Abstract

This paper describes a series of investigations carried out in an ESP lifted well (below bubble point production) that experienced a cluster of unexpected problems resulting in loss of production, and how the investigations restored production. The problems among others included apparent severe productivity drop coupled with downhole temperature rise, and the investigations eventually led to the discovery of asphaltene that has not been found in the field before. Analysis of all the problems and investigations including lessons learnt are shared in detail.

Background

Wytch Farm is the largest onshore oil field in Western Europe. It is situated on the southern coast of England, about 100 miles south-west of London. The Sherwood reservoir (Triassic sandstone) was discovered in 1978 at the time the shallower Bridport Jurassic sandstone reservoir was being developed. The Sherwood reservoir formations, at ca. 1600m TVD, lie partially onshore and extend offshore into Poole bay. The onshore part was developed first before the offshore development started in 1992, all from the existing onshore drilling sites. Fig.1 shows the location of the Sherwood reservoir and the onshore drilling sites.

The reservoir pressures have been steadily decreasing and now virtually all the producers are artificially lifted with Electrical Submersible Pumps (ESP). The temperature at reservoir depths is ca 70°C (160°F). There is a noticeable change in hydrocarbon composition onshore and offshore, manifested e.g. in bubble point from 1086psi to 932psi and GOR from 357 scf/stb to 320 scf/stb respectively. There is no appreciable amount of CO2 or H2S. The hydrocarbon API gravity is ca 38, and the produced water is ca 1.11sg. Waxes form around 23°C and will not dissolve until above 52°C. There had been no asphaltene problems found previously, and the scale potential (mainly Calcium carbonate) was low1.

The low angle well A9 (<18 degree deviation), located onshore at the southwest part of the reservoir, was drilled in October 1988 and completed with a 7" liner in April 1989. Only zones 10, 30 and 50 were perforated but not zone 70 (these are the oil bearing zones in the Sherwood sand progressively deeper in the order quoted; zone 70 is the thickest [20 – 50m] and best sand but the oil-water contact there of the supporting aquifer can vary). The well naturally flowed at a very low rate (ca 50bopd) for 5 or 6 months before being shut-in for nearly 4 years, until the pressures at this part of the reservoir were raised through water injection in 1994 into the aquifer. A9 was further flowed for up to 5 months during the course of 1994. The flow rates peaked at over 1.3mbod although not sustained. In November 1994 it was shut-in again, possibly because of dropping pressure and thus production. The total production then was only about 20,000bbls of oil while the reserves at this part of reservoir were well over 1.3mmboe.

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