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 presents field results and lessons learned from an FPSO, Offshore Brazil where a scale and corrosion inhibitor has been applied subsea to control both the deposition of scale and associated corrosion. The paper outlines the problems encountered when the initial scale inhibitor formulation was deployed in the field related to materials compatibility with the subsea manifold and the steps taken to develop and monitor an improved formulation. Problems that can affect product application in a subsea environment, including deposition of suspended solids within the chemical, hydrate formation, incompatibility of the chemicals with umbilical material and produced fluid, will all be addressed. The laboratory methods used to select the product along with measurement methods used in the field are also discussed. The validation of the laboratory selection methods in the field required the development of a monitoring program to establish base line control and to assess the degree of protection from scale deposition and corrosion across the process. The use of novel real time scale monitoring, as well as water chemistry tracking proved vital to the understanding of the efficiency of flow assurance within the processes and how treatment rates of the scale inhibitor and corrosion inhibitor could be optimised. This paper will outline in detail the particular issues associated with chemical injection to a subsea facility, many of which are currently being developed in the Gulf of Mexico, offshore West Africa and Brazil. This case study is a good example of lessons learned and sharing of best practice from another oil basin.
Summary This paper presents field results and lessons learned from a floating production, storage, and offloading (FPSO) vessel, offshore Brazil where a scale and combination scale inhibitor (SI) and corrosion inhibitor (Cl) has been applied subsea to control both the deposition of scale and associated corrosion. The paper outlines the problems encountered when the initial scale-inhibitor formulation was deployed in the field related to materials compatibility with the subsea manifold and the steps taken to develop and monitor an improved formulation. Problems that can affect product application in a subsea environment—including deposition of suspended solids within the chemical, hydrate formation, and incompatibility of the chemicals with umbilical material and produced fluid—will all be addressed. The laboratory methods used to select the product along with measurement methods used in the field are also discussed. The validation of the laboratory selection methods in the field required the development of a monitoring program to establish baseline control and to assess the degree of protection from scale deposition and corrosion across the process. The use of novel real-time scale monitoring, as well as water-chemistry tracking, proved vital to understanding the efficiency of flow assurance within the processes and understanding how treatment rates of the scale inhibitor and corrosion inhibitor could be optimized. This paper will outline in detail the particular issues associated with chemical injection to a subsea facility, many of which are currently being developed in the Gulf of Mexico, offshore West Africa, and offshore Brazil. This case study is a good example of lessons learned and sharing of best practices from another oil basin.
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.
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