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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.
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.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractApplications of technically sound reservoir management strategies to new and old reservoirs are important for maximum economic recoveries. Correct identifications of key geologic features, rock properties, state of reservoir fluids and major recovery mechanisms determine applicable reservoir management strategies. The critical decisions are selections of strategies that consider all available data and incorporate current technologies. The management strategies applied must be economic, conserve reservoir energy and adaptable to emerging technologies. Five reservoir management principles are presented as guides for determination and implementation of reservoir management strategies. The reservoir management principles are:1. Conservation of reservoir energy 2. Early implementation of simple strategies 3. Sustained and systematic collection of data 4. Continuous application of improved recovery technologies 5. Long term retention of staff in multi-disciplinary teams Case histories of 26R Reservoir, MBB/W31S Reservoirs, Luling and Slick Reservoirs are reviewed to illustrate the applications of the five reservoir management principles. The main objective of the report is to demonstrate through case histories that applications of the five reservoir management principles lead to technically sound reservoir management strategies that lead to maximum economic recoveries.
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
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