Calcium carbonate scale was detected in several vertical wells in a sandstone reservoir in Saudi Arabia. The scale was detected downhole, plugging gravel packing screens and the intake of submersible pumps. Scale build up caused significant decline in oil production from this field. The sandstone reservoir is water-sensitive and has a bottom hole temperature of 160°F. An emulsified scale inhibitor (phosphonate-type) treatment was designed to mitigate scale in this field. Recently, Nasr-El-Din et al.1 discussed the development of this new treatment and reported initial field results. So far the treatment was successfully applied in more than twenty wells. Some of these wells were de-scaled before the treatment, while other wells were treated before scale detection. The objectives of the present paper are to assess the outcome of this treatment based on field data and to optimize the scale squeeze treatment based on the analysis of well flow back samples. Samples of produced water from these wells were collected and analyzed for nearly three years. Results, Observations, Conclusions The scale treatment was successfully conducted in more than twenty wells with various water cuts. No scale was detected in any of the treated wells for nearly three years. No significant decline in oil production was observed. Based on field data, it is known that the treatment lifetime is greater than two years and is estimated to be 3–4 years. Application This paper describes fieldwork done to optimize the performance of a novel emulsified scale squeeze treatment in a sandstone reservoir. It also discusses the importance of well flow back analysis and how it can be used to enhance the outcome of a scale squeeze treatment. The emulsified chemical was successful in meeting the main objective of the treatment, i.e., providing scale mitigation for greater than three years, while maintaining the integrity of the formation. Technical Contributions

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This paper describes the development and field application of an acid-based treatment to remove downhole scale in several oil producing wells in a sandstone reservoir in Central Saudi Arabia. The sandstone reservoir is weakly consolidated and sanding problems were noted in several wells. To avoid sanding problems, these wells were gravel packed. In addition, the reservoir pressure and gas oil ratio are low and, as a result, electrical submersible pumps (ESP) are used to produce these wells. The sandstone reservoir contains 1–13.5 wt% clay minerals and the bottom hole temperature is 160°F. A thorough investigation was undertaken to identify the composition and location of the scale, to recommend a suitable acid formulae to remove the scale, and to assess the effectiveness of the treatment in the field. Based on extensive lab studies, an acid treatment was designed and applied in more than 15 wells. These wells have a water cut that ranges from 3 to 80 vol%. Because of the low reservoir pressure, these treatments were conducted using coiled tubing and the spent acid was lifted using nitrogen gas. In addition, the formation is water-sensitive. Therefore, the pre and post flushes were designed to minimize formation damage due to fines migration and clay swelling. Chemical analysis of acid returns (spent acid) was used to determine the type and concentration of acid additives. Results, Conclusions Lab tests (XRD and XRF) indicated that the scale consisted of calcium carbonate, iron oxides and iron sulfide. The scale is located mainly down hole on the gravel pack screens, ESP, and downhole tubing. The scale has a solubility of nearly 80 wt% in 20 wt% HCl. The presence of high iron contents in the scale necessitates the use of iron control agents (citric and acetic acids) with the acid. Also, the scale contained iron sulfide, therefore an aldehyde-based hydrogen sulfide scavenger was added to the acid formula. Because of the sensitivity of the formation, acid concentration was limited to 15 wt% HCl and acid volume was 15 gals/ft of screen. The acid was allowed to soak for an hour. The acid treatment was conducted on a total of 15 wells. The acid was able to remove the scale in all wells without encountering any operational problems. Analysis of flowback samples showed high levels of calcium (up to 25,000 mg/L) and iron (up to 15,000 mg/L). These results confirmed those noted in the lab and also justified the need of various acid additives that were used in the treatments. All wells responded positively to the treatment and oil production has been increased to its original level. This paper describes laboratory and fieldwork done to restore the productivity of damaged wells. It also discusses the importance of selecting acid additives to minimize formation damage and maintain the integrity of the formation. Introduction and Background Field "H" is a sandstone reservoir, which was developed in central Saudi Arabia few years ago. Oil production started in August of 1994. Water injection started in this reservoir 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 (WIPS). The water pressure is increased to approximately 1,200 psig and pumped into the injection wells.Table 1gives the chemical analysis of the water produced from selected supply wells. Note that the supply water contains high levels of sulfate ion, which contributed in the growth of sulfate-reducing bacteria and subsequent well plugging problems in this field.1,2