Lessons Learned from Descaling Wells in a Sandstone Reservoir in Saudi Arabia
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This paper describes field application of a novel scale inhibitor squeeze treatment to mitigate downhole scale (calcium carbonate) present in several oil producing wells in a sandstone reservoir in central Saudi Arabia. The sandstone reservoir is weakly consolidated, water sensitive, and sanding problems were noted in several wells. The water cut in the scaled wells ranges from 3 to 80 vol%. To avoid sanding problems, most of these wells were gravel packed. In addition, the reservoir pressure and gas oil ratio are low and, as a result, electrical submersible pumps (ESPs) are used to produce these wells. The sandstone reservoir is heterogeneous and contains up to 14 wt% clay minerals in some zones. The bottom hole temperature is nearly 160°F. A thorough investigation was undertaken to develop a suitable scale squeeze treatment to mitigate the scale, and to assess the effectiveness of the treatment in the field. Based on extensive lab studies, a new emulsified scale inhibitor treatment was designed and applied in more than fifteen wells. These wells were descaled prior to the squeezetreatment as was detailed by Nasr-El-Din et al.1 All scale squeeze treatments were conducted using 1.75 or 2 in coiled tubing. Because the formation is water-sensitive, the main treatment, the pre and post flushes were designed to minimize formation damage due to fines migration and clay swelling. Following the treatment, the well was shut-in for two days to give ample time for various reactions to occur. Chemical analysis of well flow back samples was used to estimate the lifetime of the squeeze treatment. In addition, a downhole video camera was used to follow scale formation following the treatment. The scale squeeze treatment was conducted in more than fifteen wells. The emulsified inhibitor was mixed in the field and was injected into the target zones without encountering any operational problems. Analysis of flowback samples indicated that the treatment did not affect well productivity or water cut in any of the treated wells.Based on field data, it is known that the treatment lifetime is greater than two years. The minimum scale inhibitor concentration, presented as phosphorus, is nearly 1 mg/L. Introduction Field "H" is a sandstone reservoir, which was developed in central Saudi Arabia a few years ago. Oil production from this field started in August of 1994. Water injection commenced in late 1994 and early 1995, using a peripheral water injection pattern to maintain reservoir pressure. The injection water is obtained from a shallow aquifer and is produced from 17 supply wells with electrical submersible pumps (ESP) and sent to four water injection plants. The water pressure is increased to approximately 1,200 psig and pumped into the injection wells. Table 1gives a typical chemical analysis for the aquifer water.Note that the supply water contains high levels of sulfate ion, which contributed in the growth of sulfate-reducing bacteria (SRB) and subsequent plugging problems that were encountered in water supply wells and water injectors.2–4 The formation produces Arabian Super light crude oil (°API > 50). The oil has a very low gas-oil ratio (GOR) and no appreciable CO2 and H2S content; therefore, ESPs are used to produce this reservoir. The average reservoir temperature is 150–160°F and its thickness ranges from 150 to 200 ft. The sandstone reservoir is weakly consolidated and sanding problems were noted in several wells. To mitigate sand production, the producing wells were gravel packed.
This paper describes field application of a novel scale inhibitor squeeze treatment to mitigate downhole scale (calcium carbonate) present in several oil producing wells in a sandstone reservoir in central Saudi Arabia. The sandstone reservoir is weakly consolidated, water sensitive, and sanding problems were noted in several wells. The water cut in the scaled wells ranges from 3 to 80 vol%. To avoid sanding problems, most of these wells were gravel packed. In addition, the reservoir pressure and gas oil ratio are low and, as a result, electrical submersible pumps (ESPs) are used to produce these wells. The sandstone reservoir is heterogeneous and contains up to 14 wt% clay minerals in some zones. The bottom hole temperature is nearly 160°F. A thorough investigation was undertaken to develop a suitable scale squeeze treatment to mitigate the scale, and to assess the effectiveness of the treatment in the field. Based on extensive lab studies, a new emulsified scale inhibitor treatment was designed and applied in more than fifteen wells. These wells were descaled prior to the squeezetreatment as was detailed by Nasr-El-Din et al.1 All scale squeeze treatments were conducted using 1.75 or 2 in coiled tubing. Because the formation is water-sensitive, the main treatment, the pre and post flushes were designed to minimize formation damage due to fines migration and clay swelling. Following the treatment, the well was shut-in for two days to give ample time for various reactions to occur. Chemical analysis of well flow back samples was used to estimate the lifetime of the squeeze treatment. In addition, a downhole video camera was used to follow scale formation following the treatment. The scale squeeze treatment was conducted in more than fifteen wells. The emulsified inhibitor was mixed in the field and was injected into the target zones without encountering any operational problems. Analysis of flowback samples indicated that the treatment did not affect well productivity or water cut in any of the treated wells.Based on field data, it is known that the treatment lifetime is greater than two years. The minimum scale inhibitor concentration, presented as phosphorus, is nearly 1 mg/L. Introduction Field "H" is a sandstone reservoir, which was developed in central Saudi Arabia a few years ago. Oil production from this field started in August of 1994. Water injection commenced in late 1994 and early 1995, using a peripheral water injection pattern to maintain reservoir pressure. The injection water is obtained from a shallow aquifer and is produced from 17 supply wells with electrical submersible pumps (ESP) and sent to four water injection plants. The water pressure is increased to approximately 1,200 psig and pumped into the injection wells. Table 1gives a typical chemical analysis for the aquifer water.Note that the supply water contains high levels of sulfate ion, which contributed in the growth of sulfate-reducing bacteria (SRB) and subsequent plugging problems that were encountered in water supply wells and water injectors.2–4 The formation produces Arabian Super light crude oil (°API > 50). The oil has a very low gas-oil ratio (GOR) and no appreciable CO2 and H2S content; therefore, ESPs are used to produce this reservoir. The average reservoir temperature is 150–160°F and its thickness ranges from 150 to 200 ft. The sandstone reservoir is weakly consolidated and sanding problems were noted in several wells. To mitigate sand production, the producing wells were gravel packed.
A novel carbonate/sulfate scale squeeze treatment specifically targeted to low temperature, low pressure clastic formations was developed, and successfully applied to Saudi Arabian formation, designated H-A. A number of different remediation techniques were reviewed. They ranged from adsorption and precipitation squeezes to encapsulated treatments. Due to the low temperature of the field (<160°F), and the low pressure of the formations, a non-traditional scale squeeze was required. Adsorption squeezes are well documented, but have short return lives and would have required retreating every-6–8 months. Encapsulated squeezes delivered a very short life. Naturally induced precipitation squeezes using organophosphonates (ATMP, ADMP) have been used to treat Saudi Arabian carbonates since 1986. Unfortunately, the H-A formation is a siliceous clastic reservoir (quartz > 98 wt. %) with little natural carbonates, and a natural precipitation squeeze would not be possible. It was decided that a forced precipitation would be used. A forced precipitation must contain the organophosphonate, a source of divalent cations (usually, but not confined to Ca++), and a method of either raising or lowering the pH to change the solubility of the Caphosphonate derivative, and force precipitation. The change in pH required is a function of the phosphonate used, and a large number of options have been developed. Most however, require temperatures above 180°F to be successful. This innovative method employs a multiple staged treatment using a diesel emulsified inhibitor/divalent cation stage injected with pH control stages. The two aqueous stages cannot come into contact with each other until the emulsion breaks. The breaking time of the emulsion is controlled by the adsorption of the emulsifier onto the formation rock, and is not temperature dependent, as are urea-based systems. The formulation contains a clay stabilization chemical. The treatment has been successfully applied to 25 wells, the first, H-53 nearly 36 months ago. This well has current returns nearly 0.1 mg /L organophosphonate, and has a projected treatment life of 2–3 years. Introduction The H-A formation varies from braded stream and fluvial stacked channels, to migrating dune sequences. The formation is Paleozoic in age, and underlies the Khuff carbonates.1 The mineralogy is dominated by detrital quartz, which typically comprises 95–99 percent of the mineralogy in the pay intervals. Some sections of the formation have 1–2 wt. % carbonates (calcite and ankerite), but usually less then 0.5 wt. % is common. Accessory minerals grains are K-spars, and occasional chert fragments, rare Na-feldspars and heavy minerals. The cement is mainly quartz at grain-to-grain contacts, but occasional illite/montmorillonite is noted as cement. This contributes to the clay sensitivity of the formation, which requires 7 wt. % KCl to prevent fines migration, sanding, and hole stability problems. Other secondary cements include pore filling quartz, ankerite, and chlorite. The sands range from well consolidated in the braded streams to unconsolidated in the dune sequences. The pay intervals contain 0.1 to 3 wt. % clay minerals, dependent on depositional environment. The braided stream sequences are more clay rich, and the dune sequences, the cleanest. The clay minerals include pore lining illite/montmorillonite, pore filling kaolinite, and grain and pore lining chlorite. The chlorite is Fe rich clay mineral. Other important accessory minerals include minor pyrite and hematite, but no more then 0.01 - 0.1 wt. % in pay zones. The exception to this is in sub-aerially exposed intervals. These intervals, however, are seldom reservoir quality. Porosity ranges from 18 to 32 vol%, and permeability ranges from < 1 md in interchannel or interdune intervals to > 5 Darcies in dune sequences. The formation produces Arabian Superlight crude oil (50°+ API) using ESPs. The oil has a very low GOR, and no appreciable CO2 content. Many of the wells are gravel packed, and have 150 mesh screens. The wet wells produced scale free until 1997, when calcium carbonate scale was found covering the producing screens, and in the ESPs. The presence of scale was verified by down-hole video logs, and confirmed as calcium carbonate by XRD analysis on recovered scale samples.2–4
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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