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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
- Inhibitor solubility in the acid
- Inhibitor concentration
- Contact time with steel
- Inhibitor aids
- 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/ft2 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)
- 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
- 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
- Hydrogen sulfide scavengers
Iron in solution has two forms:
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.
The 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 1.  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
- Gelling agents
A 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.
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 2. 
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
- 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.
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 3and 4.
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.
- ↑ 1.0 1.1 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. http://dx.doi.org/10.2118/54721-MS.
- ↑ Hall, B.E. and Dill, W.R. 1988. Iron Control Additives for Limestone and Sandstone Acidizing of Sweet and Sour Wells. Presented at the SPE Formation Damage Control Symposium, Bakersfield, California, 8-9 February. SPE-17157-MS. http://dx.doi.org/10.2118/17157-MS.
- ↑ Taylor, K.C., Nasr-El-Din, H.A., and Al-Alawi, M.J. 1999. Systematic Study of Iron Control Chemicals Used During Well Stimulation. SPE J. 4 (1): 19–24. SPE-54602-PA. http://dx.doi.org/10.2118/54602-PA.
- ↑ Al-Dahlan, M.N. and Nasr-El-Din, H.A. 2000. A New Technique to Evaluate Matrix Acid Treatments in Carbonate Reservoirs. Presented at the SPE International Symposium on Formation Damage Control, Lafayette, Louisiana, 23-24 February 2000. SPE-58714-MS. http://dx.doi.org/10.2118/58714-MS.
- ↑ McLeod, H.O. 1986. Matrix Acidizing to Improve Well Performance. Short Course Manual. Richardson, Texas: SPE.
- ↑ King, G.E. and Holman, G.B. 1985. Quality Control at Well Site Optimizes Acidizing Economics. Oil & Gas J. 83 (11): 139.
- ↑ Coulter, G.R. and Jennings, A.R.J. 1999. A Contemporary Approach to Matrix Acidizing. SPE Prod & Fac 14 (2): 144–149. SPE-38594-PA. http://dx.doi.org/10.2118/38594-PA.
Noteworthy papers in OnePetro
Rostami, A., and Nasr-El-Din, H.A. 2009. Review and Evaluation of Corrosion Inhibitors Used in Well Stimulation. Presented at the SPE International Symposium on Oilfield Chemistry, 20-22 April, The Woodlands, Texas. SPE 121726.
Nasr-El-Din, H.A., and Al-Humaidan, A.Y. 2001. Iron Sulfide Scale: Formation, Removal and Prevention. Presented at International Symposium on Oilfield Scale, 30-31 January, Aberdeen, United Kingdom. SPE 68315.
Taylor, K.C., and Nasr-El-Din, H.A. 2001. Laboratory Evaluation of In-Situ Gelled Acids for Carbonate Reservoirs. Presented at SPE Annual Technical Conference and Exhibition, 30 September-3 October, New Orleans, Louisiana. SPE 71694.
Safwat, M., Nasr-El-Din, H.A., Dossary, K., McClelland, K., and Samuel, M. 2002. Enhancement of Stimulation Treatment of Water Injection Wells Using a New Polymer-Free Diversion System. Presented at Abu Dhabi International Petroleum Exhibition and Conference, 13-16 October, Abu Dhabi, United Arab Emirates. SPE 78588.
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