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Collaborating Authors
Harpole, K.J.
Abstract Stimulation of sandstone reservoirs usually involves the use of a hydrofluoric-based acid (HF). Hydrofluoric acid reacts rapidly with clay minerals and slowly with sand particles. Stimulation of sandstone formations is a challenging task because it involves several chemical and physical interactions of the acid with the formation. Some of these reactions may result in formation damage. Retarded HF (RHF) acids are less reactive with the rock and normally result in deep acid penetration into the formation. Three RHF acids that are based on boric acid (H3BO3), aluminum chloride (AlCl3), and a phosphonic acid were examined. Several tests were conducted to evaluate interactions between RHF acids and sandstone rocks. Static solubility tests were performed using sand particles and clay minerals at 25 and 75°C. Chemical analysis of spent acids was extensively used in this study. Acidizing sandstone reservoirs using mud acid is a complex process where dissolution and precipitation occur simultaneously. The process is even more complicated when RHF acids are used. The results of this study indicate that the composition of spent acid strongly depends on the retarded system used. Dissolution of clays is generally reduced when a form of RHF is employed. However, increasing the soaking time caused precipitation in all RHF acids examined. Some of the RHF acids precipitate materials that are not encountered when regular mud acid is used. This paper addresses several chemical interactions that have not been addressed previously in the literature. Introduction Sandstone formations consist of four main categories of minerals: silica (quartz), feldspars, clays, and carbonates. Mud acid is a mixture of hydrochloric acid (HCl) and hydrofluoric acid (HF). This mixture can be prepared at different HCl:HF mass ratios to prevent the formation of damaging precipitates. The goal of retarded HF acids is to decrease the reaction rate of HF with alumino-silicates (clays and feldspars) to achieve a sufficient acid penetration into the formation and remove deep damage. A through literature review indicates that there are at least three main retarded HF systems. A brief summary of each acid system is given below. The first system (BRHF) is based on fluoboric acid (HBF4). Fluoboric acid can be generated by the reaction of boric acid (H3BO3) with HF (Eqs. 1 & 2). Fast Reaction:Equation (1) Slow Reaction:Equation (2) As HF spends on siliceous minerals, HBF4 hydrolyzes to regenerate HF (Eq. 2). The second system (ALRHF) is based on aluminum chloride (AlCl3). Aluminum chloride reacts with HF to form aluminum fluoride species (Eq. 3).Equation (3) As HF spends on siliceous minerals, AlF4 - hydrolyzes to regenerate HF (Eq. 4).Equation (4) The third system (PRHF) is based on using a phosphonic acid complex that contains five hydrogen atoms. This acid reacts with ammonium bifluoride to produce an ammonium phosphonate salt and HF. The fluoride ions are provided by the ionization of dissolved ammonium bifluoride. To form HF, hydronium and fluoride ions combine. However, the hydronium ion concentration is low because of the weak nature of the phosphonic acid. Therefore, equilibrium is created by the buffering action of the weak organic acid and ammonium phosphonate salt. The objectives of this study are to:examine the solubility of sand and clay minerals in the three retarded HF systems, and compare these systems with full strength regular mud acid (RMHF).
- Europe > Norway > North Sea > Central North Sea (0.93)
- North America > United States > Texas (0.67)
- Research Report > New Finding (0.54)
- Overview (0.53)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral > Silicate (1.00)
- Europe > Norway > North Sea > Central North Sea > Utsira High > PL 069 > Block 25/11 > Grane Field > Heimdal Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 046 > Block 15/9 > Sleipner Field > Draupne Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 046 > Block 15/8 > Sleipner Field > Draupne Formation (0.99)
- (3 more...)
- Well Completion > Acidizing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Information Technology > Modeling & Simulation (0.46)
- Information Technology > Data Science (0.46)
Abstract Several laboratory CO2-foam experiments were performed in South Cowden Unit cores to select a suitable surfactant for possible CO2-foam application in the South Cowden Unit. Four surfactants Chaser CD-1045, Chaser CD-1050, Foamer NES-25 and Rhodapex CD-128 were evaluated for their foaming ability. Chaser CD-1045 and Rhodapex CD-128 were selected for further testing after an initial screening. These surfactants were tested in co-injection as well as Surfactant Alternating with Gas (SAG) processes at various frontal velocities. The resulting foams exhibited Selective Mobility Reduction (higher resistance factor in higher permeability zones) as well as shear-thinning behavior. While average resistance factor for the foam produced in four sections of a field core was higher for the co-injection of Chaser CD-1045 than Rhodapex CD-128, the later surfactant performed better in the SAG process as well as exhibiting lower adsorption in Baker Dolomite cores. While it is difficult to select Chaser CD-1045 over Rhodapex CD-128 based on laboratory data alone, economics and calculations might select one product over the other. Two adsorption tests performed with Chaser CD-1045 in presence of 250 ppm hydroxy ethyl cellulose as a sacrificial agent did not reduce adsorption of this surfactant. Introduction This study is a small part of a $20 MM project funded by the United States Department of Energy and the Working Interest Owners (WIO) of the South Cowden Unit. In this Class II DOE project horizontal wells have been drilled for CO2 flooding. However, as a contingency to improve sweep efficiency of CO2 in the horizontal injection wells, this study was initiated to screen four surfactants to identify the best candidate for possible CO2-foam application for mobility control in horizontal wells at the South Cowden Unit following CO2 flood. Four surfactants, Chaser CD-1045 and Chaser CD-1050 obtained from Chaser International Rhodapex CD-128 provided by Rhone-Poulenc and Foamer NES-25 obtained from Henkel Corporation, were evaluated. Since this was a comparative study, it would have been necessary to use identical cores to evaluate the foaming ability of the surfactants. However, due to a severe inhomogeneity of the South Cowden Unit cores, identical tests performed in a single field core would have been the next choice. Initial CO2-foam tests performed in a South Cowden Unit core showed that front end of the core would collapse within 2-3 core tests due to dissolution of softer parts of the core. To avoid this problem a short South Cowden Unit core was placed upstream of the test core. This provision extended the life of the test core so that all four surfactants could be tested in the same test core. The goal of these initial studies was to select the best two surfactants for further testing for selection of the best candidate for CO2-foam applications at the South Cowden Unit. The follow-up studies included evaluation of the effect of surfactant concentration, frontal velocity, comparisons of co-injection versus Surfactant Alternating with Gas (SAG) processes, and determination of surfactant adsorption in cores with no oil or cores at residual oil saturation. All surfactant solutions used in these studies were prepared in Synthetic South Cowden Unit Brine. Analysis of this brine is given in Table 1. CO2-Foam Test Setup and Flooding Procedure All CO2-foam flooding experiments were performed at the reservoir temperature of 98 F under 2000 psi of pressure. Figure 1 shows a schematic diagram for the setup used in evaluating the foaming ability of various surfactants Core 12A, a South Cowden Unit core used to rank the four surfactants in their foaming ability, was 1" in diameter and 4.84" in length. P. 81^
- North America > United States > Texas > Ector County (1.00)
- North America > United States > Texas > Crane County (1.00)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.88)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
Abstract The East Vacuum Grayburg San Andres Unit (EVGSAU) recently completed ten years of successful CO2 miscible WAG injection. This paper briefly reviews the original CO2 project design and field performance over the past ten years, and discusses the evolution of a CO2 reservoir management strategy from the original, fixed 2:1 WAG design to the current flexible, performance-driven WAG strategy. Variations in the magnitude and character of CO2 flood response across the Unit due to variability in local reservoir geology presented numerous reservoir management challenges. Problems were encountered in areas such as injection conformance, pattern balancing and sweep efficiency; managing large swings in gas production rates, and changes in injection gas composition and MMP due to construction of an NGL recovery facility. These challenges required a re-evaluation of our understanding of the reservoir and prompted a review of the original project design and operating philosophy by an interdisciplinary study team. Significant elements of this effort included surveillance and data collection on selected infill wells, extensive reservoir characterization work, and use of operations-oriented simulation modeling. This work resulted in the evolution of a more flexible reservoir management strategy for EVGSAU utilizing selective, geologically-targeted infill drilling, well conversions, pattern realignment, and a performance-driven WAG management strategy. Operating changes implemented over the past two years have produced significant improvements in profitability and performance in terms of both increased oil production and reduced gas handling problems and expenses. Introduction The East Vacuum Grayburg San Andres Unit (EVGSAU) is located 15 miles northwest of Hobbs, New Mexico. It is one of several large units within the Vacuum Field area. Initial development of the Vacuum Field began in 1938 and was essentially complete by 1941. Waterflood development in the Vacuum area began in 1958 and gradually spread across the field. EVGSAU was one of the last areas in the Vacuum Field to be unitized (December, 1978). Ref. 1 presents details of the early field development and unitization of EVGSAU for the purpose of infill drilling to 20-acre spacing followed by implementation of full pattern waterflood operations in 1980. The initial waterflood at EVGSAU was developed using 80-acre inverted ninespot patterns. Original CO2 Project Design CO2 injection was initiated at EVGSAU in September, 1985. The CO2 flood used the same 80-acre inverted ninespot pattern configuration established for waterflooding Ref. 1 presents details of the original CO2 project design and facilities, describes the CO2 project implementation, and discusses early field response to CO2 injection. The designated CO2 project area at EVGSAU covers about 5000 acres (about 70% of the total Unit area) and contained an estimated 260 MMSTB OOIP out of the nearly 300 MMSTB OOIP estimated for the total Unit. The initial CO2 project development consisted of forty-five (45), 80-acre WAG injection patterns, divided into three operational WAG areas. These three areas, designated as WAG Area A, B, and C in Fig. 1, were selected to have approximately equal floodable pore volume and injection capacity. The original project design called for injection of a total volume of 230 BCF of CO2 (=30% HCPV) into the project area using a fixed 2:1 time WAG. P. 309
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- North America > United States > Texas > Permian Basin > Central Basin > Word Group > San Andres Formation (0.99)
- North America > United States > New Mexico > Permian Basin > Delaware Basin > Upper Pennsylvanian > Vacuum Field > San Andreas Formation > San Andreas Formation > Upper San Andreas Formation (0.99)
- (7 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Management > Strategic Planning and Management > Project management (1.00)
- Management > Asset and Portfolio Management > Field development optimization and planning (1.00)
Abstract CO2 relative permeability, trapped gas saturation, and hysteresis effects are key parameters in determining injectivity and displacement efficiency in a miscible CO2 WAG injection project. Coreflood experiments were conducted to determine these parameters for samples from two major lithofacies in the South Cowden reservoir interval. This work was co-funded by DOE under the Class II Oil Program. The data provided key input parameters for simulation modeling and evaluation of the DOE sponsored advanced technology field demonstration project at the South Cowden Unit, Ector County, Texas. Measurements of residual oil saturations following miscible CO2 displacement, trapped CO2 saturations, and endpoint relative permeabilities of CO2 and water (both before and after CO2 displacements) are presented for the primary facies. The secondary facies was determined not to be amenable to a WAG injection process. The corefloods were conducted at reservoir conditions (98 F and 1800 psig) using live oil and brine. Magnetic resonance imaging (MRI) was used to screen core plugs for internal, "hidden" heterogeneities prior to flow testing. Trapped gas saturations in the main reservoir facies at South Cowden varied from approximately 20-25 3 % PV. Measured CO2 relative permeabilities were significantly lower than oil relative permeabilities at comparable water saturations. Water relative permeabilities after CO2 displacement were appreciably reduced compared with values observed prior to CO2 injection. The impact of these key parameters on stimulation model predictions of CO2 flood performance is illustrated using a typical pattern simulation model. Experimental procedures and apparatus are presented along with a method for estimating uncertainties in the trapped gas saturation measurements. Introduction Effective management of a reservoir being considered for CO2 miscible WAG injection benefits from extensive evaluation of its projected performance via reservoir simulation. The degree to which a sophisticated reservoir simulator is successful in predicting reservoir performance is directly related to the quality of the input data, which includes geological descriptions along with the reservoir rock and fluids properties. Such input may include water and CO relative permeability data, trapped gas saturation, and relative permeability hysteresis effects. The influences of these parameters in miscible and immiscible WAG processes have been discussed in Refs. 1-8. Observed trends have not always been consistent, even among west Texas reservoirs. As a result, some degree of laboratory work should probably be included in the planning of each miscible or immiscible WAG project. The objectives of this paper are to present the results of South Cowden miscible WAG laboratory experiments and to demonstrate how the generated data impact predictions of reservoir performance via reservoir simulation. Experimental Core Samples. The core plugs used in this experimental work were taken from native state cores which had been drilled with a bland mud of neutral pH. The core plugs were cut and stored in deaerated lease crude. A large number of core plugs were available from which to select the plugs used in the coreflood experiments. The core plugs were divided into two broad geologic lithofacies groups:a burrow-mottled dolopackstone "chaotic" facies and a fusulinid dolowackestone "moldic" facies The burrow-mottled chaotic facies has been characterized as having well connected intergranular and intercrystalline porosity, while the fusulinid moldic facies has been characterized as having poorly interconnected moldic porosity. P. 273
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (28 more...)
Use of Production and Well Test Data with Predictive History Matching to Improve Reservoir Characterization for CO2 Flooding at the South Cowden Unit
Harpole, K.J. (Phillips Petroleum Company) | Gerard, M.G. (Phillips Petroleum Company) | Snow, S.C. (Phillips Petroleum Company) | Caldwell, C.D. (Phillips Petroleum Company)
Abstract The South Cowden Unit was selected for one of three mid-term field demonstration projects being conducted under the DOE Class II Oil Program for shallow-shelf carbonate reservoirs. The South Cowden project is designed to demonstrate the technical and economic viability of using horizontal CO2 injection wells and centralization of surface facilities to optimize CO2 project economics. If successful, this approach will help to improve the economic viability and application of CO2 flooding for many smaller fields which might otherwise soon face abandonment. Successful design and implementation of the project requires a focused, cost-effective reservoir characterization effort to identify those reservoir characteristics and field areas best suited to application of this technology. Integration of production and well test data with geologic reservoir description information was necessary to develop a sufficient understanding of the permeability distribution at South Cowden. A predictive history matching approach was used in modeling historical field performance to further refine the reservoir description. Field History The South Cowden Unit (SCU), located in Ector County, Texas, produced from the Grayburg Formation at an average depth of approximately 4550 feet. A summary of reservoir and fluid characteristics is presented in Table 1. Initial production from the Unit area began in 1948 and a total of approximately 100 wells have been drilled at SCU on 20-acre spacing. The field was unitized for secondary recovery waterflood operations in 1965 with initial water injection going into peripheral wells located around the edge of the producing structure near the oil/water contact. Leaseline cooperative water injection was added in the early 1970's along the northern boundary of the Unit. From the late 1970's through the mid-1980's, several additional water injection wells were added at selected locations in the interior of the Unit, however there was no formal injection pattern at SCU. In spite of the lack of a regular flood pattern, waterflood performance at SCU has been excellent (Fig. 1). The Unit is currently nearing its economic limit for waterflood operations. At the end of 1995 there were 11 active injectors and 39 active producers and Unit production was a little over 400 BOPD at a watercut approaching 95%. Selective infill drilling over the past few years has met with only limited success, leaving tertiary CO2 enhanced oil recovery as the only viable prospect remaining for extending field life and adding significant reserves. Project Overview Two earlier CO2 flood feasibility studies both indicated SCU to be an excellent technical candidate for CO2 flooding, but the project could not meet requisite economic criteria. The capital costs for new injection wells and related facilities to implement a conventional pattern CO2 flood development were too high relative to the recoverable oil volumes at SCU. Most of the current wells are not suited for conversion to CO2 WAG injection service because of mechanical or completion problems. The situation at SCU is one which will confront operators of many smaller fields in the Permian Basin.
- North America > United States > Texas > Ector County (1.00)
- North America > United States > Texas > Crane County (0.82)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.76)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (23 more...)
Abstract The South Cowden (San Andres) Unit is the site selected for one of three mid-term projects to be conducted under the DOE Class II Oil Program for Shallow Shelf Carbonate Reservoirs. The proposed $21 million dollar project is designed to demonstrate the technical and economic viability of an innovative CO2 flood project development approach. The new approach employs cost-effective advanced reservoir characterization technology as an integral part of a focused development plan utilizing horizontal CO2 injection wells and centralization of production/injection facilities to optimize CO2 project economics. If proven successful, this new approach will help improve the economic viability of CO2 flooding for many older, smaller fields which are or soon will be facing abandonment. Introduction CO2 miscible flooding has been demonstrated to be a technically viable tertiary enhanced oil recovery process which can extend the producing life and add significantly to the ultimate recovery of the remaining oil resource in Shallow Shelf Carbonate reservoirs in the Permian Basin. Most of the incremental tertiary oil production from CO2 projects implemented to date has come from a few, large scale projects where the sizable economies of scale inherent in this type of development improve project economics. In 1992, Moritis reported that the five largest CO2 projects accounted for over one-half of the total incremental oil production attributable to CO2 miscible flooding in the United States. Lang, et. al. estimate that between 250 and 575 million barrels of incremental oil could be produced from new CO2 miscible flood projects in the Permian Basin over the next 25 years if oil prices stabilize in the $16 to $20 per barrel range. P. 409^
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (30 more...)
Abstract This paper summarizes the comprehensive reservoir characterization effort for the foam pilot area and discusses the response to foam injection in the CO2 Foam Field Verification Pilot Test conducted in the East Vacuum Grayburg San Andre S Unit (EVGSAU) in New Mexico. A detailed study of the pilot pattern geology provided an understanding of the major controls on fluid flow in the foam pattern. Pattern performance data, falloff testing, profile surveys, and interwell tracer results were integrated into the geologic model to guide project design work and provide a framework for interpretation of foam performance. Localized regions of high permeability resulting from solution enhancement of the matrix pore system appear to be the primary cause of the early CO2 breakthrough and channeling of injected CO2 toward the problem production well in the foam pattern. Positive response to foam injection is indicated by reduced injectivity and injection profile data in the foam injection well; by results from time sequence monitor logging in the observation well; and by changes in production performance in the high GOR, "offending" production well in the foam pattern. Hall plots and pressure falloff testing were used to measure in situ changes in fluid mobility near the foam injection well. Time sequence logging responses at an observation well located 150 feet from the foam injector provided evidence of changes in fluid flow patterns in response to foam injection. Positive response to foam injection is further evidenced by changes in the CO2 production and oil rate performance at the "offending" production well in the foam pilot pattern. EVGSAU GEOLOGIC SETTING The Vacuum Field, located about 15 miles northwest of Hobbs in Lea County, New Mexico, is comprised of several large Units and leases. The East Vacuum Grayburg-San Andres Unit (EVGSAU) covers more than 7000 acres on the eastern side of the Vacuum Field. The primary productive interval at EVGSAU is comprised of the dolomitized carbonate sequences in the upper few hundred feet of the San Andres Formation, at a depth of approximately 4500 feet. The San Andres structure is an east-west trending anticline with more than 400 feet of closure above the original oil/water contact. The reservoir section is informally subdivided into a "lower" San Andres section and an "upper" San Andres section, separated by the more siliciclastic Lovington Sandstone Member. Stratigraphy and Lithofacics The San Andres reservoir section is comprised of a series of repeated, anhydritic, dolomitized, fining-upward, carbonate sequences composed of grain-rich dolostones which grade upward into dolomudstones. The subtidal, grain-rich carbonate facies form the primary reservoir units; the dolomudstones contain little effective porosity. Repetition of these depositional packages upwards through the formation results in a San Andres section composed of cyclical, shallowing/shoaling upward parasequences. Commonly occurring reservoir pore types include primary intergranular porosity, intercrystalline porosity (related to dolomitization), grain-moldic porosity, and vugular porosity. All of these pore types show varying degrees of solution enhancement. P. 163^
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (0.69)
- North America > United States > Texas > Permian Basin > Central Basin > Word Group > San Andres Formation (0.99)
- North America > United States > New Mexico > Permian Basin > Delaware Basin > Upper Pennsylvanian > Vacuum Field > San Andreas Formation > San Andreas Formation > Upper San Andreas Formation (0.99)
- North America > United States > New Mexico > Permian Basin > Delaware Basin > Upper Pennsylvanian > Vacuum Field > San Andreas Formation > Lower San Andreas Formation > Upper San Andreas Formation (0.99)
- (13 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- (3 more...)
SPE Members Abstract The East Vacuum Grayburg San Andres Unit (EVGSAU) operated by Phillips Petroleum, is the site selected for a comprehensive evaluation of the use of foam for improving the sweep efficiency of a CO2 flood. The four-year project is jointly funded by the EVGSAU Working Interest Owners (WIO), the U.S. Department of Energy (DOE), and the State of New Mexico. The Petroleum Recovery Research Center (PRRC), a division of the New Mexico Institute of Mining and Technology (NMIMT), is providing laboratory and research support for the project. A Joint Project Advisory Team (JPAT) composed of technical representatives from numerous major oil companies, PRRC, and DOE provides input, review and guidance for the project. This paper is the second in a series of papers detailing various aspects of the CO2 Foam Field Verification Pilot test at EVGSAU. An earlier paper summarized the project plans and detailed the laboratory work leading to the selection of a surfactant for the field trial. This paper presents:an overview of the operating plan for the project, details of the foam injection schedule and design criteria, and a discussion of the data collection program and performance criteria to be used in evaluating successful application of foam for mobility control in the EVGSAU CO2 project. Specific items discussed in the foam injection design include the determination of surfactant volume and concentration, selection of the surfactant-alternating-gas (SAG) injection sequence for foam generation, field facilities, operations during foam injection, and contingency plans. An extensive data collection program for the project is discussed including production testing, injection well pressure and rate monitoring, injection profiles, production well logging, observation well logging program, and both gas and water phase tracer programs. Introduction The EVGSAU, located about 15 miles northwest of Hobbs in Lea County is the site of the first full-scale miscible carbon dioxide injection project in the state of New Mexico. CO2 injection at EVGSAU began in September, 1985. The CO2 project area covers 5000 acres developed using an 80-acre inverted nine-spot flood pattern. The total CO2 injection rate is about 30 MMcf/D. A water-alternating-gas (WAG) ratio of 2:1 (time basis) is used in the project, resulting in about one-third of the project area being on CO2 injection at any one time. In any given area, a WAG cycle consists of about four months of CO2 injection followed by eight months of water injection. This results in approximately 1.5 to 2% hydrocarbon pore volume (HCPV) CO2 injection and 3 to 4% HCPV brine injection per WAG cycle. The project is currently in the seventh WAG cycle. The tertiary oil response at EVGSAU to date has been very favorable. As shown in Figure 1, the waterflood decline established prior to CO2 injection has been arrested, and oil production has held approximately constant near the current 9000 BOPD Unit total for the past six years. P. 115^
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (28 more...)
Summary An engineering/geological study of the Top Red Conglomerate (TRC) section of the Barrancas formation, Mendoza area, Argentina, was conducted (1) to evaluate historical waterflood performance and recovery efficiency and (2) to develop a reservoir description and predictive model for later use in evaluation of reservoir response to EOR process applications. Original oil in place (OOIP) in the TRC reservoir was about 400 million STB [616 ⨯ 10–6 stock-tank m3]. The field had produced about 154 million STB [24.5 ⨯ 10–6 stock-tank m3] or 38.5% OOIP through 1980 and is under consideration for application of a caustic flooding EOR process. The TRC shows extremely large variations in permeability, both areally and vertically, owing to its origin as the uppermost part of a thick, alluvial fan, braided channel sequence of sediments. Porosity and permeability development in these rocks is governed primarily by the abundance of detrital clays. Reservoir quality also is reduced somewhat in localized areas by the presence of calcite and zeolite cements and by authigenic clays. An abundance of chemically reactive minerals in the formation poses a significant potential for formation damage and/or adverse reactions with injected EOR chemicals. A geological description of layering and areal variability in the reservoir was developed and used to guide the application of a black oil simulator to two cross-sectional models. Simulation of waterflood performance indicated good vertical sweep efficiency near injection wells, with less efficient sweep farther away owing to gravity segregation and an adverse mobility ratio. A preliminary screening and feasibility study evaluated several EOR processes for recovering the oil left after waterflooding. Caustic flooding appeared to be the most feasible EOR process for application in this reservoir. The mineralogy, chemical reactivity, and cation exchange capacity (CEC) of representative core samples were examined as a part of the EOR feasibility screening. The understanding of reservoir performance, distribution of remaining oil in place, reservoir heterogeneity, and chemical reactivity of the formation obtained during this study provided the basis for a reservoir model to be used in subsequent predictions of performance under EOR operations. Introduction The Mendoza contract area operated by Argentina-Cities Service Development Co. is about 50 miles [80 km] southeast of the city of Mendoza in the Cuyo basin of western Argentina (Fig. 1). The major producing formation in this study is the TRC interval of the Juro-Cretaceous Barrancas formation. The Punta de las Bardas (PB), Vacas Muertas (VM), and Gran Bajada Blanca (GBB) fields are contiguous and form a single, common reservoir in the TRC. Fig. 2 gives the stratigraphic nomenclature in the area. Development of the TRC reservoir began in 1959. The field produced under primary depletion, assisted by a natural water drive, until 1967, when it was recognized that the natural water drive was not strong enough to sustain continued fluid withdrawal from the reservoir. At this point, a pressure-maintenance program was implemented by injecting water into most of the wells located near the original water/oil contact. Individual well production performance has been controlled primarily by sand quality, structural location, completion intervals, and proximity to local permeability barriers in the reservoir. Material balance calculations indicate that the aquifer is of only limited influence in reservoir pressure maintenance. The initial pressure in the TRC reservoir was about 2,600 psi [17.93 MPa]. The pressure declined to a minimum of about 850 psi [5.86 MPa] by 1967–68, and then increased as a result of water injection pressure maintenance. The current reservoir pressure is about 1,500 psi [10.34 MPa]. Fig. 3 shows a waterfront advance map superimposed on a structure contour map of the TRC reservoir. The waterfronts shown represent advancement of a 40% water-cut front through time. The map shows that water advancement has been controlled by the structural configuration of the reservoir and by the presence of permeability barriers, particularly the large area near the center of the reservoir where the TRC interval is missing. It is unclear whether this area resulted from erosion of the TRC or from nondeposition; however, it does form an effective local barrier to water influx. JPT P. 295^
- Geology > Geological Subdiscipline (1.00)
- Geology > Mineral > Silicate > Phyllosilicate (0.91)
- Geology > Sedimentary Geology > Depositional Environment > Continental Environment > Fluvial Environment > Alluvial Fan Environment (0.35)
Abstract At this point in time the oil industry is under considerable pressure to maximize recoveries from existing reservoirs. In order to obtain this goal it is necessary that a reservoir be accurately described as to its internal structure and producing mechanisms. Improper definition of a reservoir producing mechanisms. Improper definition of a reservoir can result in a very inefficient operation and thus a lower recoverable reserve value. This paper is being presented as an example of how the interpretation of internal structure and producing characteristics of a particular reservoir has changed as a result of an extensive reservoir data gathering program. The new information has drastically program. The new information has drastically changed the concept as to how this reservoir should be managed. Introduction The West Seminole Field is located in west central Gaines County, Texas (Figure 1). The field has a productive area which covers 2782 surface acres, and consists of a large main dome with smaller domes to the southeast and northwest. A structure contour map and 3-D perspective view of the reservoir are shown in Figure 2. The West Seminole reservoir is a San Andres Dolomite producing from an average depth of 5,112 feet. A primary gas cap overlies the oil zone over the major portion of the field. The large dome and the adjoining dome to the southeast are connected through the oil zone and share a common gas-oil contact. The gas-oil and water-oil contacts are essentially flat lying, with the water-oil contact rising somewhat near the productive limits of the field. A schematic cross section through the reservoir is shown in Figure 3a. The average oil zone thickness in the main structure is 140 feet and the average gas cap thickness is 111 feet. The original volume of oil-in-place is estimated to be 172 MMSTB and the original volume of gas cap gas-in-place is estimated to be 137 BCF. Throughout the history of the field, the approach to operations and reservoir management at West Seminole has been guided by an underlying conception of reservoir structure. Major operational decisions have been delayed because of disagreement as to the correct reservoir description. The approach to operations and reservoir management has changed as the concept of reservoir structure has evolved. The development of current reservoir description is the result of an extensive combined geological and engineering effort. EARLY FIELD HISTORY The field was discovered in June, 1948. The initial field development consisted of 54 wells developed on approximately 40-acre spacing (Figure 4). Most of the wells were completed as open holes with casing set to just below the gas-oil contact. The early approach to reservoir operations was based on the concept of the reservoir as a relatively homogeneous dolomitic limestone. This reservoir description was based on the observation that relatively flat, horizontal gas-oil water-oil contacts exist across the field in spite of the large structural relief in the reservoir. Vertical continuity was supported When a number of wells began producing large volumes of gas; this was interpreted as gas coning and/or downward movement of the gas-oil contact. Production from the reservoir was thought to be primarily by solution gas drive assisted by an expanding gas cap, along with some limited water influx. The field was unitized in December, 1962. By this time reservoir pressure had declined from the initial discovery pressure of 2020 psi to about 1600 psi after having produced only about 6% of the original oil-in-place. It was decided that some action must be taken to reduce the rate of decline in reservoir pressure and to allow producing rates to rise to meet increased allowables. A program to inject produced gas back into the gas cap was initiated in 1963–64.
- Geology > Sedimentary Geology (0.95)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (0.34)
- North America > United States > Texas > Permian Basin > Central Basin > West Seminole Field (0.99)
- North America > United States > Texas > Permian Basin > Central Basin > Seminole Field > Word Group > San Andres Formation (0.99)
- North America > United States > Texas > Permian Basin > Central Basin > Seminole Field > Wolfcamp Reef Formation > San Andres Formation (0.99)
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