Techniques for allocating historical production (oil and water) by layer for individual producers and waterflood patterns are presented. Production splits were approximated from offset injection histories (i.e. spinner profiles, hydrocarbon pore volumes injected, proximity to injection, and injection timing). The techniques presented include the following by layer:Production Gross & Oil Bubble MapsWater Cut MapsInjection Streamline MapsPattern Performance Graphs The tools are extremely useful and rapid when well counts and production histories are extensive such as in the Long Beach Unit with 1200 wells and 27 years of waterflooding. Reservoir material balance and pressures are not used in the split logic for a well but checked later for each pattern. Predicted splits and water cuts compared favorably with fullfield reservoir simulation results and field production logs. The allocation logic works in stratified formations where reservoir cross flow is minimal. Shales or other barriers between zones are required. The logic also requires that injection profiles, pressures, and injection-withdrawal ratios remain relatively constant. However, the logic can be applied over incremental time steps to handle dynamic changes in these parameters.

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SPE Member Abstract An aggressive workover program was undertaken from 1984 to 1987 at the Kuparuk River field on the North Slope of Alaska to recomplete older single completions with the more versatile selective single design. The two oil producing horizons (" C" and "A" Sands) have contrasting reservoir properties which complicate reservoir management. The recompletion allowed fracture stimulation of the "A" Sand which was easily damaged during drilling.. In addition, selective zone management in each production or injection well maximized reserves development under waterflood and gas reinjection. Eighty-six (86) of the field's 529 wells (16%) have been recompleted since 1984 at a total cost of $68 million (1987 dollars). This case history summarizes oil rate benefits and workover cost trends for use in future evaluation of remaining Kuparuk workovers. An economic evaluation approach for justifying injection workovers in a limited-capital environment is also included. Introduction The Kuparuk River field is the 2nd largest oil field in North America lying 40 miles (64 km) west of the Prudhoe Bay field on the North Slope of Alaska Approximately 1.5 billion STB oil (238 × 10 stock-tank m oil) are expected to be ultimately recovered with the aid of waterflood from an original oil-in-place (OOIP) of 4.5 to 5 billion STB oil (710 to 790 × 10 stock-tank m" oil)". Proposed field development could exceed 200 sq miles (518 × 10 m using 700 to 900 wells. To date 529 wells have been drilled on 160-acre well spacings (647 × 10(3) m2). Current oil production rate is 290,000 BOPD (46 × 10-1 m3/d oil) from over 300 producers. Full-field waterflood was commenced in late 1985 using sea water injection. Full field injection currently averages 550,000 BWPD (87 × 10 m3/d water) using over 170 wells on direct-line-drive and nine-spot patterns. Artificial lift is provided through gas lift. Approximately 250 million scf/D (7.1 × 10 std m3 /d) of produced gas is reinjected into the oil rim due to lack of a gas cap or sales market. Each of the current 36 gravel drill sites typically has 16 wells directionally drilled with an average hole angle of 45 degrees. The Kuparuk River sandstone is an oil-bearing Lower-Cretaceous sand/shale sequence divided into 3 major lithological units (" A", "B", and "C" Sands). An example type log is shown in Figure 1. The formation is a slightly-dipping anticline with depth varying from 5600 to 6300 ft (1707 to 1920 m). An impermeable siltstone overlays the "C" Sand providing the formation cap rock. The primary production mechanism is solution gas drive. Reservoir fluids were originally undersaturated preventing a formation gas cap. The upper unit (" C" Sand) is naturally fractured and most productive, ranging in rate from 1500 to 5000 BOPD (238 to 795 m3/d oil). Typical permeability values are 150 to 400 md with a net pay thickness up to 80 ft (24 m). Grain size for this sandstone ranges from very coarse, to very fine with siderite and quartz cementation. The "C" Sand has contributed most of the full-field rate since field startup in late 1981. This moderate permeability zone is typically stimulated using hydrochloric acid. The lower zone (" A" Sand) is less productive than the "C" Sand but areally more extensive providing 60% to 65% of the recoverable reserves. Average permeability is 60 md with a net pay thickness up to 35 ft (11 m). P. 529^

SPE Members Abstract The Long Beach Unit with 3 billion bbls of oil originally in place, is a part of the giant Wilmington Oil Field, the 4th largest field in the United States. In 1989, ARCO approached the City of Long Beach and State of California with a proposal to provide technology and capital needed to redevelop the field. The optimized waterflood program (OWP) agreement took effect on January 1, 1992 and today the LBU is producing more than 25% above the oil rate predicted from the base case decline. In addition, substantial reductions in both drilling and operating costs have been achieved. This paper discusses all aspects of the OWP agreement, including negotiations, technical studies, implementation, management philosophy and critical keys to success. Introduction The Wilmington Field, discovered in 1936, is largest field in the Los Angeles Basin shown in Figure 1. The Long Beach Unit (LBU) comprises the eastern portion of the field underlying the City of Long Beach and California coastal waters (Figure 2) in 30 ft of water. LBU production began in 1965 using directionally drilled wells from four man-made gravel islands and an onshore drill site located in the Port of Long Beach (Figure 2). Waterflooding was implemented at field start-up to improve recovery and prevent subsidence which was observed in older portions of the Wilmington Field during the 1950's. LBU production peaked in 1969 at 148,000 BOPD Current production is 46,000 BOPD and 557,000 BWPD from 640 active producing - wells using electrical submersible pump (ESP) as the primary artificial lift method. Gravel packs are required for unconsolidated sand control. Waterflood patterns vary by zone and area with 340 injection wells used in peripheral, line-drive, 5- spot, and inverted 7-spot patterns. Cumulative production to date is 800 million bbls oil (27% of original oil in place). Unit Operator is the City of Long Beach (City) through it's Department of Oil Properties. The City acts as trustee for the State of California (State), which receives the majority of Unit profits. Daily field operations are managed by THUMS Long Beach Company (THUMS), under the direction of the City. THUMS, now owned by ARCO, was originally a consortium of Texaco, Humble [Exxon], Unocal, Mobil, and Shell. The roles of the City as Unit Operator and THUMS as field contractor continue today as they did before the optimized waterflood program. GEOLOGY The Wimington structure is an asymmetrical anticline. Oil production is from lower Pliocene and upper Miocene rocks from 3000 to 7000 ft in depth. P. 241