Slope and basin clastic reservoirs in sandstones of the Delaware Mountain Group in the Delaware Basin of West Texas and New Mexico contained more than 1.8 billion barrels (Bbbl) of oil at discovery. Recovery efficiencies of these reservoirs have averaged only 14 percent since production began in the 1920s, and, thus, a substantial amount of the original oil in place remains unproduced. Many of these mature fields are nearing the end of primary production and are in danger of abandonment unless effective, economic methods of enhanced oil recovery can be implemented. The goal of this Class III project is to demonstrate that reservoir characterization, using outcrop characterization, subsurface field studies, and other techniques, integrated with reservoir simulation, is a cost-effective way to recover more original oil in place by geologically based field development.
The project is focused now on reservoir characterization of the East Ford unit (Dutton and others, 1999), a representative Delaware Mountain Group field that produces from the upper Bell Canyon Formation in the Delaware Basin (figure 1). The field, discovered in 1960, is operated by Orla Petco, Inc., as the East Ford unit; it contained an estimated 18.4 million barrels (MMbbl) of original oil in place. The main reservoir in the East Ford unit is the Ramsey sandstone in the upper Bell Canyon Formation (figure 2). Earlier reservoir characterization for this project was conducted on the Ford Geraldine unit (Dutton and others, 1997), which is immediately adjacent to the East Ford unit and produces from a branch of the same Ramsey sandstone channel (figure 3). Abundant subsurface data were available from the Geraldine Ford unit for reservoir characterization, including cores from 83 wells, core analyses from 152 wells, and 3-D seismic over the entire unit. In contrast, the smaller subsurface data base from the East Ford unit is more typical of most Delaware sandstone fields. Reservoir characterization of the East Ford unit has provided an excellent opportunity to test the transferability of the reservoir model and the methodology developed during reservoir characterization of the Ford Geraldine unit to another Ramsey sandstone field.
Upper Permian (Guadalupian) Delaware Mountain Group strata compose a 3,500-ft-thick succession of slope and basin deposits in the Delaware Basin that are important contributors to Permian Basin production. Production from the Ford Geraldine and East Ford units and other upper Bell Canyon fields in the Delaware Basin occurs from the distal (southwest) ends of east-dipping, northeast-oriented linear trends of thick Ramsey sandstone deposits (figure 4). Most hydrocarbons in these fields are trapped by structurally updip facies changes from higher permeability reservoir sandstones to low permeability siltstones (Dutton and others, in press).
Interpretation of the reservoir sandstones at the East Ford unit was based strongly on characterization of upper Bell Canyon exposed in outcrop. Outcrops of the Bell Canyon Formation are present within 25 mi of the East Ford unit. These outcrops were studied to better interpret the depositional processes that formed the reservoirs at the Ford Geraldine and East Ford units and to determine the dimensions and characteristics of reservoir sandstone bodies in well-exposed sections (Barton and Dutton, in press).
Stratigraphic relationships indicate that the outcrop sandstones were deposited in a basin-floor setting by a system of leveed channels having attached lobes and overbank splays that filled topographically low interchannel areas (figure 5). The sandstones are interpreted as having been deposited by sandy high- and low-density turbidity currents. Lobe sandstones, as much as 25 ft thick and 2 mi wide, are composed of massive or structureless sandstones, and they display a broad tabular geometry. Channels, as much as 60 ft thick and 300 to 3,000 ft wide, are largely filled with massive and cross-stratified sandstone. Flanking the channels on both sides are wedges composed of thinly bedded sandstone and siltstone that are interpreted as levees. The levees thin away from the channel, decreasing in thickness from 20 to 3 ft over the distance of 0.5 mi. The levees are onlapped by massive sandstones interpreted as overbank splays having an irregular geometry.
Individual channel-levee and lobe complexes appear to stack in a compensatory fashion and are separated by laterally continuous, 3-ft-thick laminated siltstones. The laminated siltstones are interpreted to have been deposited by the settling of marine organic matter and airborne silt during periods when coarser particles were prevented from entering the basin.
Subsurface mapping, study of Bell Canyon sandstones in outcrop, and descriptions of Ramsey sandstone cores from the adjacent Ford Geraldine unit indicate that reservoir sandstones at the East Ford unit were deposited by turbidity currents in a deep-water channel-levee and lobe system. Ramsey sandstone channels at the East Ford unit, 1,000 to 1,500 ft wide and 15 to 30 ft thick, are flanked by levee deposits (figure 6). Lobe facies were deposited at the mouths of channels. Throughout the East Ford unit, the Ramsey sandstone is divided into two sandstones (Ramsey 1 and Ramsey 2) separated by a 1- to 3-ft-thick laminated siltstone (SH1). The best leases in the field produce from what are interpreted to be channel facies in the Ramsey 1 and 2 sandstones near the center of the unit (Dutton and others, 1999). The thickest part of the Ramsey 2 channel occurs somewhat to the west of the Ramsey 1 channel, suggesting that the Ramsey 2 sandstone was deposited in the topographic low to the west of the thick Ramsey 1 sandstone (figure 7). The SH1 siltstone, though thin, is significant in that it will affect displacement operations. Because of the low permeability of the siltstone, there will be very limited cross flow of fluids between the two sandstones.
Reservoir characterization also focused on applying petrophysical techniques to the mapping of reservoir properties in the East Ford unit. Our approach to quantitative petrophysical analysis using old log suites was developed in the Ford Geraldine unit because of the abundant core and core-analysis data available (Asquith and others, 1997). We started from traditional methods of log interpretation and integrated them with new methods for (1) determining true formation resistivity (Rt) from Deep Laterologs (LLD) and (2) calculating saturation exponent (n) using core porosity and water-saturation values from relative permeability curves. Much of the approach, but not all, was transferred successfully to the East Ford unit, where the technique was modified to calculate water saturation. The result was a set of maps of porosity (figure 8), permeability (figure 9), net pay, water saturation, porous hydrocarbon volume, and other reservoir properties across the unit. The maps of average porosity and permeability exhibit a strong north-south trend that follows the positions of the Ramsey 1 and 2 sandstone channels.FIELD DEVELOPMENT HISTORY
Primary recovery in East Ford field began in October 1960 and continued until June 1995. A total of 45 wells were drilled for primary production. Primary cumulative oil production was 3,209,655 bbl. An estimated 10 percent of the total production, or 320,966 bbl, was from the Olds sandstone. The estimated 2,888,690 bbl produced from the Ramsey sandstone represents 15.7 percent of the 18.4 MMbbl of original oil in place. Remaining oil in place (ROIP) in the Ramsey sandstone is 15.6 MMbbl.
Primary production data in the East Ford unit were collected by lease, not by individual well. To map primary oil production, production for each lease was plotted at the geographic center of the wells that produced from the Ramsey sandstone (figure 10). Highest production at the north end of the field occurs along the position of the Ramsey 2 channel, whereas at the south part of the field the highest production is shifted to the east, at the position of the Ramsey 1 channel.
The East Ford unit, like other Delaware sandstone reservoirs, is characterized by relatively high amounts of mobile water at the time of discovery. Primary recovery by solution gas drive was low, less than 16 percent. Among the reasons for the low primary production are (1) the small amount of gas in solution with the oil to act as a driving force, (2) the expenditure of considerable solution-gas drive energy in the recovery of water from the reservoir, and (3) the lack of pressure support from the aquifer owing to the limited water influx (W. Flanders, written communication, 1994).
Because waterflooding in Ramsey sandstone reservoirs in other fields has not been very successful, the East Ford unit did not undergo secondary recovery by waterflooding. In the Ford Geraldine unit, waterflooding added only an estimated 3.5 percent of the OOIP to the total recovery by the end of secondary development. Waterflood recoveries in Ramsey sandstones have been low because of poor sweep efficiency caused by (1) abundant mobile water present when the waterflood was started and (2) water injection above the formation parting pressure. Geologic heterogeneity caused by depositional and diagenetic processes may also reduce secondary recovery in Delaware sandstone reservoirs. Laminated siltstone beds and extensively calcite-cemented sandstones cause reservoir complexity and may reduce sweep efficiency
Tertiary recovery in the East Ford unit by CO2 injection began in July 1995, and production response to the CO2 injection was observed in December 1998. During Phase 2 of the project, production from the East Ford unit will be monitored and compared with predictions made on the basis of flow-model simulations. This comparison will provide an opportunity to evaluate the success of these operations and to test the accuracy of reservoir-characterization and flow-simulation studies as predictive tools in resource preservation of mature fields.
To estimate the tertiary recovery potential, we applied the results of fluid-flow simulations of a CO2 flood in the Ramsey sandstone to the East Ford unit. The area simulated was the north end of the Ford Geraldine unit (Malik, 1998), which is similar to the East Ford unit, both in terms of reservoir thickness and in the separation of the Ramsey sandstone into two parts by the SH1 siltstone. Independent estimates of tertiary recovery from the East Ford unit were made on the basis of the results of the CO2 flood performed in the south part of the Ford Geraldine unit. Both methods of estimating tertiary recovery in the East Ford unit indicate that a minimum of 10 percent, and as much as 30 percent, of remaining oil in place is recoverable through a CO2 flood. Original oil in place in the CO2 flood area within the East Ford unit was approximately 14.7 MMbbl, and of that, 2.5 MMbbl were produced during primary production. Of the 12.2 MMbbl of remaining oil in place in this area, an estimated 1.2 to 3.7 MMbbl is recoverable through CO2 flood.
This research was funded by the U. S. Department of Energy under contract no. DE-FC22-95BC14936, by Conoco, Inc., and by the State of Texas under State Match Pool Project 4201 and as part of the State of Texas Advanced Resource Recovery project. The Bureau of Economic Geology acknowledges support of this research by Landmark Graphics Corporation via the Landmark University Grant Program.
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