Summary A full-scale CO2 miscible tertiary project in the Means San Andres Unit, Andrews County, TX, is expected to result in the additional recovery of morethan 38 million STB [6.0 × 10(6) stock-tank m3]. Design, implementation, surveillance, and early performance of the CO2 project are discussed. Introduction The tertiary flood implemented in the Means San Andres Unit was part of anintegrated reservoir development plan that included apattern-modification/infill-drilling program and construction of newfacilities. The 10-acre [4-ha] infill program consisted of drilling 205producers and 158 injectors in the project area. Facility construction includedCO2 injection and production facilities and a gas compression and treatingfacility to recycle the produced CO2/gas stream. CO2 injection began in Nov.1983. Unique aspects providing engineering and operational challenges in thisproject include a more viscous crude than is found in most west Texas CO2projects, a relatively high miscibility pressure. and a narrow window betweenoperating pressure and the bottomhole formation parting pressure. Field Discovery and Development The Means (San Andres) field is about 50 miles [80 km] northwest of Midlandin Andrews County, TX. Geologically, the field lies along the eastern edge ofthe central basin platform and in a northwest/southeast trend of Permian SanAndres fields. Production is from the Grayburg and San Andres formations atdepths ranging from about 4,200 to 4,800 ft [1280 to 1460 m]. The Meanstertiary target is the San Andres. which consists of dolomite with minoramounts of shale and anhydrite. The field is a north/south-trending anticlineseparated into north and south domes by a dense structural saddle near thecenter of the field (Fig. 1). Table 1 gives reservoir and fluid properties forthe San Andres. Most significant is the oil viscosity of 6 cp [6 mPas], compared with 1 to 2 cp [1 to 2 mPas] for most San Andres reservoirs in westTexas. The primary producing mechanism was a combination of fluid expansion anda weak waterdrive. In 1963, the field was unitized and water injection beganinto a peripheral waterflood pattern. CO2 Project Planning/Design A review of other proposed CO2 projects indicated that, although Means wassimilar to other large San Andres fields in the area, some reservoir and fluidproperties appeared unique or at least substantially different. Programs weredesigned to evaluate the impact of high oil viscosity, relatively highmiscibility pressure, and low formation parting pressure. The initial screeningstudies indicated that the miscible CO2 process would work despite potentialproblems associated with these reservoir properties. Fieldwide implementationplans proceeded simultaneously with these investigations. Process Characterization. Investigations characterizing the CO2 floodprocess for Means were important in identifying the tertiary oil target, conducting miscible simulation studies, and designing the CO2 flood. Laboratorytest results, combined with actual field data, were used to determine minimummiscibility pressure (MMP), residual oil saturation (ROS) to waterflood, andthe ability of CO2 to mobilize the waterflood residual oil. Operating pressureis more important at Means than in many Permian Basin CO2 projects because ofthe small window between MMP and formation parting pressure. Slim-tubeexperiments indicated that the MMP was between 1,850 and 2,300 psi [12.8 and15.9 MPa], Because of the slim-tube data and the bottomhole injection pressurelimitation of 2,700 to 2,800 psi [18.6 to 19.3 MPa] caused by a low formationparting pressure, a 2,000-psi [13.79-MPa] operating pressure was selected. Anestimate of waterflood ROS was needed to determine the magnitude of thetertiary target. Relative permeability data, remobilization tests, and pressurecore results indicated that the 34% ROS determined from the pressure cores wasthe most representative. Remobilization tests to determine the ability of CO2to mobilize waterflood residual oil were run with Means crude and native-statecomposite cores. Many authors have reported observance of water blocking in thelaboratory. After the core was water-flooded, CO2 and water were injected at2,300 psi [15.9 MPa] at a water-alternating-gas (WAG) ratio of 1:1 until themiscible residual saturation of 9.1 % was reached. JPT P. 638⁁
Detailed studies of three waterfloods in Permian carbonate reservoirs of west Texas resulted in new depletion plans with major operating changes, including infill drilling and pattern modifications. Close coordination of geologic and engineering work produced a consistent approach to the relationship between reservoir description and operations when calculating ultimate recovery. Introduction Detailed studies of three waterfloods in Permian carbonate reservoirs of west Texas resulted in new depletion plans with major operating changes, including infill drilling and pattern modifications. An important aspect of these studies was the close coordination of geologic and engineering work that produced a consistent approach to the relationship between reservoir description and field procedures used to improve ultimate recovery. The Fullerton, Means, and Robertson fields are located in west Texas about 50 to 75 miles northwest of Midland (Fig. 1). These reservoirs have been producing oil since the mid-1930's and later were unitized with Exxon Co., U.S.A., as operator. These three units are typical of many west Texas carbonate waterfloods in which waterflooding began in the early 1960's and progressed through several expansion phases. Although economically successful, results were often less than predicted. As problems with early waterfloods began to develop, old concepts changed and led to more detailed studies. Ghauri et al. reported several of these changing concepts in 1974. The same year, Driscoll summarized some approaches that had been used to improve waterflood recovery. To better relate reservoir description to past performance and future operations, a special study group composed of an engineer-geologist team was formed to conduct in-depth studies of these three reservoirs. Techniques used in these studies were largely refinements of those used previously in the Permian Basin area; however, some new concepts and approaches were developed. A practical requirement was having to use available data that, in some cases, were almost 40 years old and often of poor quality. Reservoir Description Geology The fields studied are located geologically in the north-eastern part of the Central Basin Platform, a shallow shelf area separating the Delaware and Midland basins during Permian time. Fig. 1 is a geological province map showing various basin and platform areas during Permian time. The Robertson and Fullerton fields produce mainly from the Clearfork formation of Permian Leonard age, while Means Field produces primarily from the San Andres formation of Permian Guadalupian age. These fields, even though varying slightly in age, geographical location, and producing depth, exhibit similar depositional and lithologic characteristics that affect waterflood performance. These reservoirs are characterized by numerous porosity stringers within a gross, vertical, carbonate section that may be several hundred feet thick. These carbonates were deposited as limestone in a shallow shelf environment and most of the limestone later became dolomitized. JPT P. 1547^
Summary Evaluation of reservoir discontinuity has been used by industry to estimate potential oil recovery to be realized from infill drilling. That this method may underestimate the additional recovery potential is shown by continuity evaluation in a west Texas carbonate reservoir, as infill drilling progressed from 40-acre (162×103-m2) wells to 20-acre (81×103-m2) wells and eventually to 10-acre (40.5×103-m2) wells. Actual production history from infill drilling in nine fields, including carbonate and sandstone reservoirs, shows that additional oil recovery was realized by improving reservoir continuity with increased well density. Introduction One objective of an orderly field-development program is to determine the maximum well spacing that will effectively drain oil and gas reserves. While wide spacing has proved effective in many oilfield applications, there are a growing number of examples where infill drilling, combined with water-injection pattern modifications, has provided substantial additional oil reserves. This paper deals with such fields: Means, Fullerton, Robertson, IAB (Menielle Penn), Howard Glass cock, Dorward, and Sand Hills fields in west Texas, Hewitt field in southern Oklahoma, and Loudon field in Illinois. The paper will quantify the contribution to current production and the additional reserves attributable to this action, using data available through Oct. 1981. Infill drilling has continued in most of these fields. Also revealed by infill drilling is the fact that the west Texas carbonate reservoirs are more stratified, and porous stringers are more discontinuous than revealed by initial studies. Background The theoretical concepts indicating that infill drilling will increase reservoir continuity and improve water flood pattern conformance in heterogeneous west Texas carbonate reservoirs were researched and published in the early 1970's by Ghauri,1 Ghauri et al.,2 Stiles,3 George,4 and Driscoll.5 Detailed field studies recommending infill-drilling and water flood-pattern modifications were made for the Means, Fullerton, and Robertson fields by Stiles and George.3,4 Unpublished studies were made for the other reservoirs prior to infill drilling. Borrowed from a previous work by George and Stiles,4 Fig. 1 is a type cross section in the Fullerton Clear fork reservoir that illustrates the concept of "continuity," the percentage of pay in a well that is continuous to another well. The two original Wells A and B are 40-acre (162×103-m2) locations, and the center well is an infill location 660 ft (201.2 m) from either original well. Note the discontinuous nature of the porosity stringers and that correlation before the infill well was drilled would have been considerably different than it is after the infill well was drilled. The increase in net pay in the infill well, especially in the upper pan of the Clear fork formation, illustrates the fact that the more wells that are drilled, the more highly stratified, discontinuous, and complex a given west Texas carbonate reservoir is found to be. This fact leads to a conservative evaluation of the potential increased recovery from an infill well.
American Institute of Mining, Metallurgical, and Petroleum Engineers Inc. Abstract After a detailed study of 12 years' performance of the Fullerton Clearfork performance of the Fullerton Clearfork Unit, a special study group recommended major operating changes which will increase ultimate oil recovery 22 million barrels. New techniques included a simplified waterflood model and a statistical approach to measure reservoir continuity. Evaluation of alternate plans with these tools indicated the plans with these tools indicated the need for infill drilling and a closer spaced pattern. Introduction Location and Geology The Fullerton Field is located in west Texas in Andrews County, 50 miles north-west of Midland as shown on Figure 1. Geologically, the field is located in the northeastern part of the Central Basin Platform Area, and lies in a north-west-southeast trend of Permian carbonate production stretching for more than 100 miles. Figure 2 is a structure map which shows the northwest-southeast trending, anticline with approximately 400 feet of relief on top of the Clearfork formation. There are two prominent structural domes on this feature with the North Dome being much the larger of the two. The Fullerton structure continues northward from the Unit boundary and is productive in the adjacent, but separately prorated Union Field. Discovery was in 1942 and was followed by rapid development during the next five years with 565 wells completed by 1947. Development continued throughout the 1950's and 1960's with sporadic development up to the present time.
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