Impact of Inducing Fractures at Prudhoe Bay
- Brian D. Williams (BP Exploration (Alaska) Inc.) | David W. Sherrard (BP Exploration (Alaska) Inc.) | C.Y. Lin (BP Exploration)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- October 1989
- Document Type
- Journal Paper
- 1,096 - 1,101
- 1989. Society of Petroleum Engineers
- 5.6.4 Drillstem/Well Testing, 5.4.1 Waterflooding, 2.2.2 Perforating, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 5.5.8 History Matching, 4.1.2 Separation and Treating, 5.7.2 Recovery Factors, 5.5 Reservoir Simulation, 2.4.3 Sand/Solids Control, 4.1.5 Processing Equipment, 3 Production and Well Operations, 5.4.2 Gas Injection Methods, 6.5.2 Water use, produced water discharge and disposal
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Early step-rate tests (SRT's) on Prudhoe Bay water-injection wells showed that injecting cold (80 deg. F [27 deg. C]) seawater into the 200 deg. F [93 deg. C] Ivishak reservoir significantly reduced the formation fracture gradient.
To understand the fracturing process, in-depth studies of field injection trends, innovative pressure-transient analyses of step-rate data, interpretation of specially designed injection-well tests, and several simulation studies were conducted. After evaluating the impact of formation breakdown on areal and vertical sweep and on oil production rates, we concluded that potentially negative effects from inducing fractures with clean-water injection into the Ivishak formation are minimal, while benefits include accelerated oil production. As a result, an injection pressure limit above the thermally reduced formation fracture gradient has been defined and adopted.
The Prudhoe Bay oil field is on Alaska's North Slope. Rock quality in the Sadlerochit sand body, where the Ivishak sandstone is the main oil-bearing formation, is generally high, with permeabilities varying from 0.1 to 5 darcies [1.0 x 10-13 to 5.1 x 10-12 m2]. Production from the oil field is driven by a number of mechanisms, including gas-cap expansion, gravity drainage, miscible gas injection, and waterflooding.
Waterflooding in portions of the Ivishak formation began in 1984. The waterfloods are generally peripheral pattern floods composed of variations of inverted nine-spot pattems with interwell distances of about 1,500 ft [457 m] (Fig. 1). Currently, water from two sources is being injected. Beaufort seawater will remain the primary water supply during the project's early years; loiter, however, reinjected produced water will become the main source. The seawater is heated to about 80 deg. F [27 deg. C] at the wellhead, compared with a produced-water temperature of 150 deg. F [66 deg. C]. During early pilot testing and in the months following waterflood startup, seawater-injection wells (SWI's) typically indicated formation breakdown during SRT's at injection gradients of 0.53 to 0.54 psi/ft [12.0 to 12.2 kPa/m]. Produced-water injectors (PWI's) showed higher initial fracture gradients, from 0.57 to 0.60 psi/ft [12.9 to 13.6 kPa/m].
The apparent reduction in fracturing pressure with lower injected-water temperatures caused concern regarding waterflood management. It was realized that injection at subfracturing pressures would result in severe underinjection in many waterflood pattems; conversely, if injection were to continue for an extended period at pressures above the fracture gradient, vertical and lateral fracture growth was possible. Because vertical and areal sweep efficiencies could be affected, an investigation of the fracturing process began. The approach involved reviewing injection data, analyzing pressure-transient step-rate data, designing and analyzing results from special well tests, and performing a variety of simulation studies. The objectives were (1) to identify fracture initiation pressures, (2) to quantify the magnitude of fracturing and the impacts on flood performance, and (3) on the basis of Objectives 1 and 2, to define a realistic injection strategy.
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