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

Abstract

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, deploying such treatments from the FPSO host, along the production flowlines, into four low-watercut, horizontal subsea wells, completed with sand control. The relatively small number of high-cost, highly productive wells, coupled with a very high barium-sulfate scaling tendency upon breakthrough of injection water, meant not only was effective downhole scale management critical to achieve high hydrocarbon recovery, but even wells at low water cuts were deemed to be at sufficient risk to require squeeze application. Initial bullheaded scale treatments comprised mutual solvent preflush, a water-based main flush, and diesel overflush; so-called "hybrid" treatments. As water production rates rose, so did the treatment volumes required. To improve the logistics of these treatments and to mitigate issues arising from poor injectivity of diesel in these wells, core studies were conducted to investigate the option of exchanging the overflush fluid from marine diesel to injection-quality seawater. This change also introduced the possibility of forming a gas-hydrates plug during shut-in, but this was managed using a thermodynamic hydrate inhibitor and by replacing the flowline contents to flashed crude during the shut-in period. The operational aspects and the response of the wells to the modified treatments will both be compared with those previously deployed, in particular, in terms of the injectivity of the wells during treatment and well clean-up rates and productivity afterwards. The core studies also highlighted a formation-damage mechanism caused by incompatibility between mutual solvent and the produced oil, which required modification of the treatment. INTRODUCTION The fields are located 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 6 horizontal producers, gravel-packed with pre-packed screens, located centrally in the reservoir and 4 deviated water injectors at the flanks. The 6 production wells are located on 2 production manifolds and the 4 injection wells on a single injection manifold. Field Y is 5 km to the northwest of Field X, and was developed in a similar manner, with 2 horizontal producers completed as in Field X, producing to one manifold, and 2 deviated water injectors tied back to another. Both fields produce to the same FPSO, which has a production capacity of around 80,000 bbl of oil per day and a storage capacity of 1.2 million barrels of oil. The field came on stream in August 2003. Initial average production was some 60,000 bpd but this dropped to 50,000 bpd by early 2005 due to early breakthrough of injection water and well impairment. The reservoir temperature is approximately 90 °C. Scale formation has been a production issue in these fields as they are supported by injection of seawater, which is incompatible with the formation brines, which contain up to 180 mg/l barium and up to 300 mg/l strontium ions (Table 1). The sulphate scaling tendencies of the produced water are presented in Figures 1 to 4. 1 Wells with seawater breakthrough are scale squeezed using 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. INHIBITOR SQUEEZE SELECTION & INITIAL TREATMENT DESIGN The methods to determine the suitability of candidate scale inhibitors has been described in previous publications.2–4 Determination of static / dynamic inhibitor efficiency, produced brine inhibitor compatibility, static chemical adsorption and thermal stability are not covered in this paper.