Managing Formation-Damage Risk From Scale-Inhibitor Squeeze Treatments in Deepwater, Subsea Fields in the Campos Basin

Abstract

Summary This paper describes field experience and lessons learned from bullhead-deployed scale-control operations in a deepwater subsea development in the Campos basin, Brazil; specifically, this paper is about deploying such treatments from the floating production, storage, and offloading (FPSO) host, along the production flowlines, and into four low-water-cut, horizontal, subsea wells completed with sand control. The relatively small number of high-cost, highly productive wells, coupled with a very high barium sulfate (BaSO4) scaling tendency upon breakthrough of injection water, meant that not only was effective downhole scale management critical to achieve high hydrocarbon recovery, but that even wells at low water cuts were deemed to be at sufficient risk to require squeeze application. Initial bullheaded scale treatments comprised three "hybrid" treatments: a mutual-solvent preflush, a water-based main flush, and a diesel overflush. As water-production rates rose, so did the treatment volumes required. To improve the logistics of these treatments and to mitigate issues that arise from poor injectivity of diesel in these wells, core studies were conducted to investigate the option of changing the overflush fluid from marine diesel to injection-quality seawater. This change also introduced the possibility of forming a gas-hydrate plug during shut-in, but this was managed by use of a thermodynamic hydrate inhibitor and by replacing the flowline contents to flashed crude during the shut-in period. Both the operational aspects and the response of the wells to the modified treatments will be compared with those previously deployed in terms of, in particular, the injectivity of the wells during treatment and well-treatment cleanup rates and productivity afterward. The core studies also highlighted a formation-damage mechanism caused by incompatibility between the mutual solvent and the produced oil; this required modification of the treatment. Introduction The fields are in the Campos basin offshore Brazil, approximately 145 km east of Macae, on the present-day continental slope, in water depths ranging from 700 to 850 m. Development of Field X comprises six horizontal producers, gravel-packed with prepacked screens and located centrally in the reservoir, and four deviated water injectors at the flanks. The six production wells are on two production manifolds, and the four injection wells are on a single injection manifold. Field Y is 5 km northwest of Field X and was developed in a similar manner, with two horizontal producers completed as in Field X producing to one manifold and two deviated water injectors tied back to another manifold. Both fields produce to the same FPSO host, which has a production capacity of approximately 80,000 BOPD and a storage capacity of 1.2 million BO. The field came on stream in August 2003. Initial average production was 60,000 B/D, but this dropped to 50,000 B/D by early 2005 because of early breakthrough of injection water and because of well impairment. The reservoir temperature is approximately 90°C. Scale formation has been a production issue in these fields because they are supported by injection of seawater, which is incompatible with the formation brines that contain up to 180 mg/L of barium and up to 300 mg/L of strontium ions (Table 1). The sulfate-scaling tendencies of the produced water are presented in Figs. 1 through 4 (Bogaert et al. 2007). Wells with seawater breakthrough are scale squeezed with a phosphate ester scale inhibitor to control sulfate-and carbonate-scale formation within the wells and flowlines; additional inhibitor is injected to the produced fluids once they reach the topside facilities.