A Decision Analysis Approach to Hydraulic Fracture Optimization in the W31S Stevens Oil Zone, Elk Hills Field, California

Abstract

Since 1999, hydraulic fracture stimulation in the layered W31S Stevens reservoir, Elk Hills, has increased productivity of new infill wells. One to six months increase in production of well over 300 percent in barrels of oil equivalent per day (BOEPD) has been achieved. Since 2002, optimization in treatment fluid has lead to a change from conventional borate cross-linked, guar-based polymers to new gel technologies with low polymer concentrations designed to minimize formation damage - an important consideration for the declining reservoir pressure and the low permeability rock in W31S sand. New available fluids combine stable downhole rheology with enhanced visco-elastic properties to provide good proppant transport capabilities. Infill drilling activity in the W31S zone has recently moved from the flank areas of the 31S structure to up-dip locations with higher vertical rock stress difference, less thick pay, and higher gas-to-oil ratios. Different fracture monitoring and diagnostic data, including a down hole treatment pressure survey, has been acquired to characterize fracture growth profile and to optimize the W31S fracture design model. Review of recent well performance and treatment data suggests that, though productivity gains are realized from improved clean-up characteristics of the new fracturing fluids, achieving full vertical coverage and design conductivity remains a great challenge. This has huge implications for the economics of the development drilling in the up-structure locations. This paper introduces a quantitative fracturing treatment option model as a useful communications tool for selecting the treatment with the best chance for economic success. Field History Elk Hills Oil Field is located 20 miles southwest of Bakersfield, California, on the west side of the southern San Joaquin Valley (Fig. 1). The field produces oil and gas from several reservoir intervals. Production depths range from 1,100 to 9,500 ft total vertical depth (TVD) and elevations range from 625 to over 1000 ft. The Stevens sands of the upper Miocene Monterey Formation[1] on the 31S structure, the largest of three deep structural anticlines at Elk Hills, were first produced in 1941. The Stevens B interval on the 31S feature consist primarily of the Main Body B (MBB) and Western 31S (W31S) reservoirs. The W31S reservoir is made up of two adjacent sand layers known as the Upper W31S and Lower W31S sands with low to moderate permeability at average depths of 6,000 ft (Fig. 2). Net pay ranges from 250 to 350 ft depending on well location at the varying dips of the structure. Average porosity is estimated at 22% and bottomhole static temperature (BHST) of about 1850F. In early 1998, following the acquisition of a major interest in the Elk Hills field by Occidental Petroleum Corporation and the subsequent takeover as operator for the asset, drilling activity in the W31S has been on the increase. Active producers and peripheral waterflood injectors average 52 and 33 respectively. Since 2002, up to 20 new in-fill wells have been drilled or side-tracked and completed in 10- or more acre spacing to target oil banked up structure by the expanding water-flood front. In addition to the waterflood support, hydraulic fracturing has been a major means of achieving better well productivity in the W31S reservoirs and the Upper MBB sands. The existing W31S fracture treatment design was optimized following comprehensive performance studies. Treatments size of between 90,000 to 105,000 lbs of proppant per 50 ft of net pay using 16/30 resin-coated sand has been used to create effective fracture half-lengths of 100 ft or more[2]. As a result; the steep decline in W31S production of 14% prior to 2002 was successfully reversed to an incline of above 30 % by 2003.