Reservoir Performance of a Gravity-Stable, Vertical CO2 Miscible Flood: Wolfcamp Reef Reservoir, Wellman Unit

Abstract

Summary A gravity-stable, vertical CO2 miscible flood was implemented in the Wellman Unit Wolfcamp reef reservoir in 1983. CO2 was injected into the crest of the reservoir to displace the oil vertically downward, and water was injected into the lower water-swept region of the reservoir to maintain reservoir pressure at slightly above the minimum miscibility pressure(MMP). Excellent production response to increased CO2 injection was observed. The reservoir performance was encouraging and indicated excellent volumetric conformance and ultimate recovery. This paper reviews the operating strategy and project performance from inception through mid-1991. Introduction In recent years, vertical hydrocarbon miscible floods have been reported1–4 that use natural gas liquids, liquefied petroleum gas, or lean gas to achieve miscibility and to improve recovery in reefal reservoirs. To our knowledge, the application of gravity-stable vertical CO2 miscible flooding in a reef like Wellman field is unique. The Wellman field is a limestone reef reservoir in Terry County, TX, in the western Midland basin. At discovery, the reservoir contained 126 million STB of highly undersaturated oil and reservoir and bubblepoint pressures were 4,105psig and 1,375 psig, respectively. During the primary phase from discovery in1950 through early 1979, the field produced under a combination of pressure depletion and bottomwater drive. During the depletion phase, reservoir pressure declined to 970 psig, ~400 psi below bubblepoint (Fig. 1). The field was unitized in 1978 to implement a secondary recovery project. To maintain pressure, water was injected into the lower part of the reef just above the original oil/water contact (OWC) to displace the oil vertically upward. Water production in the primary and secondary phases was controlled by recompleting the wells upward. Fig. 1 shows waterflood performance. A vertical CO2 miscible flood was implemented in mid-1983 to improve recovery in the upper reservoir, which was not completely waterflooded, and to mobilize oil in the water-swept region. CO2 was injected into two crestal wells to move the oil vertically downward toward wells lower on the structure. Fig. 2 is a schematic of the various depletion stages during primary, secondary, and tertiary phases. After the CO2 flood was begun, sufficient water injection was continued into the flank wells to maintain reservoir pressure slightly above the 1,900-psig MMP. When oil prices dropped to ~$15/barrel in early 1986, the net CO2 injection rate (purchased volume) in the reservoir was reduced from 10 to 3.85 Mmscf/D. Injection continued at this rate until Nov.1989, when the purchased rate was increased to 15 Mmscf/D. Immediate response to the increased injection was observed. The production rate increased from1,750 to 2,400 BOPD in 5 months and stabilized at 2,300 to 2,400 BOPD inmid-1990. Field data are consistent with our previous technical studies and confirm that the vertical CO2 miscible flood is performing successfully. On the basis of the performance of the tertiary project through mid-1991, we estimate that 21 million STB of tertiary oil [i.e., 16.7% of original oil in place (OOIP)] will be recovered from the field. Reservoir Description The Wellman structure is a bioherm reef with a maximum closure of 824 ft above the original OWC at 6,680 ft subsea. The thick limestone accumulation, known as the Wolfcamp reef complex, is Permian age and was formed on the southwestern edge of the existing Pennsylvanian "Horseshoe Atoll." Vest5 gives a detailed geologic description of the Horseshoe Atollreef complex. Fig. 3 shows the structure on top of the Wolfcamp reef. The reef is oval-shaped and approximately 1.8 miles long and 1.4 miles wide, covering a1,306-acre productive area. Wolfcamp reservoir porosity is predominantly secondary in nature. Three different porosity types are identified in the rock:intercrystalline, vugular, and fracture. Scanning electron microscope photographs of the cores show that vugular porosity is significant throughout the reservoir. Although microfractures also have been noticed in the cores and the fracture identification log in Well 7–6, their contribution to porosity maybe small; however, production data indicate their significant contribution to permeability. Average porosity in the reef is ~8.5%, and the effective average core permeability is ~110 md. Tables 1 and 2 present reservoir and fluid properties at original and current operating conditions. The 43.5°API oil is highly undersaturated, and solution GOR above bubblepoint is ~450 scf/STB. Because of the predominantly secondary porosity in the Wellman field, volumetric estimation of OOIP cannot be made accurately. Therefore, the OOIP of126 million STB was determined by material balance with a 1D reservoir simulator and long-term production and pressure histories. For the material-balance calculation, the aquifer strength was known from the stabilized reservoir pressure achieved during 1958–66. The OOIP was verified later with the full-scale 3D model used for history matching. Reservoir pressure stabilization was observed during 1958–66 when the allowable production per well was restricted to 182 BOPD, indicating pressure support from the aquifer underlying the thick oil column (Fig. 1). At higher withdrawal rates before 1958 and after 1966, reservoir pressure was declining, indicating partial waterdrive. Therefore, a combination of limited solution-gasdrive, waterdrive, and gravity segregation was present during the primary production phase. Water influx analysis based on voidage calculations during several production periods shows a pressure dependency. At the stabilized2,000- to 2,100-psig pressure, water influx was estimated to be 3,325 B/D. Primary and Secondary Performance Primary Performance. The Wellman field was an excellent performer during primary production. After discovery in 1950, the field was developed on 40-acre spacing, and 33wells had been drilled in the field by 1953. Allowable restrictions dictated withdrawal rates from the Wellman field throughout the primary production phase. In 1958, the field rate was reduced to ~ 1,800 BOPD because of allowable restrictions imposed by the Texas Railroad Commission. From 1958 to 1965, the field produced at this rate and reservoir pressure remained essentially constant at ~3,050 psig (Fig. 1). Primary Performance. The Wellman field was an excellent performer during primary production. After discovery in 1950, the field was developed on 40-acre spacing, and 33wells had been drilled in the field by 1953. Allowable restrictions dictated withdrawal rates from the Wellman field throughout the primary production phase. In 1958, the field rate was reduced to ~ 1,800 BOPD because of allowable restrictions imposed by the Texas Railroad Commission. From 1958 to 1965, the field produced at this rate and reservoir pressure remained essentially constant at ~3,050 psig (Fig. 1).