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Abstract

An aggressive hydraulic fracture stimulation program on program previously fractured wells in the Kuparuk River Field has increased production by 50,000 BOPD. The Kuparuk River Field is the second largest producing field in the united States with sixty-five percent of the reserves contained in a 20–100 md permeability sandstone. This paper describes results of a series of design improvements in an ongoing refracture program of oil wells in this moderate permeability formation. Over 185 of the 380 production wells have been refractured during the past five years. Long term production data are presented comparing productivities after the initial stimulations carried out in the early 1980's to the recent refracture stimulations. A twofold improvement in long term productivity is shown with changes in the treatment design: increased job size, different proppant types (ceramic vs. sand), proppant mesh sizes (10/14 and 12/18 vs. 20/40 and 16/20), and fluid types (gelled water vs. gelled diesel). The average productivity increase from 30 to 60 BOPD/net foot pay provided the economic justification for refracturing some wells a second time. Additionally, wells with high flow potential after initial stimulation have been refractured for substantial increases in oil rate.

Introduction

Since June 1983, over 880 fracture stimulations have been performed in the Kuparuk River Field. These treatments can be classified in two major groups, 680 initial fracture stimulations and over 200 refracture stimulations (refracs). Clearly, fracturing has played a primary role in the development of this major oil field. Evolution of the initial fracture designs and an introduction to the refrac program have been documented. This paper presents a review of the evolution, implementation, and results of this extensive refrac program.

The Kuparuk River Field is located in the Alaskan Arctic about 40 miles west of the Prudhoe Bay Field (Figure 1). The field was discovered in 1969, but-was not deemed economic for development until 1977, after completion of the Trans Alaska Pipeline. The reservoir covers 115,000 acres with over 5 billion barrels of original oil in place. The formation contained no gas cap upon discovery; primary recovery commenced in late 1981 by solution gas drive. In December 1985, a waterflood begin with the injection of Beaufort seawater. Two years later, immiscible gas injection was initiated in a water alternating gas (WAG) process. The majority of the field is now under secondary recovery receiving pressure support through a combination of waterflood and WAG injection. An enhanced recovery pilot is underway through WAG injection of miscible enriched gas. The field currently produces over 310 MBOPD with over 685 production and injection wells.

Initial development was on 160 acre well spacing with some 80 acre infill locations. Drilling continues to fully develop peripheral and infill areas. Wells with departures up to 10,000 feet are drilled from centrally located gravel pads to reduce the environmental impact to the Arctic tundra (Figure 2). The majority of the wells are drilled at an angle through the Kuparuk to-minimize drilling costs. The typical hole angle within the producing interval is 40. The interpretation of fracture treating pressures and height growth are complicated by the deviated wellbores. Special perforating strategies upon initial completion include oriented and aligned perforating to improve the effectiveness of fracture stimulation.

The Kuparuk reservoir produces from two horizons. A typical log of the Kuparuk interval is shown in Figure 3. The upper zone, the C Sand, is a very fine to coarse grained quartzose sandstone over 100' thick with over 80' of net pay. The C Sand was deposited upon a regional unconformity and has limited areal extent as shown in Figure 1. With average permeability of 130 md ranging up to 2600 md, the C Sand typically produces at rates from 1000 to 5000 BPD.

The A Sand, the lower producing zone, is present throughout the field and contains 65% of recoverable oil in ace. The average net thickness is typically less than 30 Feet, with permeability ranging from 20 to 100 md. It is a fine to very tine grained sandstone interbedded with shale and cemented with quartz and varying amounts of ankerite. The A Sand unit can be further divided into six distinct mappable subzones, A1 through A6 (Figure 1). Each of these subzones has variable reservoir quality across the field and typically one or two of these subzones dominate the A Sand productivity of any given well. The resulting A Sand permeability-thickness (kh) of wells across the field is similar, averaging 1000 md-ft upon initial completion and stimulation.

The B unit, made up of sands, siltstones, and shales, ranges in gross thickness from 0 to 150 ft. This high shale content nonpay interval provides an impermeable barrier to flow between the two producing zones. This barrier benefits the oil recovery at Kuparuk try allowing the two zones of distinctly different producing characteristics to be waterflooded separately. In addition, the B Sand provides the reservoir barrier to isolate the A Sand during hydraulic fracture stimulation.

Until 1990, field oil rate was dominated by the upper zone, the high permeability C Sand. Since that time, watercuts have increased with rapid waterflood breakthrough in the C Sands. The A Sand WAG/waterflood is much less mature. Waterflood breakthrough is limited to approximately 34 of 290 patterns. In most refracture stimulated wells, the A Sand zones produce at watercuts less than 5%. A surveillance program has been developed to effectively manage the dual zone waterflood and maximize recovery. The fracture stimulation program has played an important role in balancing the floods by increasing A Sand offtake.

Wells are typically completed with single tubing strings, a using packers and sliding sleeves or mandrels to allow isolation of the separate zones where both are present (Figure 4).

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