Scale Inhibitor Squeeze Treatments Deployed From an FPSO in a Deepwater, Subsea Field in the Campos Basin
- Philip J. Bogaert (Shell Nigeria E&P Co. Ltd.) | Marcos C. Berredo (Sarawak Shell Berhad) | Celso Toschi (Shell Brasil S.A.) | Myles M. Jordan (Nalco) | Dario M. Frigo (Shell Intl. E&P Inc.) | Lee N. Morgenthaler (Shell E&P Co.) | Macros Afonso (Nalco)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Operations
- Publication Date
- November 2007
- Document Type
- Journal Paper
- 451 - 471
- 2007. Society of Petroleum Engineers
- 4.3.1 Hydrates, 1.8 Formation Damage, 4.2.4 Risers, 5.1.1 Exploration, Development, Structural Geology, 3 Production and Well Operations, 5.2 Reservoir Fluid Dynamics, 5.8.7 Carbonate Reservoir, 4.3.4 Scale, 1.4.3 Fines Migration, 4.2 Pipelines, Flowlines and Risers, 4.2.3 Materials and Corrosion, 5.6.5 Tracers, 2.4.3 Sand/Solids Control, 4.5 Offshore Facilities and Subsea Systems, 4.3.3 Aspaltenes, 4.5.3 Floating Production Systems, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 2.4.5 Gravel pack design & evaluation, 1.6.9 Coring, Fishing, 4.1.2 Separation and Treating, 5.3.2 Multiphase Flow, 4.1.5 Processing Equipment, 5.6.4 Drillstem/Well Testing, 1.3.2 Subsea Wellheads
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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 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 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.
Fields Description. 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 six horizontal producers, gravel-packed with pre-packed screens, located centrally in the reservoir and four deviated water injectors at the flanks. The six production wells are located on two production manifolds and the four 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 two horizontal producers completed as in Field X, producing to one manifold, and two deviated water injectors tied back to another.
Both fields produce to the same FPSO, which has a production capacity of 81,000 BOPD and a storage capacity of 1.2 million barrels of oil. A third party operates the FPSO.
The field came on stream in August 2003. Initial average production was some 60 kbpd but this dropped to 50 kbpd by early 2005 because of 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 that 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.
Table 1 shows the typical formation brine chemistry for both fields. Injection-quality seawater has been used to maintain reservoir pressure and improved fluid sweep within most of the reservoir units over the life of the field. Figs. 1 and 2 show the maximum predicted mass of sulfate scales associated with injection-water breakthrough under reservoir conditions as a function of the fraction of seawater in the produced water; Figs. 3 and 4 show the corresponding supersaturation values. There is no calcium sulfate tendency for any mixing ratio.
It is clear that barium sulfate is the most significant predicted scale type present in terms of both mass of scale and supersaturation. Observation of scale samples recovered from the field supports these predictions with barium sulfate being more prevalent than either strontium sulfate or calcium carbonate in the suspended particulates observed in produced water and in scale samples recovered from wells. Significant amounts of calcium carbonate particulates have only been observed from one well in Field Y.
|File Size||6 MB||Number of Pages||21|
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