Aluminum Scaling and Formation Damage due to Regular Mud Acid Treatment
Abstract: This paper was selected for presentation by an SPE Prcgram Committee following review of information contained in an abstract submitt~by the author(s), Conten& of the paper, as presented, have not ken revie~d by the~iety of Petroleum Engineers and are subject to correction by the author(s), The material, as presented, does not necessarily reflect any psition of the~iety of Pe!roleum Engineers, ita officers, or membara. Papem presented at SPE meetings are subject b publication review by Edtorial timm%tees of th… Show more
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Field results indicate that the Jauf reservoir, a deep, high temperature illitic sandstone, is sensitive to conventional mud acid treatments. As a result, an extensive study was performed to better understand the problem. The focus of this paper is on core flow tests using various inorganic and organic preflushes and mud acid (HCl - HF) systems. Interpretations of the core tests results are supported by chemical, XRD, SEM, and Thin Section analyses. A detailed description of the mineralogy of cores prior to and following an acid treatment is presented with emphasis on precipitation of reaction products, fines migration and other potential damage mechanisms. Chemical analyses indicated that the HCl preflush extracted the majority of the aluminum during a conventional mud acid treatment. As a result, the Si/Al ratio during the subsequent mud acid stage is a false indicator of hydrated silica precipitation. Additionally, precipitation can occur in acid effluent collected during a core test once the fluid cools to ambient temperature. This results in an erroneous Si concentration and impacts numerous calculations and "conclusions" i.e., reaction kinetics, amount of silica precipitation, etc. The same analogy applies to flowback samples that are used to postulate various downhole phenomena. Although potassium hexafluosilicate was present in core effluents, it was not present in the cores based upon XRD, SEM, and Thin Section examination. Potassium hexafluosilicate was identified as two distinct crystal structures i.e., cubic and pyramidal. SEM examination showed that most cores exhibited severe alteration of illite and chlorite to yield a significant quantify of clay residue including fines. The residue, severely degraded potassium feldspar (microcline) and quartz fines created formation damage subsequent to treatments with 12 wt% HCl – 3 wt% HF mud acid. This paper supports the literature in some cases yet spotlights some possible flaws in our understanding of sandstone acidizing. Introduction Wells completed in the pre-Khuff (Jauf) reservoir have the potential to deliver a significant quantity of sweet gas. The Jauf retrograde gas reservoir, located in eastern Saudi Arabia, exhibits a bottomhole temperature from 280 to 300°F and is normally greater than 14,000 feet deep with 8600 to 8800 psi reservoir pressure.1 Table 1 indicates the Jauf reservoir in Well "A" is primarily composed of quartz, but contains significant amounts of potassium feldspar (microcline) and clay minerals including illite, chlorite, and illite/montmorillonite mixed-layer clay. Note greater than 95 wt% of the mixed-layer illite/montmorillonite clay is illite. This complex mineralogy suggests that the formation may be "sensitive" to aqueous fluids i.e., damaged during drilling, completion and workover operations. This is supported by field and laboratory experience. Previously, it was reported that the Jauf reservoir was "water-sensitive" and easily damaged by fresh water.2 Lynn concluded that a minimum concentration of 5 wt% KCl was required during drilling to minimize formation damage. Field experience complements Lynn's work i.e., a well completed in the Jauf reservoir was drilled with a low chloride content mud and perforated in a fresh water mud to yield a skin damage of greater than thirty. An attempt to remove the formation damage incorporating a 15 wt% HCl preflush to 12 wt% HCl – 3 wt% HF (mud acid) was not successful and production decreased by 40%. This study was initiated to address damage removal in the Jauf formation.
Field results indicate that the Jauf reservoir, a deep, high temperature illitic sandstone, is sensitive to conventional mud acid treatments. As a result, an extensive study was performed to better understand the problem. The focus of this paper is on core flow tests using various inorganic and organic preflushes and mud acid (HCl - HF) systems. Interpretations of the core tests results are supported by chemical, XRD, SEM, and Thin Section analyses. A detailed description of the mineralogy of cores prior to and following an acid treatment is presented with emphasis on precipitation of reaction products, fines migration and other potential damage mechanisms. Chemical analyses indicated that the HCl preflush extracted the majority of the aluminum during a conventional mud acid treatment. As a result, the Si/Al ratio during the subsequent mud acid stage is a false indicator of hydrated silica precipitation. Additionally, precipitation can occur in acid effluent collected during a core test once the fluid cools to ambient temperature. This results in an erroneous Si concentration and impacts numerous calculations and "conclusions" i.e., reaction kinetics, amount of silica precipitation, etc. The same analogy applies to flowback samples that are used to postulate various downhole phenomena. Although potassium hexafluosilicate was present in core effluents, it was not present in the cores based upon XRD, SEM, and Thin Section examination. Potassium hexafluosilicate was identified as two distinct crystal structures i.e., cubic and pyramidal. SEM examination showed that most cores exhibited severe alteration of illite and chlorite to yield a significant quantify of clay residue including fines. The residue, severely degraded potassium feldspar (microcline) and quartz fines created formation damage subsequent to treatments with 12 wt% HCl – 3 wt% HF mud acid. This paper supports the literature in some cases yet spotlights some possible flaws in our understanding of sandstone acidizing. Introduction Wells completed in the pre-Khuff (Jauf) reservoir have the potential to deliver a significant quantity of sweet gas. The Jauf retrograde gas reservoir, located in eastern Saudi Arabia, exhibits a bottomhole temperature from 280 to 300°F and is normally greater than 14,000 feet deep with 8600 to 8800 psi reservoir pressure.1 Table 1 indicates the Jauf reservoir in Well "A" is primarily composed of quartz, but contains significant amounts of potassium feldspar (microcline) and clay minerals including illite, chlorite, and illite/montmorillonite mixed-layer clay. Note greater than 95 wt% of the mixed-layer illite/montmorillonite clay is illite. This complex mineralogy suggests that the formation may be "sensitive" to aqueous fluids i.e., damaged during drilling, completion and workover operations. This is supported by field and laboratory experience. Previously, it was reported that the Jauf reservoir was "water-sensitive" and easily damaged by fresh water.2 Lynn concluded that a minimum concentration of 5 wt% KCl was required during drilling to minimize formation damage. Field experience complements Lynn's work i.e., a well completed in the Jauf reservoir was drilled with a low chloride content mud and perforated in a fresh water mud to yield a skin damage of greater than thirty. An attempt to remove the formation damage incorporating a 15 wt% HCl preflush to 12 wt% HCl – 3 wt% HF (mud acid) was not successful and production decreased by 40%. This study was initiated to address damage removal in the Jauf formation.
Since the mid-1990s the use of HCl/HF at a weight ratio of 9 to 1 has been used extensively in field operations to minimize precipitation during sandstone acidizing. Although it was perceived as applying to all secondary reactions, it was originally directed at fluosilicates. Field case histories have been reported to support this recommendation. However, little evidence is available to justify the use of 9 wt% HCl - 1 wt% HF (9–1 mud acid) at the 300°F temperature exhibited in the Jauf reservoir. Thus, a laboratory study incorporating HF systems with various HCl to HF ratios was performed to quantify the amount of precipitation in Jauf reservoir cores at 300°F, and the impact on permeability. The focus of this paper is on the silicon (Si) and aluminum (Al) concentrations in core flow test effluents that were corrected for post-core test precipitation of reaction products in collection tubes. This technique accounts for the Si and Al in the liquid and solid phases of core flow effluents. The literature teaches that the Si/Al molar ratio of a core test effluent can be used as a diagnostic tool to quantify hydrated silica formation. It is assumed that hydrated silica precipitation increases as the Si/Al ratio decreases from the theoretical value as a result of a greater completion of the secondary and tertiary reactions of HF with silt and clays. The results of this study on short Jauf reservoir and Berea cores at 300°F indicate that cores treated with 9 wt% HCl - 1 wt% HF yield a lower Si/Al ratio than observed with 12 wt% HCl - 3 wt% HF. However, cores treated with 4 wt% HCl - 1 wt% HF yield the lowest Si/Al ratio. The Si/Al ratio is not the only diagnostic tool required to determine the amount of hydrated silica precipitation i.e. factors including the mud acid flow pattern (matrix vs. channel) have a significant impact on the Si/Al ratio. Core flow test results are presented for acetic acid preflush followed by various mud acid systems. All cores were stimulated, although hydrated silica formed in all core tests and aluminum fluoride precipitated in core tests using 4–1 mud acid formulations at 300°F. Introduction Sandstone matrix acidizing has been applied in oil, gas and injection wells for decades to remove formation damage in the critical area surrounding the wellbore.1,2 The chemical reactions that occur between HF acid systems and the aluminosilicate minerals in sandstone reservoirs have been investigated in detail. It is obvious that the sandstone matrix process is significantly more complex than carbonate acidizing. Unlike carbonate acidizing where the formation damage is simply bypassed via the creation of wormholes, during sandstone acidizing the damage that is plugging the pores normally must be dissolved. Subsequent reactions must not occur that create formation damage i.e. precipitation of calcium fluoride (CaF2) or potassium fluosilicate.3–5 Formation of insoluble reaction products during carbonate acidizing using hydrochloric acid (HCl) is rare, but it occurs in every sandstone acid treatment incorporating an HF acid system i.e. hydrated silica.6–7 The focus of this paper is on the formation of hydrated silica as a function of the HCl to HF ratio in mud acid systems, and its impact on formation damage. Hydrated silica, Si(OH)4, is formed during the secondary and tertiary reactions of HF with feldspar and clay as shown in Equations 1 and 2, respectively.4–9 Secondary Reaction: Equation 1 Silica gel, aluminum fluoride complexes (AlFx(3-x)+, and potassium (K) cations are formed during the secondary reaction (Equation 1) via the reaction of pentafluosilicic acid with feldspar/clay. This reaction goes to completion in most sandstone acidizing treatments before well flowback occurs.4,6,7 Secondary Reaction:Equation 1 Silica gel, aluminum fluoride complexes (AlFx(3-x)+, and potassium (K) cations are formed during the secondary reaction (Equation 1) via the reaction of pentafluosilicic acid with feldspar/clay. This reaction goes to completion in most sandstone acidizing treatments before well flowback occurs.4,6,7
Optimization and Field Test of a Chelating Acid System for Scaled Gas Wells in the Hechuan Gas Field
The Hechuan gas field is one of the tight gas reservoirs with the highest formation water salinity in China. The content of metal ions, such as calcium, magnesium, iron, and barium, is as high as 20 g/L. Severe scales in near-wellbore reservoir blocks the gas and liquid flow paths, affecting the normal production of gas wells. The analysis of scale samples shows that the scale compositions in the Hechuan gas field are complex, which are composed of calcium carbonate, calcium sulfate, barium sulfate, iron salt, silicate, and other inorganic scales. To dissolve these scales, 14 kinds of laboratory self-made chelating acids named AST-01 to AST-14, sequentially, were evaluated by the descaling rate, in which the chelating acid AST-01 was selected with a dissolution rate of 77.7%. Meanwhile, the optimal concentration and reaction time of AST-01 were investigated, and the concentrations of the corrosion inhibitor, the iron ion stabilizer, and surfactants were also optimized. Then, a chelating acid descaling formula was obtained, which was 15~20% of AST-01 chelating acid + 1.5~2.0% of corrosion inhibitor + 2.5% of iron ion stabilizer + 0.3% of drainage aid. A pilot field trial of this descaling formula was applied in a Hechuan X1 well. A remarkable result was obtained in that the shut-in tubing pressure recovery rate was increased by 14 times, the gas production was increased by 10 times, and the gas well resumed to produce continuously again.
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