Formation Damage Control and Remediation
Selection of Treatment Fluids
As expressed by Thomas et al. (1998),*
The type and location of the damage must be determined to select the proper treating fluids . . . Additionally, precautions should be taken to avoid further damage. Damage can be from emulsions, wettability changes, a water block, scale, organic deposits (paraffin and asphaltenes), mix deposits (a mixture of scale and organic material), silt and clay, and bacterial deposits. In most cases, the type or types of damage cannot be precisely identified with 100% accuracy. However, the most probable type or types can be determined; therefore, most matrix treatments incorporate treating fluids to remove more than one type of damage. The selection of the treatment fluids depends on the specific applications and purposes. The treatment fluid volumes are usually determined by means of laboratory core tests and mathematical models. Treatment fluids should contain various additives for various purposes. Thomas et al. (1998) explain the issue of additives as following:
Although proper fluid selection is critical to the success of a matrix treatment, the treatment may be a failure if the proper additives are not used. The major treating fluid is designed to remove the damage effectively. Additives are used to prevent excessive corrosion, sludging and emulsions, provide uniform fluid distribution, improve cleanup, and prevent precipitation of reaction products. Additionally, additives are used in preflushes and overflushes to stabilize clays, disperse paraffins and asphaltenes and inhibit scale and organic deposition. Additive selection is primarily dependent upon the treating fluid, the type of well, bottom-hole conditions, the type of tubulars, and the placement technique . . . Diverters are essential to obtain uniform fluid distribution in a horizontal well. The volume of each additive used is dependent on the specific problem addressed. For example, surfactants are commonly used at 0.2 to 0.5% to lower surface and interfacial tension and provide water wetting. As a rule, the minimum amount of additive should be used. Normally, the recommended concentration is determined in the laboratory and is based on testing (i.e., nonemulsifiers, anti-sludge agents).
Clay Stabilization
When clays are exposed to low salinity solutions, two mechanisms cause formation damage (Himes et al., 1991). Swelling clays imbibe water into their crystalline structure and enlarge in size and plug the pore space. Mobilization, migration, and deposition of clays can plug the pore throats. Himes et al. (1991) describe the desirable features of effective clay stabilizers, especially for applications in tight formation as following:
1. The product should have a low, uniform molecular weight to prevent bridging and plugging of pore channels.
2. The chemical should be nonwetting on sandstone surfaces to reduce water saturation.
3. It should have a strong affinity for silica (clay) surfaces to compete favorably with the gel polymers for adsorption sites when placed from gelled solutions and to resist wash-off by flowing hydrocarbons and brines.
4. The molecule must have a suitable cationic charge to neutralize the surface anionic charges of the clay effectively.
Inorganic Cations (1C)
Clay stabilization can be maintained by the aqueous solution salinity above that of the connate water (Himes et al., 1991). Figure 23-1 by Himes et al. (1991) shows the clay stabilizing effectiveness of various brines. The basal spacing versus the salt concentrations are shown as an indication of clay swelling, measured by x-ray diffraction (XRD). The clay will disperse when the basal spacing is greater than 21A (Himes et al., 1991). In this respect, Figure 23-1 indicates that the clays are stable even at very low concentrations of K+ and NHj cations; whereas, a sufficiently high concentration of Na+ cation is necessary to maintain clay stability.
Therefore, K+ and NHj are natural clay stabilizers, but are not permanent because they can be exchanged with Na+ (Himes et al., 1991). Figure 23-1 shows that calcium ion can maintain clay stability, but it is not preferred as a clay stabilizing agent because it may react with formation brines and chemical additives (Himes et al., 1991). Cesium cation (Cs+) is also very effective at low concentrations, but it is very rare and expensive (Khilar and Fogler, 1985; Himes et al., 1991). Damage resulting from clay swelling and mobilization, migration, and redeposition can be prevented by adding certain ions to stabilize the clays in workover and injection fluids (Keelan and Koepf, 1977). Five percent solutions of CaCl2 and KCl, and hydroxy-aluminum (OH-Af) may be effective (Keelan and Koepf, 1977).
Cationic Inorganic Polymers (CIP)
In order to provide somewhat permanent clay stabilization, cationic inorganic polymers (CIP) such as hydroxyl aluminum and zirconium oxychloride, have been introduced (Reed, 1974; Valey and Coulter, 1968; Coppell et al., 1973; Himes et al., 1991). These agents provide resistance to cation exchange, but they are applicable for clay stabilization in noncarbonate containing sandstones and the formation should be retreated after acidizing (Himes et al., 1991).
Cationic Organic Polymers (COP)
Quaternary cationic organic polymers (COP) are used for effective and permanent stabilization of clays (especially smectite clays), and controlling fines and sand in sandstone as well as carbonate formations (Himes et al., 1991). They are applicable in acidizing and fracturing treatments. They provide permanent protection because of the availability of multiple cationic sites of attachment. However, their applicability in tight formations is limited to low concentrations (Himes et al., 1991). They can cause permeability damage by pore plugging because these high molecular weight and long-chain polymers have molecular sizes comparable with the some pore size fractions in porous rock. They can also increase the irreducible water content of porous rock because they are hydrophobic and water-wetting. Their effectiveness is substantially lower in gelledwater solutions used for hydraulic fracturing and gravel-packing as indicated by Table 23-1 by Himes et al. (1991) because of gel competition for adsorption on clay surfaces.
Oligomers
Oligomers are low-molecular-weight, cationic, organic molecules having an average of 0.017 \lm length (Penny et al., 1983; Himes et al., 1991). Oligomers offer many potential advantages over the cationic organic polymers for clay stabilization (Himes et al., 1991). Availability of many repeating sites and high affinity for clay surfaces enables better competition of oligomers with gels in water used for hydraulic fracturing and gravel-packing. Because of their smaller size compared to pore size, the treatment-imposed permeability damage is significantly reduced. Because they are only slightly water-wetting (contact angle is 72°), the irreducible water content is also reduced. Zaitoun and Berton (1996) examined the effectiveness of cationic polyacrylamides (CPAM) and nonionic polyacrylamides (PAM) for stabilization of montmorillonite clay by means of the critical salinity concentration method (CSC). As schematically depicted in Figure 23-2 by Zaitoun and Berton (1996), the polymers prevent fines migration by coating over the pore surface and
blocking the clay particles. They determined that low-molecular-weight polymers have comparable stabilizing capability to high-molecular-weight polymers and are more advantageous because they cause less treatmentinduced permeability damage. Kalfayan and Watkins (1990) used organosilane compounds as additives to acid systems to prevent the weakening of the rock by acid dissolution. This additive undergoes a hydrolysis reaction to form silanols, which tie to the silanol sites present on siliceous mineral surfaces and forms a polysiloxane coating to bind clay and siliceous fines in place.
pH-Buffer Solutions
Buffering is an effective means of pH control by maintaining the hydrogen ion activity constant in spite of the changing conditions. Buffer capacity expresses the sensitivity of pH of an aqueous solution to adding a strong base (Gustafsson et al., 1995). Hayatdavoudi (1998) hypothesizes that alteration of kaolinite to dickite, nacrite, and halloysite, through chemical oxidation according to the following reactions, may be responsible for fines generation, at high pH in the presence of alkali hydroxides.
Therefore, Hayatdavoudi (1998) recommends buffering the pH of brines to 8 or below and avoid aeration of injected fluids to prevent kaolinite comminution-induced formation damage. Hayatdavoudi (1998) also recommends adding ammonium chloride and/or ammonium sulfate buffers to prevent silicate dissolution at high pH environments.
Clay and Silt Fines
The fluid selection studies conducted by Thomas et al. (1998) have indicated that:
1. The sandstone formation damage can be treated by fluids that can dissolve the materials causing the damage.
2. The carbonate (limestone) formations are very reactive with acid and, therefore, the damage can be alleviated by dissolving or creating wormholes to bypass the damaged zone. If there is a silt or clay damage, HCl should be used to bypass the damage. The damage by calcium fluoride recipitation cannot be treated by HCl or HF acid treatment.
Formation damaged by silt and clay fines introduced by drilling, completion or production operations require different acid treatment recipes that vary by the formation type, location of damage and temperature (Thomas et al., 1998). Recipes recommended for acidizing of carbonate (limestone) formations are outlined in this article by Thomas et al. (1998). Motta and Santos (1999) proposed that certain blends of fluosilicic acid (H2SiF6) with hydrochloric acid (HCl) or an organic acid, such as acedic acid (//Ac) can dissolve clays and feldspars without reacting with the quartz. These systems remove deep clay damage in sandstone formations, without the usual adverse effects of the secondary precipitation reaction encountered in conventional acidizing by HF or H2SiF6 alone. Motta and Santos (1999) have determined that properly designed acid blends can substantially reduce the skin in the field. Gdanski and Shuchart (1996) have shown that the equilibrium condition between fluosilicic acid and
hydrochloric acid controls the extent of the primary and secondary reactions of hydrofluoric acid with the aluminum silicates. Fluobaric acid (HBF4) is a retarded acid, which reacts with the alumina layers of clays to form a borosilicate film. The borosilicate film prevents the migration of in-situ clay and silt fines at high shear-rates of flow because the borosilicate film stabilizes the fine particles in petroleumbearing formations (Thomas and Crowe, 1978; Colmenares et al., 1997). The fluoboric acid can be effective for applications extending 3 to 5 feet from the wellbore (Ezeukwu et al., 1998).
Bacterial Damage
Bacteria growth in injection wells can cause many problems including plugging of the near-wellbore formation. Johnson et al. (1999) recommend the use of 10-wt% anthrahydroquinone disodium salt in caustic to control the growth of sulfate-reducing bacteria (SRB) combined with the traditional biocide treatment for control of other types of bacteria. For example, bacteria-induced formation damage in injection wells can be treated using a highly alkaline hypochlorite solution, followed by a HCl overflush for neutralization of the system (Thomas et al., 1998).
Inorganic Scales
Scales can be removed by various methods. Carbonate scales can be dissolved by HCl, organic acids, and dihydrogen ethylenediamine tetraacetic acid. Iron scales can be dissolved using HCl and an iron stabilizer. When FeS is present, iron reducing and chelating (or sequestering) agents should be added to the treatment fluid to avoid any precipitation (Thomas et al., 1998). Chelating agents chemically bind the hydrated metal ions and change the reactivity of these ions and, therefore, prevent precipitation of iron (III) hydroxide at pH > 2.5 (Brezinski, 1999). The reaction of ferric ion with hydrogen sulfide causes sulfur precipitation. Reaction of ferrous iron with H2S above pH =1.9 causes FeS precipitation. Scale inhibitors may also interfere with the crystallization phenomena by blocking the sites available for crystal growth and prevent the adhesion of scales to metal surfaces (Meyers et al., 1985).
Brezinski (1999) has demonstrated that some of the frequently used chelating agents, such as ethylenediaminetetra acedic acid (EDTA) and nitrilotriacedic acid (NTA), may not be effective in downhole temperature conditions because they may decompose at temperatures at or above 250°F. Therefore, Brezinski (1999) recommends removing H2S using a hydrogen sulfide scavenger as the only method of preventing FeS production. Scale inhibitor squeeze method is resorted to prevent the precipitation of inorganic salts, including barium/strontium/calcium sulfates, calcium/ barium/magnesium carbonates, and calcium fluoride. The effectiveness of the scale inhibitors is severely reduced at high temperature and pressure environments prevailing at most wellbore conditions because of thermal decomposition. In fact, the thermal stability studies with several inhibitors, such as penta and hexa-phosphonates, phosphino polycarboxylate (PPC), polyvinyl sulfonate (PVS), and sulfonated polyacrylate copolymer (SPC), conducted by Graham et al. (1997), indicate that they are stable up to 175°C. Hydroxide scales can be dissolved by HCl and organic acids, sulfate scales can be dissolved gradually by EDTA, chloride scales can be dissolved by aqueous solutions of weak HCl or brine, and silica scales can be dissolved using mud acids (Thomas et al., 1998).
Organic Deposits
Organic deposits, such as paraffins and asphaltenes, can be dissolved with aromatic solvents, mutual solvents, blends of aromatic and mutual solvents or their dispersion in water (Thomas et al., 1998). Asphaltine flocculatization and deposition can be prevented by adding resins and aromatics (Leontaritis et al., 1992). Samuelson (1992) has demonstrated that combined non-aromatic solvents yield the best solvent performance. Barker et al. (1999) tested solvent treatment for removal of the paraffin deposits and applied crystal modifier squeezing to prevent paraffin crystallization.
Mixed Organic/Inorganic Deposits
Mixed organic/inorganic deposits can be dissolved using acid dispersed in an organic solvent (Thomas et al., 1998).
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