Design, Installation, and Early Operation of the Timbalier Bay S-2B(RA)SU Gravity-Stable, Miscible CO2-Injection Project

Abstract

Summary This paper reviews the design, installation, and early operation of a gravity-stable, miscible CO2-injection project initiated in April 1984. The purpose of the project is to determine process economics, recoverable reserves, and operational difficulties to evaluate better the potential for fieldwide large-scale CO2 flooding. The results will also potential for fieldwide large-scale CO2 flooding. The results will also help to justify the major investments required to provide pipeline CO2 to the gulf coast oil fields. Introduction The Timbalier Bay S-2B(RA)SU project involves most phases of handling and processing CO2 for EOR. CO2 phases of handling and processing CO2 for EOR. CO2 was trucked, stored, pumped, pipelined, compressed, and injected. The injection rate, along with reservoir pressure, permeability, and dip angle, enabled the CO2 permeability, and dip angle, enabled the CO2 displacement to be both miscible and gravity stable. Cased-hole pulsed-neutron logs were used to track the reservoir displacement process. Purchased-CO2 injection began in April 1984 and was completed in June 1985. Field gas is used as a chase gas to push the CO2 through the reservoir. Project production is estimated to begin in late 1986. Produced CO2-contaminated gas will be dehydrated and Produced CO2-contaminated gas will be dehydrated and reinjected. To date, the facilities and reservoir displacement process have operated successfully with very few problems. problems. Timbalier Bay Field History The Timbalier Bay field is located in the coastal waters of Louisiana, 60 miles [97 km] south of New Orleans. Fig. 1 is a map showing the field's location. Discovered in 1937, the field has over 400 separate oil reservoirs developed by the drilling of more than 435 wells. Field production peaked in 1969 at a rate of 57,600 B/D [9158 production peaked in 1969 at a rate of 57,600 B/D [9158 m3/d] oil. Since that time, production has steadily declined and currently averages less than 4,000 B/D [636 m3/d]. The original oil in place (OOIP) for the field is estimated to have been 645 × 106 bbl [102.55 × 106 m3]. Cumulative production through 1984 has been 272 × 106 bbl [43.24× 106 m3] oil, Which is equal to a fieldwide recovery of 42% of OOIP. At the current level of operating expense and the present decline rate, the field will reach its economic limit in less than 8 years. Total ultimate recovery will approach 44 % of the OOIP. An estimated 365 × 106 bbl [58.03 × 106 m3] will remain as the resource base for enhanced recovery. Reservoir Characterization The S-2B(RA)SU was a saturated oil reservoir produced by a very strong water drive. The original-net-oil sand averaged 67 ft [20.4 m] thick and extended over 200 acres [81 ha]. Reservoir boundaries are shown on the structure map in Fig. Twenty-nine wells penetrated this sand at an average depth of 7,400 ft [2256 m]. A type log of the S-2B sand in Well 305 is shown in Fig. The reservoir was bounded on the east by faults and by an originaloil/water contact at 7,558 ft [2304 m] in all other directions. Two small splinter faults divided the reservoir into three segments: A-1, A-2, and A-3. Fig. 4 shows a cross section of the reservoir. As oil was produced, the common oil/water contact moved updip in a uniform manner. Reservoir characterization and geologic study indicated that the sand was continuous throughout the reservoir. Extensive shale zones above and below the S-2B sand effectively confined the injected CO2 to the target interval. Examination of the juxtaposed sand to the cast, across Fault B, showed the fault to be sealing. This prevented loss of CO2 in that direction. Whole core analysis from Well 286 showed a very clean sand with average unstressed horizontal and vertical permeabilities of 9.2 and 8.2 darcies, respectively. Overburden-corrected porosities averaged 30%, and the initial water saturation was porosities averaged 30%, and the initial water saturation was 11%. Additional reservoir rock and fluid data are given in Table 1. Pulse testing was considered for this project but was not feasible. It was determined that the reservoir's massive sand thickness, high permeability, and large storage capacity would absorb any reasonable pressure disturbance (pulse) before its arrival at any of the production wells. production wells. Production History Production History Initial production from the S-2B(RA)SU began in Jan. To date, 15 wells have produced from this reservoir. The OOIP was determined volumetrically to have been 20.7 × 10 6 bbl [3.3 × 106 m3]. SPEPE P. 369

Complex Flow and Composition Path in CO2 Injection Schemes from Density Effects

“…A number of other studies are based on the assumption that, when the injected CO 2 is lighter than the oil, the CO 2 injection is a stable gravity drainage process. [4][5][6]8,11,12 As we discuss in this work, this assumption may not be true. We point out that the CO 2 dissolution in water also results in a density increase.…”

Gravitational Fingering Due to Density Increase by Mixing at a Vertical Displacing Front in Porous Media

“…A number of other studies have been performed based on the assumption that when the injected CO 2 is lighter than the oil, the CO 2 injection is a stable gravity drainage process. ,− To clarify the effect of density increase on the fingering structure during the injection process, we performed the injection experiment using a fluid pair without density increase, namely, the fluid mixture did not exhibit an increase in density upon mixing. In this experiment, 31 wt % glycerine solution and 1 wt % NaCl were added into 10 wt % NaI solution (NaI + NaCl) to match the viscosity ratio and initial density difference of fluid pair B with that of fluid pair A, as shown in Table .…”

The CO2 Huff 'n' Puff Process in a Bottomwater-Drive Reservoir

“…As ofJan. 1,1986, when the projects were initiated, the sand cumulatively produced 4.165 Bcf [118x 10 6 m 3 ], 1.08 MMSTB [172x 10 3 stock-tank m 3 ], and 6.6 x 10 6 bbl [1.05 x 10 6 m 3 ] water.…”