Predicting Success of Horizontal Openhole Completions on the North Slope
- Dennis Denney (JPT Technology Editor)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- November 2006
- Document Type
- Journal Paper
- 47 - 49
- 2006. Society of Petroleum Engineers
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- 65 since 2007
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This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 97121, “Predicting Openhole Horizontal Completion Success on the North Slope of Alaska,” by M.D. Erwin, SPE, ConocoPhillips Alaska Inc., and D.O. Ogbe, SPE, U. of Alaska, Fairbanks, prepared for the 2005 SPE Annual Technical Conference and Exhibition, Dallas, 9–12 October.
Wells in the Colville River (Alpine) field, on the North Slope of Alaska, were completed with horizontal open holes. This paper describes why this completion technique was selected and identifies key parameters for successful application in the field. The optimal completion technique for a candidate well is determined by the reservoir properties, geological setting, rock mechanics, development plan, and completion design. Guidelines are provided for future application of horizontal openhole completions on the North Slope of Alaska and elsewhere.
From the early 1970s through the 1990s, engineers drilled and completed wells on the North Slope of Alaska with conventional cemented and perforated liners. The wells drilled in Prudhoe Bay, Kuparuk, Lisburne, and other fields are protected with casing and cement to maintain wellbore stability, ensure reservoir access, restrict solids movement, and provide conformance control for various reservoir fluids. In 2000, the Colville River field, better known as the Alpine field, was developed without conventional well-bore isolation or protection.
This paper examined advantages, limitations, and unique requirements for applying openhole completions. Major issues included fluid isolation and coning, damage remediation, fluid mobility, conformance control, sand control, and surveillance. Failure to address these issues properly could result in surface-facility and processing problems from uncontrolled water, gas, and sand production.
As shown in Fig. 1, the field is approximately 60 miles west of the Prudhoe Bay field on the North Slope of Alaska. It contains 429 million STB of recoverable reserves out of approximately 1 billion bbl of oil in place. Production is from the Alpine oil zone. The field was discovered in 1994, with field construction of the process facilities and pipelines in the winter of 1999. Development drilling followed in May 1999, with first oil delivered in November 2000.
Reservoir Description. The Alpine reservoir is Upper Jurassic sandstone, approximately 10 miles east/west and 6 miles north/south. The maximum thickness of the reservoir is 100 ft, with an average thickness of 50 ft. Reservoir dip is 2° from the northeast tip of the structure to the downdip southwest corner. Top of the structure is approximately 6,600 ft true vertical depth subsea (TVDSS), falling to 7,600 ft TVDSS in the southwest. The reservoir is undersaturated, and the aquifer has not been delineated or penetrated.
Original average reservoir pressure was 3,200 psig, and average reservoir temperature is 160°F. The reservoir oil is 40°API gravity and has a viscosity at reservoir conditions of approximately 0.45 cp. The bubblepoint of the fluid is 2,450 psig.
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