.  Here, the rate is stabilized at 0.55 bbl/min. When the HF acid stage entered the formation, the pressure slowly declined but stayed above 0 psi. This rate was continued as long as the pressure was observed and is the type of response that one should observe when a well is treated to remove wellbore damage.
Fig. 7.18—Acid treatment with poor rate control.
Fig. 7.19—Acid treatment with good rate control.
When the overflush reaches the formation, the rate may be increased as fast as allowed, as long as the pressure stays below the fracturing pressure. The faster overflush rate will push the spent acid deeper into the formation and overdisplace the spent acid reaction products more efficiently away from the wellbore. This safely finishes the treatment and allows the spent acid to be produced back sooner. The well should be flowed immediately, unloaded with nitrogen, swabbed back, or put on artificial lift.
On-Site Evaluation of Acid Treatment Effectiveness
The pressure and rate chart of the acid treatment show the effect of acid volume on the formation as the acid treatment proceeds. The papers of McLeod and Coulter,  Paccaloni et al.,  and Prouvost and Economides are significant to the on-site evaluation of acidizing treatments. On-site data monitoring follows and evaluates the progress of damage removal by acid. Fig. 7.20 shows injection rate and pressure plotted on a precalculated chart of pressure vs. rate and crossplotted with a family of skin-factor curves based on steady-state injection. The successive points clearly show the reduction in skin factor. These plots may be somewhat misleading because pressure transients are ignored after rate changes; however, no on-site computer is required.
Fig. 7.20—Matrix acid pressure chart with job evaluation.
Fig. 7.21 shows rates, pressures (both measured and simulated), and skin-factor change during acidizing, as presented by Prouvost and Economides.  This method requires an onsite computer but considers pressure transient effects when rate is changed. Such plots are a tremendous help in analyzing on-site acidizing performance and in follow-up well analysis. More information is also available in the excellent text on stimulation by Economides and Nolte.  McLeod and Coulter presented the first example of injection pressure buildup analysis before and after acidizing cleanup in Figs. 7.22 and 7.23. Calculation to obtain formation permeability before and after acidizing are shown with data in Tables 7.11 through 7.14.
Fig. 7.21—Skin evolution during acid job.
Fig. 7.22-Injection pressure buildup with wellbore damage.
Fig. 7.23-Injection pressure buildup with damage removed.
Hill and Zhu advanced the monitoring of acidizing treatments, building on the earlier contributions of McLeod and Coulter,  Paccaloni et al.,  and Prouvost and Economides.  The use of the inverse injectivity diagnostic plot permits the real-time evaluation of treatments and further assists in post-treatment evaluations. Montgomery et al. proposed more active treatment monitoring into standard acidizing practice.
Zhu, Hill, and Morgenthaler and Hill and Zhu provide good field examples of monitoring acid treatments with concurrent skin evolution for both diverted and nondiverted treatments. Monitored on-site evaluation was later confirmed with well-flow analysis of post-treatment well performance. However, more work is needed on evaluating causes of treatment failures or skin increases.
Spent Acid Production Control
The well should be produced first at the same rate before acidizing. As soon as the well has cleaned up and all spent acid has been recovered or reduced to zero water cut, the producing rate may be increased. In formations with moveable fines, the rate should be increased once each week to finally reach the optimum producing rate for that well. Increasing the rate gradually helps the return of any dispersed solids and prolongs the improvement for the acid treatment.
Ali et al. discussed a method to minimize production facility upsets offshore by special handling of the returned acids at the surface. The cost of fluid handling is further reduced by optimizing use of additives with improved laboratory testing procedures.  This was stimulated by the work of Bansal. 
Produced Fluid Sampling
Spent acid samples should be collected at the surface to properly analyze the response of the well to the acid treatment. These samples should be analyzed for pH immediately and then kept in airtight containers for chemical analysis. Chemical analysis of these samples can provide information for use in evaluating why a well did not respond to acid treatment. If precipitates or emulsions are a problem, the return samples will show the reason. Whatever solids are precipitating to cause possible damage to the rock around the wellbore may be present in these collected samples. Steps can be taken to reduce precipitation by changes in acid concentration, preflush fluids, and/or additives in the next scheduled treatment.
Analysis of well flowback may indicate problems and concerns not readily evident otherwise. Such problems may arise from acid or spent acid mixing with lost completion brines and/or formation water, significant dissolution of carbonates, and total consumption of acid. The insight obtained helps to design optimum formulations for future treatments. 
A comprehensive HF acidizing radial flow model was modified by Gdanski and Schuchart to account for deep-matrix mixing and back production of sandstone-acidizing treating fluids. Deep matrix mixing may require back production of at least two treatment volumes of aqueous fluid to recover the spent injected acids. Matching the ionic return profiles can provide information about formation mineralogy and excess precipitation.
To summarize, on-site supervision of acid treatments is critical to successful acidizing. Long treatments can best be controlled by two persons—one to coordinate the acid schedule and rate and pressure control, and the other to check materials; titrate acid; and monitor volumes, rates, and pressures. The engineer who recommended and designed the job and the supervisor who prepared the well for acidizing make a good combination. Good data and record keeping greatly help the job of evaluating acidizing results.
Evaluation of Acid Treatments
The evaluation process encompasses six major areas on which to focus when assessing job performance and acid treatment success:
- Injection rate and pressure.
- Final fall-off pressure record.
- Well production analysis (nodal analysis).
- Produced fluid samples.
- Post-treatment investigation concerning damage incurred during injection, acid removal of damage, post-treatment damage (precipitates), and verbal communications.
- Recommendations for continuous improvement.
The most important measure of the treatment is the productivity of the well after treatment. When the productivity stabilizes at the same production rate as before treatment, the flowing bottomhole pressure should be estimated from fluid levels or from measured flowing pressures. Static bottomhole pressure should be measured following any long shut-in periods. A well flow analysis should show whether the designed productivity was obtained. The pressure charts from the treatment, including both accurate injection rates and recorded injection pressures, can be analyzed using transient pressure analysis to determine when or if the wellbore damage was removed by the treatment. An injectivity index can be calculated for the well both before and after the HF-acid stage. The final overflush injection pressures and rates should give a fairly accurate measure of the well productivity before the well is ever returned to production. A useful source of information is the final pressure falloff after the treatment. If the pressure exists at the wellhead, the falloff pressures should be recorded on site until the well goes on vacuum. If the well goes on vacuum too soon, fluid levels can be shot with a sonolog device until the level falls to near the static bottomhole pressure. These final falloff pressures can be used to estimate the wellbore condition after the acid treatment. If this analysis shows that the acid treatment removed all wellbore damage, the treatment is potentially successful if later well production analysis shows that no post-acid precipitation occurred. An example of this type analysis is shown in the example provided by McLeod. 
If the well injectivity or productivity (after the well returns to injection or production) is not close to that predicted by the falloff analysis, some damage probably occurred to the formation after the acid treatment ended. Subsequent damage after the treatment may be caused by precipitation of acid reaction products in the formation or by return of fines to the wellbore with internal pore plugging at or near perforations. This is especially true in gravel-packed wells.
First, it is important to know that the treatment removed the damage in the wellbore during treatment as intended. If damage occurred after the treatment, steps can be taken to prevent that damage in a later treatment of that well or others in the reservoir by such steps as utilizing different additives to keep reaction products in solution, overflushing the reaction products deeper into the formation, using different acids or acid concentrations to prevent the excess precipitation of acid reaction products, or using stabilizers to prevent fines from returning to the wellbore and reducing productivity.
If the anticipated productivity was achieved, the acid treatment worked as designed. If not, the entire treatment should be reviewed to analyze the causes. Often, unsatisfactory performance results from imperfect coverage during the treatment. A change in the acid placement technique may be necessary for the next acid treatment in the field. If solid diverting agents were employed, changes in concentrations may be necessary, or perhaps another diversion technique would work better. Feasibility and economic analysis from the expected well production increase determine whether these changes are worthwhile.
The engineer evaluating the treatment should individually discuss the treatment with the service company supervising engineer and the operating company supervisor. Their observations lead to future treatment improvements.
The acid treatment report and the pressure/rate treatment charts are the best sources of information. The engineer can observe and follow the injectivity during the entire process to see whether the injectivity decreased during the treatment. Plugging or reduced injectivity during the first injection into the wellbore can be traced to solids suspended in injected fluids at the beginning of the treatment. The condition of the well, well preparation, and QC sampling can reveal the source of these plugging solids.
Usually, the damage during an acid treatment occurs at the time the first acid hits the formation. This first acid damage is usually caused by solids removed from the tubing walls prior to the acid reaching the formation. Also, acid may react adversely with some of the minerals in the formation, and perhaps a different acid or solvent (such as acetic acid or an aromatic solvent) should be used to first contact the formation. Many acid failures are caused by the elimination of needed wellbore preparations prior to the acid treatment.
Nitters et al. present a systematic approach for candidate selection, damage evaluation, and treatment selection and design using a recently developed integrated software package. They recognize the importance of evaluating skin factors from well tests to determine what could be improved. After identifying damage mechanisms, they used an expert system and geochemical simulator to select appropriate treatment fluids. They also developed software for the evaluation and design of acid placement.
Hashem et al. produced an excellent example of a complete strategy for acidizing. Well analysis and sampling identified the damage mechanisms that were removed by the appropriate acid systems and additives that were selected using formation mineralogy, extensive laboratory testing with core flood studies, and acid and additive testing. Well preparation, job supervision, and on-site monitoring played key roles in the success of the acid treatments. Treatment evaluations were performed to identify problems with some acid treatments, which led to improved additive formulations and improved spent-acid cleanup procedures. These steps resulted in an 86% success rate in treatment of water-injection wells and significantly improved water injectivity.
To summarize, successful acidizing is assured by proper treatment design, well preparation, and execution, which includes significant practices: acid cleaning of tubing; acid type and concentration designed for the mineralogy and the permeability of the formation; acids, additives, and solvent flush designed for proper acid/reservoir fluid compatibility; properly prepared wellbore and effective acid coverage; sufficient time provided for acid contact and penetration of all perforations; and precipitation prevented or flushed away from the wellbore.
Treatment evaluation leads to problem identification and to continuously improved treatments. The prime source of information on which to build an evaluation are the acid treatment report and the pressure and rate data during injection and falloff.
The tasks of execution and evaluation go hand in hand. Proper execution, quality control, and record keeping are prerequisites to the task of accurate evaluation. Evaluation of unsatisfactory treatments is essential to recommending changes in chemicals and/or treating techniques and procedures that will provide the best treatment for acidizing wells in the future. This implies a program for continuous improvement.
One may feel overwhelmed by the details in executing successful acid treatments. This is true of any complex oilfield operation such as cementing, perforating, gravel packing, or hydraulic fracturing. Acidizing has often been treated with a cavalier attitude because the treatments can be relatively inexpensive in some areas. Past acid treatments have been successful without much care. That was true because completions were so bad in the early days of acidizing that some production improvement was fairly easy. Today, completions are much better planned and executed, and there is less tolerance for poor stimulation processes. Experience with acid in a field is a starting point. If a particular formation or reservoir has a history of successful acidizing with a particular system and products, many of the recommendations herein may not be necessary. Modern completion analysis programs can evaluate the success of past jobs and can establish whether improvements are needed. If acidizing has been unsuccessful in certain areas, the systematic process presented in this chapter may provide solutions to that lack of success.
|B||=||formation volume factor (reservoir volume/stock tank volume)|
|c||=||fluid compressibility, vol/vol/psi|
|F||=||fracture initiation pressure, psi|
|h||=||formation thickness, ft|
|H||=||formation thickness, ft|
|ka||=||acidized formation permeability, md|
|kd||=||damaged formation permeability, md|
|kf||=||formation reservoir permeability, md|
|kh||=||product of k and h, md ft|
|m||=||slope of pressure buildup on semilog paper, pressure change per log cycle of time, psi/cycle|
|p1hr||=||pressure at time of 1 hour on pressure buildup line, psi|
|pf||=||fracturing pressure, psi|
|pi||=||injection pressure, psi|
|pwf||=||flowing wellbore pressure, psi|
|Pr||=||static reservoir pressure, psi|
|q||=||flow rate or injection rate, B/D|
|Q||=||injection rate, bbl/min|
|r||=||radial distance from wellbore, ft|
|rw||=||wellbore radius, ft|
|S||=||apparent skin factor (includes effect of non-Darcy flow in gas flow)|
|Δps||=||additional pressure drop from damaged zone, or skin, psi|
|μ||=||fluid viscosity, cp|
|ϕ||=||formation porosity, fraction|
SI Metric Conversion Factors
|°API||×||141.5/(131.5 + °API)||=||g/cm3|
|bbl||×||1.589 873||E – 01||=||m3|
|cp||×||1.0*||E – 03||=||Pa•s|
|ft||×||3.048*||E – 01||=||m|
|ft3||×||2.831 685||E – 02||=||m3|
|°F||(°F – 32)/1.8||=||°C|
|gal||×||3.785 412||E – 03||=||m3|
|in.||×||2.54*||E + 00||=||cm|
|lbf||×||4.448 222||E + 00||=||N|
|lbm||×||4.535 924||E – 01||=||kg|
|psi||×||6.894 757||E + 00||=||kPa|
Conversion factor is exact.