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
This paper reviews the design, implementation, and performance of a miscible CO 2 water-alternating-gas (WAG) project in a U.S. gulf coast reservoir. The field-test data obtained since the inception of the project in Oct. 1981 are presented, and solutions to such operational problems as downhole corrosion are discussed. Remarkable project response and recovery demonstrated that the CO 2 WAG process is technically viable for mobilizing considerable amounts of residual oil from watered-out Miocene reservoirs. A 16.9% recovery of original oil in place (OOIP) was obtained with a CO 2 slug size of 18.9% original HCPV. The CO 2 requirement was 2.57 Mcf/bbl [458 m 3 /m 3 ] of oil recovered.
Production allocation from petroleum geochemistry is defined here as the quantitative determination of the amount or portion of a commingled fluid to be assigned to two or more individual fluid sources (e.g., a pipeline, field, reservoir, well) at a particular moment in time, based on the fluid chemistry. It requires: i) knowledge of the original chemical compositions of each of the fluids prior to mixing (referred to here as the "end members"), and ii) that statistically valid differences in their chemistries can be identified. Petroleum geochemical-based methods for production monitoring and allocation are much lower cost than using production logging tools, as there is no additional rig time or extra personnel required at the well site. Additionally, no intervention to the production of hydrocarbons from a well is required and, hence, there is none of the risk entailed in additional operational activity. Geochemical methods are applicable to a wide range of fields, irrespective of pressure, temperature, reservoir quality and reservoir fluid type. The method has been in existence for over 30 years, during which time a number of different analytical methods, data pre-processing and treatment approaches have been applied. This paper summarises these approaches, and provides examples, but also describes a "best practice" which is not a "one size fits all" approach, as is sometimes seen in the literature. A successful production allocation study consists of the following steps: i) Selection of end member samples that contribute to the commingled production fluid; ii) Determination of the differences in chemical composition of the end members through laboratory analysis of the end members (e.g. by WO-GC), replicate analyses of samples and statistical treatment of the data (e.g. PCA); iii) If statistically significant differences exist, laboratory analysis of the end members and commingled fluids with appropriate replicate analyses of samples; iv) Data selection, pre-processing (e.g. selection of ratios or concentrations of components); v) Determination of end member contributions by solving equations (e.g. least squares best fit) and uncertainty estimation (e.g. Monte Carlo or Bootstrap methods). The differences in approach for conventional versus unconventional plays are also discussed.
Summary Steamfloods conducted in thin reservoirs generally provide marginal profits because of relatively high field provide marginal profits because of relatively high field development costs per barrel of oil in place (OIP) and excessive heat losses from the productive zone. New techniques are being used to solve these problems, such as use of induced horizontal fractures to circumvent the detriments attributable to thin zones and to solve the problems of steam distribution and confinement inherent problems of steam distribution and confinement inherent in any steamflood. This paper documents the successful application of steamflooding in the multiple thin-sand reservoirs of the Loco Unit, Stephens County, OK. These reservoirs occur at depths from 50 to 1,200 ft [15 to 366 m] and range in thickness to 40 ft [12 m]. Porosities of the productive zones vary from 20 to more than 30%, and permeabilities range from 100 to more than 4,000 md. Oil gravities of the various zones range from 16 to 24API [0.96 to 0.91 g/cm3]. Table 1 presents average reservoir properties of the three most important zones in the area of principal interest. Reservoirs that occur at depths above approximately 700 ft [213 m] have little or no natural reservoir energy and generally contain viscous oils, ranging up to 10,000 cp [10 Pa.s]. Consequently, there was no primary production from these reservoirs, and potential for waterflooding was marginal. Steamflooding has been the only recovery process applied successfully to these zones, except for one isolated instance. Reservoirs at depths greater than 700 ft [213 m] normally contain lower-viscosity oils. Six of these zones were produced by solution gas drive and were later waterflooded successfully. After 23 years of water-flooding, two of these six zones have been tested and have proved to support commercial steamflooding operations. Introduction The Loco field is situated on a northwest-southeast trending anticline that underlies a major portion of Township T3S-R5W, Stephens County, OK, at approximately the location indicated in Fig. 1. The field was discovered in 1913, and sporadic development occurred from that time until the 2,300-acre [931-ha] unit was formed in 1961 for the pursuit of secondary recovery operations. From 1961 through 1964, the field was developed on 10-acre [4.05-ha] spacing, and water-flooding of the six deepest zones was initiated, using 20-acre [8.09-ha], five-spot patterns. Geology and Reservoir Description. Twenty-four identified zones have been proved to have, or are suspected of having, significant oil saturation in at least some areas of the unit. The most significant of these are illustrated in the log section of Well 511 presented in Fig. 2. The various oil sands have been named alphabetically ascending (As, Bs, Cs, etc.) and descending (Ad, Bd, Cd, etc.) from the Loco lime (LL), which occurs at a depth of 800 to 900 ft [244 to 274 m]. Three zones (X, Y, and Z) of minor areal extent are located between the LL and the A-shallow (As) sand. The LL and the five deep sands are of Hoxbar-Pennsylvanian age. A fault trending northeast-southwest displaced this interval approximately 100 ft [30 m]. The original OIP in the six deep zones is estimated to be 73.4 × 10(6) bbl [11.7 × 10(6) m3]. These zones have had primary recoveries of approximately 3 % of the original OIP, and waterflooding, which was initiated in 1961, will ultimately recover an additional 11 %. The shallow sands, which lie above the LL, are of Pontotoc-Permian age and are not affected by the Pontotoc-Permian age and are not affected by the faulting. Minimal natural reservoir energy has precluded significant primary recovery, and the adverse mobility ratios inherent to the native oil viscosities make waterflooding generally impractical. A notable exception to this rule was a 20-acre [8.09-ha] waterflood of the As and Cs zones, which was conducted in the southeast quarter of Sec. 9 from 1956 to 1963; this was a marginally profitable operation. No response was observed in a profitable operation. No response was observed in a 10-acre [4.05-ha] X-zone waterflood, which was operated during this time interval in the southwest quarter of Sec. 9. From 1969 through 1972, pilot waterfloods were conducted in the As, Bs, Ds, and Js sands, none of which were successful. JPT P. 1707
Summary. This paper presents the results of a CO2, flood pilot performed in the Permian Age carbonate rock formations of the Maljamar Cooperative Agreement (MCA) Unit. Field background and pilot development are reviewed. Injection and production history are presented, along with an evaluation of the pilot. A summary of the observation well logging results is also given. Introduction The 5-acre (20X10-3 -m2) Maljamar tertiary recovery pilot formally ended Jan. 1, 1986. Special features of the inverted five-spot pilot included dual (separate) completions in the Grayburg and San Andres zones and two fiberglass-cased logging observation wells for in-situ monitoring of oil, brine, and CO2 movement. Solutions to operational problems and a determination of the process performance were intermediate objectives of the pilot. The major objective was to provide a basis for commercial scale CO2 floodline economics for, the unit. CO2 retention by the reservoir has prevented major CO2 production. The observation wells indicated that CO2 contacted the entire vertical section. Operating problems and pilot performance have been different for the two zones. Problems, injectivity, oil response, and CO2 production will be discussed by zone. The pilot successfully met its objectives by providing data on field operations during CO2 flooding, as well as the process performance data needed to estimate largescale CO2 flooding results in the field. Operating problems have been largely resolved, incremental oil production has peaked, and performance has been encouraging. An expansion project is being designed. General Information The 8,040-acre [ 32 × 10 6 -M 2 ] MCA Unit occupies about 20% of the Maljamar field in Western Lea County, NM (Fig. 1). Wells produce from a Grayburg dolomitic sand (Sixth zone) and four San Andres dolomite pay zones (Upper Seventh, Lower Seventh. Upper Ninth, and Ninth Massive) at depths ranging from 3,600 to about 4,100 ft 1100 to about 1250 m], Fig. 2 presents a typical log. Oil gravity is 35 to 37deg. API [0.85 to 0.84 g/CM3]. Reservoir and fluid characteristics are shown in Table 1. The MCA Unit has performed well under waterflood, considering that it is a multizone flood in a heterogeneous reservoir. The better-quality zones. Sixth and Ninth Massive, have performed very well. At the economic limit for the existing waterflood, about 60% of the original oil in place (OOIP) would remain unrecovered. thereby making this a significant target for EOR operations.' The technical feasibility of CO2 flooding was demonstrated experimentally by determination of the minimum miscibility pressure (MMP) in slim-tube floods. At 1,515 psi [10.4 MPa]. the MMP is considerably lower than the average reservoir pressure of about 2.1500 psi [ 17.2 MPa]. Feasibility studies were performed for several different CO2 flood options in the field. Because of the economic risks associated with a commercial-scale project, the decision was made in 1978 to develop a pilot project for the MCA Unit. Information from the pilot would reduce the operational and economic uncertainties of a full-scale project. The pilot was expected to provide information on whether CO2 can mobilize oil in the reservoir, on how much CO2 would be required for a barrel of oil recovered. on how the CO2 injection rates would change with time, and on what values of process parameters should be used in simulations to predict field-scale CO2 flooding operations. Separate floods were conducted in the Sixth (the Grayburg sand interval) and the Ninth Massive zones (representative of the San Andres zones). The two floods were performed simultaneously by use of dual (separate) completions in the pilot wells. Two logging wells, completed with 680 ft [207 m] of fiberglass casing across the pay intervals and with no perforations, were also included. Logging data from these wells would allow determination of vertical variations in horizontal permeability and values for process parameters. An inverted five-spot pattern was selected to decrease the total volume of CO2 that would have to be purchased. At the time, there were indications that decisions about field-scale expansion would have to be made within 2 to 3 years to be confident of securing a CO2 supply. Five acres [20 × 103 M2) was chosen as the largest pilot that could be completed in a reasonably short period of time. Fig. 3 shows the final pilot pattern. Operating Plan The pilot development and prepilot planning and testing were reported previously. 1 Pilot development and operation consisted of the six phases shown in Fig. 4. JPT P. 1256^
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