Calcium carbonate scale represents a significant safety and operational problem in offshore carbonate fields operated by Saudi Aramco. Scale can form on any surface where the pressure drop is sufficient for the produced fluids to form the scale and unload entrained solids. These solids will deposit on wellhead equipment such as the wellhead surface valves, piping, well tubulars and may plug the perforations. Well safety is jeopardized by hindering the operation of critical safety valves such as subsurface safety valves (SSSVs) and surface safety valves (SSVs). Further, scale buildup can cause backpressure problems in the tubing as the pipe internal diameter is reduced. Identification of scale in impacted wells requires periodic inspection and repair. This paper presents Saudi Aramco's experience in eliminating calcium carbonate scale by treating existing scale using HCl acid. Scale mitigation was initially attempted using an encapsulated inhibitor placed in the rat hole of vertical wells. This method had a limited treatment effective life and Saudi Aramco has moved to using inhibitor squeeze treatments. Chemical squeezes places inhibitor (phosphonate-based) directly into the formation of wet oil producers and is now the currently employed method of long-term prevention of scale. Case studies using both methods of scale mitigation are discussed as well as future plans to improve the effectiveness of these treatments. Introduction Field "B" is located both onshore and offshore along the western edge of the Arabian Gulf. The field is a north to south trending, elongated, anticlinal structure which measures 40 Km in length and 19 Km in width. This field was discovered in June 1964 and oil production began in 1967. Field "B" is a multi-reservoir field with 11 oil-bearing reservoirs at various depths from 2,133 to 3,048 meters (7,000 to 10,000 ft). The crude grade is Arab Extra Light crude with 7.5 mol% H2S and 4.5 mol% CO2. The two main reservoirs in this field are the HN and HD. The main productive formations have a low permeability in the range of 1–50 mD. The HN and HD reservoirs are carbonates reservoirs. Bulk XRD analysis of the HN reservoir cores indicates that the zone of interest contains 97–100 wt% calcite and 0–3 wt% ankerite. On the other hand, HD reservoir cores contain 70–92 wt% calcite, 0–30 wt% dolomite and 0–5 wt% ankerite.1 For pressure support purposes, peripheral water injection began in 1973 using 14 injectors into the HN reservoir and 28 injectors into the HD reservoir. The injection water is drawn from a shallow aquifer. The produced water is injected into a separate, segregated disposal system. Water breakthrough first occurred in the HN reservoir in mid 1975 and in late 1978 in the HD reservoir. Water-handling facilities were placed in service in 1983. The water cut for both the HN and HD reservoirs has gradually increased since the commissioning of these facilities and currently the field produces crude oil with an average water-cut of 32 vol%. The first scale build-up problem was encountered in 1987. Since then, scale became a difficult problem to manage as more wells started to produce formation or injection water. Scale build-up has resulted in several operational problems and production losses. The main objectives of this study are to:give a brief summary on the scale problems encountered in Field "B" carbonate reservoirs,discuss how this problem was addressed, andsummarize field experience gained from solving this problem. Chemical Analysis of the Formation Brines The composition of the produced water varies significantly for the HN and HD reservoirs as noted in Table 1. The Total Dissolved Solids (TDS) for the HN reservoir brines varies from 27,000 to 230,000 mg/L. The calcium ion concentration is in the range of 1,904–18,876 mg/L. The TDS for the HD reservoir brines is higher than that of the HN brines and varies from 33,400 to 292,000 mg/L. Calcium ion concentration is in the range of 2,392 to 39,280 mg/L.

The focus of most waterflood or pressure maintenance projects is on the performance of the production and injection systems to ensure maximizing field rates and efficiencies. Yet there is a third leg to this operational triangle: the water supply system including wells and gathering system. This paper presents a case study of operational strategies and programs developed from experience from mature Field "B," and then translated to a revitalized re-started Field "F." These strategies include the use of tubeless completions of the water supply wells to maximize the water production rate and the subsequent implementation of a "build-down" strategy consisting of the installation of smaller casing sizes to isolate impaired casing sections and well monitoring with corrosion logs to address casing integrity issues. Over time, the casing profiles became smaller, the rate of casing integrity issues accelerated and the overall supply well rates could not meet the increased injection demand. These casing integrity issues (up to 60% metal loss in some wells) necessitated a shift in strategy from the mechanical "build-down" to a mitigation strategy to extend the life of the existing supply wells. The "build-down" strategy was effective from 1975 to approximately 2006 in isolating casing integrity issues. The initial chemical squeeze inhibition campaign completed from 1979 to 1981 floundered on the monthly treatment requirements and the attendant high cost for these treatments. As casing profiles become smaller over time, a revamped corrosion inhibitor treatment program was completed quarterly and has been found to extend the well service life by 7 years so far. Furthermore, this case study will review the efficiency of the use of the same corrosion mitigation squeeze strategy in the revitalized Field "F." Introduction to the Water Supply System of Field "B" General Background The mature Field "B" has been in service since 1967 with a peripheral waterflood operation for pressure maintenance since 1972 into the two primary oil producing zones. Waterflood operations are supported by the use of water supply wells completed in a regional water aquifer, sandstone characterized by very high deliverability, with rates of up to 70,000 barrels of water per day (BWPD). This supply water flows to the surface supported by the formation pressure with surface flowing wellhead pressures (WHPs) of between 100 to 125 psig. Initial injection requirements were in the order of 250,000 BWPD in 1983 and have expanded to approximately 363,000 BWPD as of July 2013. At injection startup, there were 21 supply wells, and at July 2013 there are 18 active supply wells. Supply water is gathered from the wells through two flanks to the main operational facilities where the water is pumped into the various water injection wells. It should be noted that these main operational facilities are located within 1500 meters of the Arabian Gulf.

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This report was prepared as an account of Government sponsored work. Nel~er the United States, nor the Commission, nor any person acting on behalf of the Commission: A. Makes any warranty or representation, expressed or Implied, with respect to the accuracy, completeness, or usehlliu~ss of the Information contained In lh111 report, or thlll the u1111 of any Information, apparatus, method, or process disclosed In this report may not Infringe privately owned rights; or B. Auumes any llaollltles With respect to the use of, or for damllges resulting from the use of any Information, apparatus, method, or process dl"'-'loRed In this report. Ab used in the above, "person acting on behalf of the Commission" Includes any employee or contractor of the Commission, or employee of such contractor, to the extent that such employee or contractor of the Commission, or employee of such contractor prepares, disseminates, or provides access to, any Information pursuant to his employment or contract with the Commission, or his employment with such contractor. This report has been reproduced directly from the best available copy.

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