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Formation evaluation for acidizing

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Since the most common use of matrix acidizing is the removal of formation damage, it is important to understand the nature of the damage that exists so that an appropriate treatment can be designed.

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. [1][2][3][4][5][6][7][8][9][10][11] 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.[8][9][10]

Identify extent and 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 typically shallow (less than one in.); drilling fluid filtrate can invade the formation multiple feet. Perforation damage is shallow and varies in severity according to the perforating procedure and conditions. 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 cause solids precipitation deeper in the formation. Repeated acid treatments also may leave damage in the formation. Even shallow damage can be quite severe in that thin filter cakes or internal bridging under high differential pressure can be of very low permeability. Deep damage is usually more moderate but can be quite difficult to reach with reactive fluids such as acid and, thus, may require deep treatments such as hydraulic fracturing or acid fracturing (primarily limited to carbonate formations).

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 page. McLeod[12] provides a damage check list. More information on damage mechanisms and analysis is provided in Formation damage. Recent examples of damage analysis and removal are provided by Fambrough et al., [13] Zhu et al., [14] and Guoynes et al.[15] 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. [16]

Damage removal by chemical solvents

Selection of a chemical for any particular application depends on which contaminants are plugging the formation. Hydrochloric (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 such as xylene, or terpenes. Acetic acid can effectively dissolves calcium carbonate scale; however, it does not dissolve ferric oxide (iron oxide) scale. HCl acid dissolves calcium carbonate scale more 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 partially dissolved in one step with high pH carboxylic acid salt solutions but at a higher cost. Hydrofluoric (HF) acid must be used to dissolve formation clay and siliceous fine minerals or drilling-mud solids when they plug formation pore throats.

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 1 for the type of damage. [12]

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, especially in sandstone formations with HF acid solutions. 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.

Formation properties

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:

  • Formation fluid analysis helps select appropriate displacement fluids to isolate formation fluids that are incompatible with either the acid or the spent acid products.
  • Formation matrix characterization identifies potential problems with acid treatments.
  • 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, Potassium chloride (KCl) or Sodium Chloride (NaCl) brines will work. 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. In sandstone acidizing, NH4Cl brine must be used (KCl and NaCl are incompatible with spent HF acid).

Bicarbonate ion content

High bicarbonate-ion content in formation water can lead to precipitation of scale when contacted by spent acid. Treatment with an acid form of a carboxylic acid (e.g., EDTA) both removes calcium carbonate scale and can prevent the recurrence of the scale for at least several months.

Crude oil incompatibility

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. [17][18]

Hydrogen sulfide

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.[19]

Formation matrix properties

Formation matrix analysis is more involved and can be critical to acidizing success. The most significant properties are those that control permeability:

  • Grain size distribution
  • Cementation
  • Clay content

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. 1 and 2. [20][21]

Fig. 1 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. 2 and 3. [22] 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.

The distribution and type of clay are characterized by petrographic analysis[23] :

  • Thin sections
  • Scanning electron microscopy
  • 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).

Formation mineralogy

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 usually 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[24] 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 2. [25]

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
  • 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).


  1. McLeod, H.O.J. 1983. The Effect of Perforating Conditions on Well Performance. J Pet Tech 35 (1): 31–39. SPE-10649-PA.
  2. Unneland, T. and Waage, R.I. 1993. Experience and Evaluation of Production Through High-Rate Gravel-Packed Oil Wells, Gullfaks Field, North Sea. SPE Prod & Oper 8 (2): 108-116. SPE-22795-PA.
  3. Unneland, T. and Larsen, L. 1995. Limitations of the Skin Concept and Its Impact on Success Criteria Used in Sand Control. Presented at the SPE European Formation Damage Conference, The Hague, Netherlands, 15-16 May 1995. SPE-30093-MS.
  4. McLeod Jr., H.O. and Crawford, H.R. 1982. Gravel Packing for High Rate Completions. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 26-29 September 1982. SPE-11008-MS.
  5. Landrum, W.R., Burton, R.C., MacKinIay, W.M. et al. 1996. Heidrun - Results from Pre-Completed Techniques ells Using Innovative Gravelpacking. Presented at the Offshore Technology Conference, Houston, Texas, 6-9 May. OTC-8087-MS.
  6. Burton, R.C., Rester, S., and Davis, E.R. 1996. Comparison of Numerical and Analytical Inflow Performance Modelling of Gravelpacked and Frac-Packed Wells. Presented at the SPE Formation Damage Control Symposium, Lafayette, Louisiana, 14-15 February 1996. SPE-31102-MS.
  7. Burton, R.C., MacKinlay, W.M., Hodge, R.M. et al. 1996. Evaluating Completion Damage in High Rate, Gravel Packed Wells. Presented at the SPE Formation Damage Control Symposium, Lafayette, Louisiana, 14-15 February 1996. SPE-31091-MS.
  8. 8.0 8.1 McLeod Jr., H.O. 1994. Monitoring and Analysis of Gravel-Packing Procedures To Explain Well Performance. J Pet Technol 46 (10): 878-883. SPE-27356-PA.
  9. 9.0 9.1 Blok, R.H.J., Welling, R.W.F., Behrmann, L.A. et al. 1996. Experimental Investigation of the Influence of Perforating on Gravel-Pack Impairment. Presented at the SPE Annual Technical Conference and Exhibition, Denver, Colorado, 6–9 October. SPE-36481-MS.
  10. 10.0 10.1 Rajah, B., Linder, R., and Todd, B. 1995. Experiences And Results Of Acid Prepacking And Gravelpacking Wells In The West Lutong Field In Sarawak, Malaysia. Presented at the SPE Asia Pacific Oil and Gas Conference, Kuala Lumpur, Malaysia, 20-22 March 1995. SPE-29290-MS.
  11. McLeod, H.O. 1992. The Application of Spherical Flow Equations to Gravel-Pack Evaluation. Paper SPE 23769 presented at the 1992 SPE Formation Damage Control Symposium, Lafayette, Louisiana, 26–27 February.
  12. 12.0 12.1 McLeod, H.O. 1986. Matrix Acidizing to Improve Well Performance. Short Course Manual. Richardson, Texas: SPE.
  13. Fambrough, J.D., Lane, R.H., and Braden, J.C. 1995. A Comprehensive Approach for Stimulating Produced Water Injection Wells at Prudhoe Bay, Alaska. Presented at the SPE International Symposium on Oilfield Chemistry, San Antonio, Texas, 14-17 February 1995. SPE-28976-MS.
  14. Zhu, D., Radjadhyax, N., Hill, A.D. et al. 2001. Using Integrated Information to Optimizing Matrix Acidizing. Presented at the SPE European Formation Damage Conference, The Hague, Netherlands, 21-22 May 2001. SPE-68930-MS.
  15. Guoynes, J., Azari, M., Squire, K. et al. 1999. Damage-Specific Stimulation Techniques Provide Maximum Deliverability Improvement in Four Gas-Storage Reservoirs—A Case Study. Presented at the SPE European Formation Damage Conference, The Hague, Netherlands, 31 May-1 June 1999. SPE-54726-MS.
  16. McLeod, H.O.J. and Pashen, M.A. 1997. Well-Completion Audits to Evaluate Gravel-Packing Procedures. SPE Drill & Compl 12 (4): 228–237. SPE-31088-PA.
  17. Newberry, M.E. and Barker, K.M. 2000. Organic Formation Damage Control and Remediation. Presented at the SPE International Symposium on Formation Damage Control, Lafayette, Louisiana, 23-24 February 2000. SPE-58723-MS.
  18. King, S.R. and Worley, H.W. 2000. Have We Forgotten Oil is Not Inert? Guidelines for Enhancing Stimulation Success. Presented at the SPE Permian Basin Oil and Gas Recovery Conference, Midland, Texas, 21-23 March 2000. SPE-59541-MS.
  19. Brezinski, M.M. 1999. Chelating Agents in Sour Well Acidizing: Methodology or Mythology. Presented at the SPE European Formation Damage Conference, The Hague, Netherlands, 31 May-1 June 1999. SPE-54721-MS.
  20. 20.0 20.1 Pittman, E.D. and Thomas, J.B. 1979. Some Applications of Scanning Electron Microscopy to the Study of Reservoir Rock. J Pet Technol 31 (11): 1375-1380. SPE-7550-PA.
  21. 21.0 21.1 Poupon, A., Clavier, C., Dumanoir, J. et al. 1970. Log Analysis of Sand-Shale SequencesA Systematic Approach. J Pet Technol 22 (7): 867-881. SPE-2897-PA.
  22. 22.0 22.1 Neasham, J.W. 1977. The Morphology of Dispersed Clay in Sandstone Reservoirs and Its Effect on Sandstone Shaliness, Pore Space and Fluid Flow Properties. Presented at the SPE Annual Fall Technical Conference and Exhibition, Denver, Colorado, 9-12 October 1977. SPE-6858-MS.
  23. Kalfayan, L.J. and Metcalf, A.S. 2000. Successful Sandstone Acid Design Case Histories: Exceptions to Conventional Wisdom. Presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, 1-4 October 2000. SPE-63178-MS.
  24. Gdanski, R.D. and Shuchart, C.E. 1998. Advanced Sandstone-Acidizing Designs With Improved Radial Models. SPE Prod & Fac 13 (4): 272–278. SPE-52397-PA.
  25. McLeod, H.O.J. 1984. Matrix Acidizing. J Pet Technol 36 (12): 2055–2069. SPE-13752-PA.

Noteworthy books on Acidizing

Kalfayan, L.J.: Production Enhancement with Acid Stimulation (PennWell Books; 2000, 2007).

Noteworthy papers in OnePetro

Nasr-El-Din, H.A., Al-Mutairi, S.H., Al-Hajji, H.H., and Lynn, J.D. 2004. Evaluation of a New Barite Dissolver: Lab Studies. Presented at the SPE International Symposium and Exhibition on Formation Damage Control, 18-20 February, Lafayette, Louisiana. SPE 86501.

External links

Sparlin, D.D. and Hagen, R.W. 2004. Formation Damage Prevention. Short Course Manual. Houston, Texas: International Completion Consultants Inc.

See also

Matrix acidizing

Acidizing candidates

Acid treatment design