Summary

In 1994, a low-cost development and operating plan for future wells at the Kuparuk River Field was proposed with the goal of reducing well costs 30% by the end of 1996. This paper presents this plan of a slimhole drilling and monobore completion program, a discussion of the critical issues addressed to successfully make the change, and field results from the first 16 wells drilled in 1994 and 1995.

A review of historical cost information is included which covers drilling and completing wells using the conventional well designs that had become standard in the field for the previous 10 years. A variety of new slimhole well plans are presented for both production and injection wells together with a discussion of their potential application and cost savings. The paper concludes with a look at future work plans and opportunities for additional cost savings through the use of slimhole wells.

Introduction

Located in the Alaskan Arctic, the Kuparuk River Field is one of the United States' largest producing oil fields (300,000 barrels oil per day), and covers an area of approximately 115,000 acres. The field was discovered in 1969, but was not economic for development until 1977, after completion of the Trans-Alaska Pipeline. Fig. 1 shows the field location on the North Slope of Alaska. Field development was started in 1979 using gravel pads as central drill sites from which deviated wells are drilled to drain a four section area (4 square miles). Initial development is on 160 acre well spacing with some 80 acre infill locations.

The Kuparuk reservoir is a sandstone at approximately 6,000 ft subsea with solution gas drive as the primary production mechanism. The majority of the field is under secondary recovery receiving pressure support through a combination of waterflood and water-alternating immiscible and miscible gas injection. Previous reports have documented both the geological description and the reservoir mechanisms of the field.1,2

Production occurs from two horizons within the Kuparuk sandstone. An upper sandstone interval, referred to as the C Sand, is present over most of the southern half of the field and consists of very coarse to very fine grained siderite and sandstone. With average permeabilities of 130 to 2600 md, and net pay ranges up to 80 ft, the C Sand typically produces at rates from 1000 to 5000 barrels per day (BPD).

The A Sand, the lower producing zone, is present throughout the field and contains 65% of recoverable oil in place. The average net thickness is typically less than 30 ft, with permeability ranging from 20 to 100 md. It is a fine to very fine grained sandstone interbedded with shale and cemented with quartz and varying amounts of ankerite. Hydraulic fracture treatments are required to maximize A Sand rates which range from 500 to 3000 BPD.

Development well plans quickly standardized on a casing program using a 16 in. conductor, 9 5/8 in. surface casing and 7 in. production string. When overpressured zones are encountered, or lost circulation problems are severe, the 7 in. casing is set as an intermediate string above the Kuparuk Formation and a 5 in. liner run to total depth (TD). The standard drill bit program became 12-1/4 in. bits for the surface casing section and 8-1/2 in. bits for the production hole section. When an intermediate casing string is required, the production hole for the 5 in. liner is drilled with 6-1/8 in. bits. Since development occurs from centralized gravel pads, all the wells are deviated, employing steerable bottomhole assemblies.

The completion program standardized on the selection of one of two designs—either a single completion in the case of a well drilled in an A Sand only area of the field, or a selective completion for wells drilled where both the A and C Sands are present. The selectivity is necessary for both reservoir management and separate stimulation of the lower A Sand. Figs. 2 and 3 show schematics of these two main completion designs. Gas-lift mandrels are run for artificial lift in all cases.

Fig. 4 shows the average development well costs from 1988 to 1993. By the end of 1993, a total of 744 wells had been drilled in the field. Of these wells, over 700 wells had been justified on either 320 or 160 acre locations, with the remaining wells drilled on 80 acre infill locations. The expected cost to drill and complete future wells was budgeted at $1.59 million per well. Potential locations existed for up to an additional 436 wells. However, most of these well locations were not economic because they are planned as infill locations. As such, they have significantly less reserves associated with each well compared to initial development. The resulting economics are significantly less favorable, necessitating a step change in both the development and operating costs beyond the 7 in. single and selective well designs which had become the field standard.

Revised Development Plan

A number of different options were investigated in an attempt to provide a step change in development costs in the order of 30% lower than the standard well plan, with the goal of reducing drill and complete costs to an average of $1.1 million per well. No single change alone was found that could provide the required cost savings.

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