This paper presents a comparative well study performed in the central California Elk Hills field, Western 31S (W31S) Stevens Oil Zone. Stimulation of the W31S Stevens Oil Zone using hydraulic fracturing with conventional polymer fluids is compared with the use of a new viscoelastic high performance fracturing fluid (HPF).
The field development of the W31S zone was initially completed with conventional fracture-stimulated treatments containing borate crosslinked guar polymer and encapsulated oxidizing breakers. Although a positive production response was observed, additional production improvement was desired. Post-fracture tracer logs indicated that improvements could be made by achieving better net fracture height coverage. In addition, post-fracture acidizing treatments indicated that the fracture fluid polymer had damaged the propped fracture conductivity.
Recent development in fluid technology has resulted in the introduction of a unique, patented fracturing fluid that provides the following benefits:Less damaging to the formationExcellent proppant transportability, resulting in improved net fracture height coverageRequires no breaker additivesRecyclable
This HPF fluid was compared to conventional borate crosslinked polymers, a crosslinked CO2 foam fluid, and a high pH borate crosslinked polymer with an enzyme breaker. The case histories show better production rates with the new HPF fluid. Also, despite very robust and stable rheological properties during pumping, this new fluid returns to its original viscosity shortly after closure, with no internal breakers. The unique properties of this fluid are discussed, along with case history information, in the remainder of this paper.
Field History
Elk Hills Oil Field is located on the west side of the southern San Joaquin Valley of central California. It is positioned 20 miles southwest of Bakersfield and approximately 10 miles northeast of Taft (Fig. 1). The field was designated as the Naval Petroleum Reserve No.1 in 1912 to provide oil to the Navy in the event of a national emergency.1
Elk Hills Field produces oil and gas from several reservoir intervals highlighted on the stratigraphic column (Fig. 2). Production depths range from 1,100 to 9,500 ft total vertical depth (TVD). Initial production was established in 1911 from Pliocene age sands of the Shallow Oil Zone1 where production is related to a broad surface anticline with prominent topographic relief (Fig. 3).
In 1941, Stevens sands of the upper Miocene Monterey Formation1 were found to be productive on the 31S structure, the largest of three deep structural anticlines at Elk Hills (Fig. 2). Primary Stevens reservoirs on the 31S feature include the Main Body B (MBB) and Western 31S (W31S) of the B interval, (Figs. 3 and 4). The W31S reservoirs occur at an average depth of 6,000 ft and thick net pay development of 250 to 350 ft. W31S production was held in reserve with only periodic tests until the energy crisis of the mid-1970s. In 1976, the U.S. Department of Energy (DOE) began producing the interval.
A peripheral waterflood pilot was initiated in 19782–3 and expanded around the entire 31S structure by 1983. Development wells were drilled ahead of the flood front to capture oil banked by water moving up the structural flanks. Wells that watered out as the flood front advanced were shut in, converted to water injection, or recompleted to shallower zones to avoid cycling water.
In early 1998, Occidental Petroleum Corporation purchased the government's interest in Elk Hills and took over operatorship. Before the acquisition, due to prevailing high production rates from better quality sands of the Upper MBB and W31S reservoirs, stimulation treatments were not generally conducted, with the exception of occasional acid jobs. Hydraulic fracture stimulation had been applied on fewer than a dozen completions on the 31S structure in the lower quality sandstones of the Lower Main Body B and Upper W31S on the eastern nose of the structure.4
