Proppantless Fracture Stimulations in Injection Wells - A Case History (1996)

Abstract Development of proppantless fracture stimulations has successfully increased injection in water injection wells at the Kuparuk River Field on the North Slope of Alaska. This technique has greatly evolved since mid 1994 to become the main method of increasing injection support into the waterflood patterns at the Field. This paper presents a case history of the evolution of the proppantless fracture stimulation program (termed High Pressure Breakdown - HPBD), including an analysis of why the treatments are successful. It also summarizes the significant cost savings over conventional propped fracture methods. Introduction Kuparuk River Field Fracturing. The Kuparuk River Field is located in the Alaskan Arctic about 40 miles west of the Prudhoe Bay Field. The Kuparuk reservoir primarily contains two producing horizons that have dramatically different producing characteristics (Fig. 1). A shaley-sand sequence that ranges in thickness from 0 to 150 feet separates the intervals. The C Sand or upper producing interval, consists of a very coarse to very fine-grained siderite and quartz cemented sandstone, with permeability ranging from 100 md to over 1000 md and net pay thickness of up to 80 feet. This sand is capable of producing at rates from 1000 to 6000 BPD. The A Sand or lower producing interval is present throughout the field (Fig. 2) and is a fine to very fine-grained sandstone interbedded with shale and cemented with quartz and varying amounts of ankerite. The A Sand, which contains over 65% of the field's producible reserves, has an average net pay thickness of less than 30 feet with permeability ranging from 20 to 100 md. The A Sand requires hydraulic fracture stimulation to achieve economic, if any, flow rates. Post-fracture flow rates stabilize in a range from 200 to 3,000 BPD depending on reservoir quality. A large scale hydraulic fracture and refracture program has resulted in successful development of the A Sand and significantly expanded the economic acreage of the field. Both Sands receive secondary and tertiary pressure support which is provided in the form of water and/or water-alternating-gas (WAG) injection aligned primarily in line-drive flood patterns. The majority of the Field is developed on 160 acre well spacing; however, some areas are currently being infill drilled on 80 acre spacing and converted to 5-spot patterns. Most wells inject water at pressures which exceed the virgin fracture gradients of the reservoir by 500-1500 psi. To completely support offtake, produced water injection is supplemented with seawater taken from the nearby Arctic Ocean via a Seawater Treatment Plant. As a result of the successful producer fracture program, injection support has not kept up with these increased withdrawals in some areas. In addition, excursions in the total suspended solids (TSSs) and total suspended oils (TSOs) in the produced water system have actually caused decreases in the injectivity of produced water injectors over the years. This paper outlines the development and application of the HPBD stimulation treatments at Kuparuk It introduces the case history of the evolution of the technique, outlines the possible reasons for its success, and gives preliminary results. Finally, the large cost savings realized from using this technique versus conventional propped fracture stimulations are also discussed. HPBD DEVELOPMENT HPBD Inception. Until 1993, most of the fracture stimulation emphasis was put on increasing withdrawals from the production wells. Injection well stimulations were few and largely ineffective, consisting of chemical type treatments (acids, bleach, mutual solvent, etc.) to remove near wellbore damage. In late 1992 and 1993, seventeen injection wells (out of a 169 well fracture program) were targeted for conventional propped fracture treatments, utilizing the same techniques as used for the producer fracture program. P. 471