This paper describes field experience and lessons learned from scale control operations in a deepwater subsea development in the Campos Basin, Brazil; specifically, from bullheading scaleinhibitor squeezes 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 that not only was effective 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.Use of conventional, water based squeezes have been known to cause significant damage to productivity in low-watercut wells, including those showing a fines-migration tendency, as was the case here. Hence, on the basis of risk mitigation, supported by an extensive program of laboratory testing, it was decided that for the initial treatments, only the mainflush would be water based, with a mutual-solvent preflush and marine-diesel overflush.Other key challenges associated with treating from the host included the remote location of the wells, the potential to form hydrates, the cleanliness of the lines along which the treatment would pass, the achievement of effective placement over a long producing interval, as well as the need to deploy the chemical package via a support vessel adjacent to the FPSO. All had to be managed because of the high cost and low availability of a deepwater rig that could deploy the treatments directly to the subsea wellheads. This paper will explore in detail the issues associated with inhibitor-squeeze deployment in deepwater, subsea fields, many of which are currently being developed in the Campos basin, Gulf of Mexico, and West Africa, and are a good example of best-practice sharing from another oil basin.Downhole Scale Surveillance. Production Surveillance. Continuous monitoring of well performance is carried out using pressure and temperature gauges, both downhole and at the subsea wellheads, thus allowing productivity indices, pressure drops across the tubing, and instantaneous changes in gross rates, all to be effectively monitored. These are supplemented by regular well tests that can assist in deconvoluting changes in productivity because of formation damage from that because of changes in gas lift rates, reservoir pressure, wettability, reservoir saturations etc.
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.
This paper describes field experience and lessons learned from scale-control operations in a deepwater subsea fielddevelopment in the Campos Basin, Brazil; specifically, from bullheading scale-inhibitor squeezes 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 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. Use of conventional, water-based squeezes have been known to cause significant damage to productivity in low-watercut wells, including those showing a fines-migration tendency, as was the case here. Hence, based upon risk mitigation, supported by an extensive programme of laboratory testing, it was decided that for the initial treatments only the mainflush would be water-based, with a mutual-solvent preflush and marine-diesel overflush. Other key challenges associated with treating from the host included the remote location of the wells, the potential to form hydrates, the cleanliness of the lines along which the treatment would pass, the achievement of effective placement over a long producing interval, as well as the need to deploy the chemical package via a support vessel adjacent to the FPSO. All had to be managed due to the high cost and low availability of a deepwater rig that could deploy the treatments directly to the subsea wellheads. The paper will explore in detail the issues associated with inhibitor-squeeze deployment in deepwater, subsea fields, many of which are currently being developed in the Campos basin, Gulf of Mexico and West Africa, and is a good example of best-practice sharing from another oil basin. INTRODUCTION Fields Description The fields are located in the Campos Basin offshore Brazil, approximately 145 km east of Macae,. The field is on the present -day continental slope, in water depths ranging from 700 to 850 meters. Development of fField X comprises of 6 horizontal producers, gravel -packed and completed with pre-packed screens, located centrally in the reservoir and 4 slantdeviated flank water injectors at the flanks. Seawater injection maintains pressure and increases recovery. The wells have been drilled from a central drilling location. 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, wereand was developed in a similar manner, with 2 horizontal producers completed as in Field X, producing to one manifold, gravel pack and completed with pre-pack screens, and 2 deviated water injectors tied back in 2 subsea manifoldsto another. Both fields (1 producer and 1 injection) and tied produce into the same FPSO,. The FPSO which has a production capacity of 81,000 bbl of oil per day and a storage capacity of 1.2 million barrels of oil. A 3third party company operates the FPSO. The field came on stream oin August 12th, 2003. Initial Aaverage production initiallywas some 60 kKbpd but this droppeding of to 50 kKbpd byin early 2005 due to early breakthrough of injection water breakthrough 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. 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.
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