Fracture Stimulation Optimization in the Redevelopment of a Mature Waterflood, Elk Hills Field, California

Abstract

This paper is a case history describing fracture optimization of low-permeability highly-stratified stacked turbidite sandstone reservoirs of the B interval of the Elk Hills Field. The occurrence of high-permeability, high-pressured water saturated sands immediately above and/or below the objective oil sands poses a major challenge. Integration of improved petrophysical understanding, geoscience techniques, hydraulic fracture model calibration and on-site, real-time execution has achieved a two-fold oil production increase in the south east nose area of the field while limiting water production to a 40% increase. Downhole tiltmeter measurements are incorporated to calibrate the fracture model and limit fracture height growth, thus regulating fracture conductivity to the oil saturated reservoirs, and minimizing contact with the adjacent wet zones. To date, results from surface tiltmeter1 measurements completed during twenty six fracture stages have been used with the downhole tiltmeter2 data and reservoir characterization to optimize the ongoing redevelopment from a peripheral waterflood to a pattern flood. Introduction 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 (Figure 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. Elk Hills Field produces oil and gas from several reservoir intervals highlighted on the stratigraphic column, (Figure 2). Production depths range from 1,100 to 9,500 ft, TVD. Initial production was established in 1911 from Pliocene age sands of the Shallow Oil Zone where production is related to a broad surface anticline with prominent topographic relief (Figures 1–2). In 1941, Stevens sands of the upper Miocene Montery Formation were found to be productive on the 31S structure, the largest of three deep structural anticlines at Elk Hills (Figures 2–3). Primary Stevens reservoirs on the 31S feature include the Main Body B (MBB) and Western 31S (W31S) of the B interval, and the younger, prolific 26R pool (Figures 3–5). Secondary objectives include sands in the B Shale zone and the siliceous shales or sands in the NA and CD Shale zones that lie above and below the B interval, respectively. MBB/W31S reservoirs occur at an average depth of 6,500 ft and exhibit 2,800 ft of vertical closure between the up-dip pinchout of the sands near the anticlinal crest and the Oil-Water Contact at −6,800 ft, subsea depth. These zones have abnormal reservoir pressure (0.50 psi/ft), good permeability (10 to 250 md, air permeability) and thick net pay development (300 to 500 ft). MBB production was held in reserve with only periodical tests until the energy crisis of the mid-1970's. In 1976, the U.S. Department of Energy (DOE) began producing the interval at initial rates ranging from 500 to 2000 BOPD per well.

An Independent Scientific Assessment of Well Stimulation in California Volume II: Potential Environmental Impacts of Hydraulic Fracturing and Acid Stimulations

“…Fisher and Warpinski (2012) compared microseismic data on fracture extent and found that fractures in shallower formations (<1,200 m, or 3,900 ft) have a greater horizontal component, and that deep hydraulic fractures should not be vertically extensive such as to contact shallow aquifers. This paper, however, also stated that earlier work found orientations dependent on the unique stress profiles and rock fabric of a given location (Walker et al, 2002). Coupled flow-geomechanical modeling (Kim and Moridis, 2012) found inherent physical limitations to the extent of fracture propagation-for example, the presence of overlying confining formations may slow or stop fracture growth in the vertical direction, thus containing fractures within the reservoir (Kim et al, 2014).…”

“…This research applies to deep formations and thus evaluates pathway formation scenarios over large vertical distances. Fracturing has been practiced in California for decades (Walker et al, 2002), but fundamental studies of fracturing behavior, fracture propagation, and the orientation of fractures relative to reservoir depth for California geology are lacking. Fully understanding this behavior is particularly important in California due to the possibility of relatively shallow fracturing depths (200-300 m [650-1,000 ft] from surface) compared to other regions using hydraulic fracturing technology.…”

Applied Reservoir Management Principles with Case Histories

“…The data collected from the evaluation well and subsequent analyses laid the groundwork for conversion of the project from peripheral to pattern waterflooding. Much of the latter analyses were reported by Hampton et al 7 and Walker et al 8 Both papers illustrate the reservoir management principle of application of improved technology to an existing wellmanaged project. Finally, the MBB/W31S Waterflood Project benefited immensely from long-term retention of staff in a multi-disciplinary team.…”

Improved Fracture Stimulation Revitalizes the Western 31S Stevens Oil Zone, Elk Hills Field, California

“…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 Fracturing connects the good sand bodies and the thin stringers of sand into a single flow unit delivering hydrocarbon into the wellbore.…”