Dual-lateral horizontal wells successfully target bypassed pay in the San Andres Formation, Vacuum field, New Mexico

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1 Dual-lateral horizontal wells successfully target bypassed pay in the San Andres Formation, Vacuum field, New Mexico Matthew J. Pranter, Neil F. Hurley, Thomas L. Davis, Michael A. Raines, and Scott C. Wehner ABSTRACT This case study of the San Andres Formation in the mature Vacuum field, New Mexico, shows how seismic data can be used to target bypassed pay with horizontal wells. These dual-lateral wells were the first attempt at horizontal development in the Vacuum San Andres field and in the San Andres Formation in New Mexico. The primary reservoir facies consist of ramp crest and outer ramp dolomitized peloidal packstones, skeletal and ooid grainstones, and fusulinid packstones. Vertical facies successions form numerous highfrequency carbonate depositional cycles and cycle sets that create distinct reservoir zones. Structural blocks created by small-scale faults (25 ft [8 m] vertical displacement) and bypassed pay located in thin depositional cycles were identified with three-dimensional compressional-wave seismic amplitude and coherency volumes and well data and targeted using medium-radius horizontal wells. Horizontal wells penetrated fault blocks and depositional cycles that were not adequately drained by existing vertical wells. Production curves show a significant increase in production from the horizontal wells and no interference with production from offset vertical wells. This suggests that the faults are partially sealing. INTRODUCTION Vacuum field is located in southeast New Mexico on the northwest shelf of the Permian basin (Figure 1). Stratigraphic, structural, and diagenetic variability in the shelf-margin carbonates of the Permian San Andres Formation (Guadalupian) forms a heterogeneous and compartmentalized reservoir. Detailed characterization and Copyright #2004. The American Association of Petroleum Geologists. All rights reserved. Manuscript received September 4, 2002; provisional acceptance December 5, 2002; revised manuscript received July 28, 2003; final acceptance September 5, AUTHORS Matthew J. Pranter Department of Geological Sciences, University of Colorado at Boulder, Boulder, Colorado 80309; matthew.pranter@colorado.edu Matt Pranter is an assistant professor of geological sciences at the University of Colorado at Boulder. He received a B.S. degree in geology from Oklahoma State University (1987), an M.S. degree in geology from Baylor University (1989), a B.S. degree in geological engineering from the Colorado School of Mines (1996), and a Ph.D. in geology from the Colorado School of Mines (1999). He currently serves as an AAPG associate editor, is a member of the AAPG Distinguished Lecture Committee and is a past member of the AAPG Foundation Grants-in-Aid Committee. He was previously a senior research geologist with ExxonMobil Upstream Research Company and a geologist with Conoco Inc. His research interests are in reservoir geology and geophysics, sedimentary geology, and reservoir modeling. He is a member of AAPG, SEPM, Society of Exploration Geophysicists, Society of Petroleum Engineers, Geological Society of America, European Association of Geoscientists and Engineers, and Society of Petrophysicists and Well Log Analysts. Neil F. Hurley Department of Geology and Geological Engineering, Colorado School of Mines, Golden, Colorado 80401; nfhurley@mines.edu Neil Hurley is a professor of geology at the Colorado School of Mines. He received B.S. degrees in geology and petroleum engineering from the University of Southern California (1976), an M.S. degree in geology from the University of Wisconsin, Madison (1978), and a Ph.D. in geology from the University of Michigan (1986). He is a past editor of AAPG and has been an AAPG distinguished lecturer. Specialties include carbonate geology and reservoir characterization. He is a member of AAPG, Society of Petroleum Engineers, Society of Exploration Geophysicists, SEPM, European Association of Geoscientists and Engineers, and Society of Petrophysicists and Well Log Analysts. Thomas L. Davis Department of Geophysics, Colorado School of Mines, Golden, Colorado 80401; tdavis@mines.edu Tom Davis is currently a professor of geophysics at the Colorado School of Mines and has 29 years of teaching and research experience. He is the founder and codirector of the Reservoir Characterization Project, an industry-funded consortium in its 18th year of applying multicomponent seismic data to improve hydrocarbon recovery. He holds a Ph.D. in geophysical engineering from the Colorado School of Mines, an M.Sc. degree in geophysics from the University of Calgary, and a B.E. degree in geological engineering (geophysics option) from the University of Saskatchewan. Memberships include AAPG, Canadian Society of Exploration Geophysicists, Denver Geophysical Society, European Association of Geoscientists and Engineers, Rocky Mountain Association of Geologists, and Society of Exploration Geophysicists. AAPG Bulletin, v. 88, no. 1 (January 2004), pp

2 Michael A. Raines Kinder Morgan CO 2 Company, L.P., Midland, Texas 79701; michael_raines@kindermorgan.com Michael Raines is a geologist with Kinder Morgan CO 2 Company, L.P. He has a B.S. degree in geology from West Texas State University and an M.S. degree in geology from the University of Oklahoma. His professional interests include reservoir characterization, tertiary recovery, horizontal drilling, earth science education, multicomponent seismic, time-lapse seismic monitoring, and carbonate systems. He is involved with AAPG, West Texas Geological Society, and Permian Basin Section-SEPM. Scott C. Wehner Kinder Morgan CO 2 Company, L.P., Midland, Texas 79701; scott_wehner@kindermorgan.com Scott Wehner is a senior engineer with Kinder Morgan CO 2 Company, L.P. located in Midland, Texas. He was previously with Texaco. His 22-year career has been in the Permian basin of west Texas and southeast New Mexico. His past 18 years have been devoted to the design, implementation, and/or management of CO 2 projects. He has published various CO 2 -related papers and has one CO 2 process patent. He is a past director of the Society of Petroleum Engineers and is a past Department of Energy Program Manager. He graduated from the University of Missouri, Rolla in 1980 with a B.Sc. degree in geological engineering. ACKNOWLEDGEMENTS We thank the industry sponsors of the Colorado School of Mines Reservoir Characterization Project for funding and input to this study. The consortium members include AGIP, Amoco Production Company (now BP), Anadarko Petroleum Corporation, ARCO (now BP), Chevron Petroleum Technology Company (now ChevronTexaco), China National Petroleum Corporation, Compagnie Generale de Geophysique, Conoco Inc. (now Conoco- Phillips), Dawson Geophysical Company, Exxon Production Research Company (now ExxonMobil Upstream Research Company), Gas Research Institute (now Gas Technology Institute), GeoQuest/Schlumberger/Geco, Golden Geophysical/Fairfield Industries, Grant Geophysical, Inc., Input/Output, Inc., INTEVEP, S.A., Japan National Oil Corporation, Landmark Graphics Corporation, Marathon Oil Company, Maxus Energy Corporation, Nambe Geophysical, Inc., Occidental Oil and Gas Corporation, Oyo Geospace Corporation, PanCanadian Petroleum Limited (now EnCana), Phillips Petroleum Company (now ConocoPhillips), Paradigm Geophysical (formerly Cogni- Seis), Shell E&P Technology Company, Discovery Bay Company (now Rock Solid Images), Silicon Graphics Corporation, Solid State Geophysical, Texaco Group, Inc. (now ChevronTexaco), Union Pacific Resources Company (now Anadarko Petroleum Corporation), UNOCAL/Sprint Energy, Western Geophysical, and Veritas DGC, Inc. The study was also supported through research grants and funding from AAPG, Geological Society of America, Society of Professional Well Log Analysts (now Society of Petrophysicists and Well Log Analysts), and the Department of Geology and Geological Engineering at the Colorado School of Mines. modeling of reservoir heterogeneity are used to identify areas with bypassed pay potential. Supplemental recovery techniques, including horizontal wells, could access the bypassed pay. The study area (Figure 2) includes a portion of the Central Vacuum Unit. This area is under waterflood operations and was converted to a partial-field CO 2 flood and monitored to evaluate the effect of CO 2 injection on reservoir performance and recovery. Vacuum field, one of the larger oil fields in the Permian basin, produces oil and gas from several formations, including the San Andres Formation. The field is part of a major productive trend along the northwest shelf. Vacuum field was discovered in 1929 by the Vacuum-Socony Company, predecessor of Magnolia Petroleum and Mobil Oil (now ExxonMobil). By 1941, 327 wells were completed with 40-ac (0.16-km 2 ) spacing (Purves, 1990; Wehner and Prieditis, 1996). In the Central Vacuum Unit, scattered development drilling associated with primary recovery operations continued until a water-injection program began in 1978 when Texaco (now ChevronTexaco) became the unit operator. At that time, infill wells were drilled on 20-ac (0.08-km 2 ) spacing, and in the mid-1990s, more wells were added in the heart of the field, resulting in 10-ac (0.04-km 2 ) spacing. In 1995, a pilot CO 2 -injection program with one well, Central Vacuum Unit 97 (Figure 3), was initiated in the area. The pilot was a CO 2 injection, soak, and production process (Benson and Davis, 2000). The Central Vacuum Unit CO 2 project was expanded successfully through the late 1990s, until the gas-handling facilities were fully used. The project continues to be expanded in the targeted acreage to maintain the full efficiency of the surface facilities. The unit was brought up to a peak of and is maintained at approximately 7300 BOPD. Time-lapse, multicomponent (four-dimensional, nine-component) seismic data were acquired during the CO 2 pilot program to determine the use of these data for reservoir characterization and to detect and monitor changes in rock and fluid properties associated with the CO 2 pilot (Roche et al., 2001). In addition, a larger P-wave three-dimensional (3-D) seismic survey was acquired in The CO 2 flood was expanded in April 1998 to six injectors (Figure 3). With the expansion, additional time-lapse, multicomponent seismic data were acquired in 1997 and 1998, before and after CO 2 injection. The time-lapse, multicomponent seismic data were used to characterize static reservoir properties such as lithology, porosity, and fracture-related permeability (Pranter, 1999) and to monitor changes in fluid saturation (Benson and Davis, 2000). Other data include conventional logs from 120 wells, one borehole image log in well WS-2-26 (Figure 3), and log data from the medium-radius, dual-lateral horizontal well, Central Vacuum Unit 110 (CVU-110). Six cores are available, and neural-network estimated permeability curves were provided by the unit operator for most of the wells in the study area. Injection and production data, primarily consisting of monthly cumulative volumes of fluids injected or produced, were also provided by the unit operator. In 100 Dual-Lateral Horizontal Wells Target Bypassed Pay in the San Andres Formation

3 Figure 1. Location map of Vacuum field on the northwest shelf of the Permian basin. Modified from Hills (1984). addition, several wells have single or multiple production and injection profiles. These profiles show which intervals in a well are producing or taking injected fluid. GEOLOGIC SETTING Vacuum field is associated with an anticline that developed through a combination of sediment drape, differential compaction, and faulting (Purves, 1990). Shelfmargin depositional relief (Figure 3) and faults bound the reservoir on the south. The structural features, combined with the high-frequency cycles that are characteristic of the San Andres Formation, create a stratigraphic and structural trap for hydrocarbons at Vacuum field. Evaporites, supratidal carbonates, and low-permeability siltstones provide updip and top seals for the reservoir. In the Vacuum field, the San Andres Formation consists of approximately 1500 ft (457 m) of dolomites interbedded with a few thin dolomitic siltstones (Figure 4). The average depth to the top of the San Andres Formation is approximately 4400 ft (1341 m). The upper ft ( m) of the San Andres Formation is the main hydrocarbon-bearing interval (Stoudt and Raines, 2000). The typical rock and fluid properties of the San Andres Formation are shown in Table 1. Table 1. Typical Rock and Fluid Properties of the San Andres Formation Gross pay maximum of 500 ft (150 m) Net-to-gross ratio average of 40% Porosity 0 24%, average of 11.6% Permeability md, average of 22.3 md Initial reservoir pressure 1628 psia ( Pa) at 4500 ft (1372 m) Producing interval ft ( m) Reservoir temperature 105jF (40.6jC) Stock tank oil gravity 38j API Bubble-point pressure 764 psia ( Pa) Initial solution 400 SCF/STB (differential data) gas-oil ratio Reservoir oil viscosity 0.96 cp at the bubblepoint pressure Reservoir drive mechanism water and solution-gas drive in the southern and southeastern parts of the field; solution-gas drive in the northern part of the field Pranter et al. 101

4 Figure 2. Base map of the western part of the Vacuum field and the location of the Central Vacuum Unit. Detailed map of area in circle is shown in Figure 3. The reservoir interval consists of four highfrequency sequences (Figure 5). These four sequences include the upper two high-frequency sequences of the lower San Andres Formation and the upper two high-frequency sequences of the upper San Andres Formation. High-frequency sequences are bounded locally by unconformities and consist of retrogradational, aggradational, and progradational sets of high-frequency cycles (Mitchum and Van Wagoner, 1991; Kerans and Tinker, 1997; Tinker, 1998, Kerans and Kempter, 2002). Individual high-frequency cycles in the San Andres Formation (Figure 5) consist of vertical lithofacies successions that commonly include bryozoan/ sponge/pelmatozoan wackestones and boundstones, fusulinid and peloidal wackestones and packstones, skeletal, ooid, and peloidal packstones and grainstones, and tidal-flat caps with abundant fenestrae (Pranter, 1999; Stoudt and Raines, 2001). The San Andres Formation in this area represents an overall shallowing-upward interval composed of numerous high-frequency depositional cycles that subdivide the reservoir into alternating zones of high and low reservoir quality. Depositional cycles range in thickness from several feet to more than 10 ft (3 m). The primary reservoir rocks consist of dolomitized peloidal packstones, skeletal and ooid grainstones, and fusulinid packstones (Adams, 1997; Scuta, 1997; Pranter, 1999, Stoudt and Raines, 2001). Porosity of these lithofacies ranges from 5 to 20%, and permeability ranges from 5 to 100 md. These rocks alternate with dolomite cycles of lower reservoir quality that exhibit variable degrees of anhydrite cementation. The Lovington siltstone stratigraphically separates the upper and lower San Andres Formation in the northwest part of the study area and is characterized by very low matrix permeability. The Lovington siltstone represents eolian silts and sands that were deposited on the platform or that infiltrated shallow karst features in the tidal-flat capped lower San Andres interval. The high gamma-ray response in the sandstones, however, is enhanced by high uranium 102 Dual-Lateral Horizontal Wells Target Bypassed Pay in the San Andres Formation

5 Figure 3. Top of San Andres Formation structure contour map. Contour interval is 20 ft (6.1 m). The San Andres shelf margin is clearly depicted by the closely spaced contours in the southern part of the map. For location, see Figure 2. content in tidal-flat cycles at the top of the lower San Andres interval (Stoudt and Raines, 2001). Significant faults, fractures, and other effects of pervasive diagenesis overprint the primary depositional fabric. The prominent diagenetic processes, which created additional reservoir complexity, included dolomitization, karstification, and cementation (Leary and Vogt, 1990; Adams, 1997; Stoudt and Raines, 2000). RESERVOIR STRUCTURE Reservoir quality and compartmentalization of the San Andres Formation in the Central Vacuum Unit are related to stratigraphic, diagenetic, and structural variability. Alternating cycles of subtidal, intertidal, and supratidal deposits compartmentalize the reservoir vertically. Lateral transitions in facies associations produce variations in reservoir quality. Faults also compartmentalize the reservoir laterally. Definition of faults in the Central Vacuum Unit was achieved through the use of compressional-wave seismic data, seismic coherency, and well data. Seismic Coherency Coherency volumes were generated from 3-D, compressional-wave seismic data. A coherency volume shows changes in seismic character associated with the similarity Pranter et al. 103

6 Figure 4. Stratigraphic column of the main geologic formations at or near Vacuum field. (continuity) or lack of similarity (discontinuity) among neighboring seismic traces. To compute coherency attributes, each seismic trace was compared with eight surrounding traces, and correlation coefficients or semblance values were calculated for each trace pair (comparison of the central trace with each of the eight surrounding traces) through cross correlation. The correlation coefficients of each pair were then used to determine a single continuity attribute value for the central trace in the comparison pattern. In general, high coherency is typical for a relatively flat and continuous seismic event. A regional seismic coherency map of the lower San Andres horizon (Figure 6) shows east-west trending discontinuities associated with interpreted normal faults along the Leonardian-Guadalupian shelf margin in the Central Vacuum Unit (Talley, 1997). Faults identified on regional 3-D seismic amplitude and coherency volumes (Talley, 1997) appear to compartmentalize the reservoir and affect production. Vertical throw of the main faults is estimated from seismic and well data to range from 0 to 70 ft (0 to 21 m), but is generally less than 25 ft (8 m). The main faults are intersected by smaller scale faults with minor 104 Dual-Lateral Horizontal Wells Target Bypassed Pay in the San Andres Formation

7 In the Central Vacuum Unit, two main (and one minor) faults were identified at the southern edge of the unit. The faults trend approximately parallel to the shelf margin (Figure 6). The low seismic coherency anomaly that parallels the shelf margin at the lower San Andres level (Figure 6) is also observed at the upper San Andres horizon (Figure 7). This linear, low-coherency anomaly crosses well CVU-110 at the shelf margin. The low-coherency trend corresponds to high-angle faults that parallel the shelf margin and displace the San Andres interval (Figure 8). A north-south seismic profile that crosses the area (Figure 9) shows the San Andres interval and the fault-related seismic discontinuities at the shelf margin. Horizontal Wells Figure 5. Type log of the San Andres reservoir in the Central Vacuum Unit. LSA = lower San Andres, USA = upper San Andres. offset (10 ft [3 m] vertical displacement). The smaller scale faults are defined using well data and structure maps with small contour intervals and are not imaged on the 3-D seismic data. The reservoir was developed using a regular waterflood pattern (inverted five-spot) in this area of the field. The pattern was originally designed without regard to faults because they were unknown at the time the pattern was initially developed. Based on a preliminary structural analysis of shelf-margin faults (Talley, 1997; L. Duranti, 1998, personal communication), two medium-radius, horizontal wellbores were proposed to be drilled from the vertical production well CVU- 110 to intersect isolated fault blocks for oil banked against faults and in thin reservoir zones. An estimate of the streamtube pattern (fluid-flow paths) between wells based on production and injection rates and pressure data indicated that the faults could separate the reservoir into blocks that were not adequately drained by vertical wells in the existing injectionproduction pattern. The streamtube analysis, which included a primary sealing fault, indicated that the injection well pattern would result in banked oil against the fault in two different locations (Figure 10). Examination of production and injection data revealed that certain wells on opposite sides of the fault were not in communication on a production timescale. The horizontal drilling plan for CVU-110 was designed to target the potential oil banks on both sides of the fault. Lateral serpentine (snaky) wellbores (in the vertical plane) were drilled to intersect several depositional cycles in fault-bounded compartments, improve the sweep efficiency, and replace existing vertical wells. Lateral serpentine wellbores are desirable in a stratified reservoir because of the increase in reservoir exposure from isolated reservoir zones along a single well path (Corlay et al., 1997). In addition, Pranter et al. 105

8 Figure 6. Top of the lower San Andres Formation seismic coherency map. Lighter shades indicate areas of low seismic continuity, and darker shades indicate areas of high seismic continuity. Well CVU-110 is the vertical well that was used to drill the two horizontal wells. with higher horizontal permeability/vertical permeability ratios, the productivity of a serpentine wellbore is generally higher than that of a slanted wellbore of similar length (Corlay et al., 1997). The northwestern lateral well, CVU-110-NW, was terminated 150 ft (50 m) from the offset vertical well, CVU-111 (Figure 11), and has not affected production from the well. The northeastern lateral well, CVU-110-NE, passed within 75 ft (25 m) of CVU-109 (Figure 12) and terminated 330 ft (100 m) from the leaseline (the legal setback distance). The lateral wells were deviated after exiting milled sections in the vertical wellbore. While drilling well CVU-110-NW, the steering was difficult to control initially. In this interval, the anhydrite content was high. Dogleg severity, a relative measure of the rate of change in borehole deviation, was also anomalous in this interval. These characteristics occurred in an area where a fault was expected, and were attributed to drilling through the fault at a highly oblique angle. To identify the faults encountered by the horizontal wells, the horizontal well logs were converted to true vertical depth for direct correlation to adjacent vertical wells. In general, correlation of reservoir zones was based on gamma-ray and neutron porosity log signatures. Fault cuts were identified in wells as zones of ft (3 8 m) of missing section on the logs (Pranter, 1999). Intervals above and below these zones of missing section are correlative between the horizontal and vertical wells. Although the observed fault throw is generally less than 25 ft (8 m), it is sufficient to offset relatively thin depositional cycles, reduce lateral fluid flow across the fault, and limit the efficiency of vertical production wells. Cross sections through wells CVU-110-NW and CVU-110-NE show fault locations along the well paths 106 Dual-Lateral Horizontal Wells Target Bypassed Pay in the San Andres Formation

9 Figure 7. Top of the upper San Andres Formation seismic coherency maps. Darker shades indicate areas of low seismic continuity, and lighter shades indicate areas of high seismic continuity. The time-lapse seismic area is shown by the large open circle. (A) Map generated from coherency data (unfiltered), and (B) map generated from coherency data with frequency-wavenumber (f-k) fan filter applied to eliminate minor discontinuities and emphasize the more significant discontinuities (modified from Talley, 1997). Pranter et al. 107

10 Figure 8. Map of fault traces interpreted from 3-D seismic amplitude and coherency data. The fault patterns represent the projection onto the map of all fault traces that were interpreted for each time slice or stratigraphic interval through the San Andres Formation (provided by L. Duranti). The fault trace patterns spread out because the faults are not vertical. The location of the seismic profile of Figure 9 is shown. (Figures 11, 12). As much as 25 ft (8 m) of vertical displacement can be inferred at the wellbore from the given data. Based on the fault patterns observed on the 3-D seismic coherency data and production characteristics, the faults approximately parallel the shelf margin (Figure 13) and separate nearby vertical wells to form undrained fault blocks. Production data from CVU-110 and nearby producers, CVU-109 and CVU-111, illustrate the significance of the fault blocks. The CVU-110 horizontal wellbores were completed open hole for 273 bbl oil/ day, 53,000 ft 3 of gas per day, and 279 bbl of water per day (previous production from the CVU-110 vertical well was bbl per day and had been declining for many years). A graph of monthly oil production for the wells clearly shows a significant increase in oil production in CVU-110 associated with the dual-lateral development. However, there was no change in production in the offset wells (Figure 14), presumably because of compartmentalization by faults. Based in part on the results of CVU-110, several additional horizontal wells were drilled in the San Andres interval at Central Vacuum Unit. However, none of these wells specifically targeted oil banks stranded against sealing faults. Instead, they were individually designed to address issues such as (1) controlling upper 108 Dual-Lateral Horizontal Wells Target Bypassed Pay in the San Andres Formation

11 Figure 9. North-south compressional-wave seismic profile showing seismic discontinuities associated with faults at the shelf margin. The projected well path for the CVU- 110 vertical well is shown as a white vertical line. Figure 10. Map showing an estimate of the streamtube pattern (fluid-flow regions) between wells based on production and injection rates and pressure data. The areas with gradational shading depict approximate production and injection regions that exist when the major northeast-southwest trending fault (bold solid black line) is included as a sealing fault. Regions that are estimated to be unaffected by the waterflood or areas of potential banked or unswept oil are shown on both sides of the fault. These regions were the targets for the horizontal wells. Pranter et al. 109

12 Figure 11. Cross section of the CVU-110-NW horizontal well. Faults intersected by the horizontal well are shown. Figure 12. Cross section of the CVU-110-NE horizontal well. Fault intersected by the horizontal well is shown. 110 Dual-Lateral Horizontal Wells Target Bypassed Pay in the San Andres Formation

13 Figure 13. Map of faults intersected by the horizontal wells from CVU-110. Based on the fault patterns observed on the 3-D seismic coherency data and production characteristics, the faults approximately parallel the shelf margin. and lower San Andres injection and production separately; (2) replacing vertical well locations; (3) improving lateral pattern sweep efficiency; (4) connecting discontinuous pay; (5) improving effective productivity in a single well or zone; and/or (6) distributing pressure sinks (or sources) along a line (as opposed to a point source). All of these additional wells did, however, use the serpentine approach as much as feasible. CONCLUSIONS Fault blocks present along the Leonardian Guadalupian shelf margin in the Central Vacuum Unit are sites of bypassed pay and banked oil in relatively thin depositional cycles of the San Andres Formation. Seismic coherency data, when combined with production information, is useful for detecting faults that compartmentalize the reservoir. The observed fault throw is generally less than 25 ft (8 m), but it is adequate to offset relatively thin reservoir zones and limit the efficiency of vertical production wells. By using multilateral serpentine horizontal wells, compartmentalized areas that are not adequately drained can be targeted to increase overall recovery efficiency. Horizontal development wells have a great potential for increasing rates of production, improving sweep efficiency, and increasing recoverable reserves in the San Andres interval of Vacuum field and elsewhere. Pranter et al. 111

14 Figure 14. Plot of monthly oil production vs. time for CVU-109 (solid gray line), CVU-110 (solid black line), and CVU-111 (dashed gray line). The significant increase in production from CVU- 110 corresponds to the completion of the dual-lateral horizontal wells in early The completion of the two horizontal wells did not affect production from the offset vertical wells. These data also support the sealing capacity of the faults. REFERENCES CITED Adams, S. D., 1997, Sedimentology and diagenesis of the San Andres Formation, Vacuum field, New Mexico: M.S. thesis, T-5060, Colorado School of Mines, Golden, Colorado, 158 p. Benson, R. D., and T. L. Davis, 2000, Time-lapse seismic monitoring and dynamic reservoir characterization, Central Vacuum Unit, Lea County, New Mexico: Society of Petroleum Engineers Reservoir Evaluation & Engineering, SPE Paper 60890, p Corlay, P., D. Bossie-Codreanu, J. C. Sabathier, and E. R. Delamaide, 1997, Improving reservoir management with complex well architectures: World Oil, v. 218, p Hills, J. M., 1984, Sedimentation, tectonism and hydrocarbon generation in Delaware basin, west Texas and southeastern New Mexico: AAPG Bulletin, v. 68, p Kerans, C., and K. Kempter, 2002, Hierarchical stratigraphic analysis of a carbonate platform, Permian of the Guadalupe Mountains: AAPG/Datapages Discovery Series No. 5, CD-ROM. Kerans, C., and S. W. Tinker, 1997, Sequence stratigraphy and characterization of carbonate reservoirs: SEPM Short Course Notes 40, 130 p. Leary, D. A., and J. N. Vogt, 1990, Diagenesis of the San Andres Formation (Guadalupian), Central Basin platform, Permian basin, in D. G. Bebout and P. M. Harris, eds., Geologic and engineering approaches in evaluation of San Andres/Grayburg hydrocarbon reservoirs Permian basin: Texas Bureau of Economic Geology, p Mitchum, R. M., Jr., and J. C. Van Wagoner, 1991, High-frequency sequences and their stacking patterns: sequence stratigraphic evidence of high-frequency eustatic cycles, in K. T. Biddle and W. Schlager, eds., The record of sea-level fluctuations: Sedimentary Geology, v. 70, p Pranter, M. J., 1999, Use of a petrophysical-based reservoir zonation and multicomponent seismic attributes for improved geologic modeling, Vacuum field, New Mexico: Ph.D. dissertation, Colorado School of Mines, Golden, Colorado, 366 p. Purves, W. J., 1990, Reservoir description of the Mobil oil bridges state leases (upper San Andres reservoir), Vacuum field, Lea County, New Mexico, in D. G. Bebout and P. M. Harris, eds., Geologic and engineering approaches in evaluation of San Andres/Grayburg hydrocarbon reservoirs Permian basin: Texas Bureau of Economic Geology, p Roche, S. L., T. L. Davis, R. D. Benson, and L. Duranti, 2001, Dynamic reservoir characterization; application of time-lapse (4-D), multicomponent seismic to a CO 2 EOR project, Vacuum field, New Mexico (abs.): AAPG Bulletin, v. 85, p Scuta, M. S., 1997, 3-D reservoir characterization of the Central Vacuum Unit, Lea County, New Mexico: Ph.D. dissertation, Colorado School of Mines, Golden, Colorado, 274 p. Stoudt, E. L., and M. A. Raines, 2000, Karst features in the San Andres Formation on the northwest shelf of the Permian 112 Dual-Lateral Horizontal Wells Target Bypassed Pay in the San Andres Formation

15 basin; they re not just at Yates field anymore!, in S. T. Reid, ed., Transactions, Southwest Section AAPG, 2000 Convention: SWS Publication , p Stoudt, E. L., and M. A. Raines, 2001, Reservoir compartmentalization in the San Andres Formation of Vacuum field, Lea County, New Mexico; peritidal deposits and karst overprints create vertical and lateral barriers to fluid flow in carbonate platform dolopackstones and dolograinstones (abs.): AAPG Bulletin, v. 85, p Talley, D. J., 1997, Characterization of a San Andres carbonate reservoir using four dimensional multicomponent attribute analysis: M.S. thesis, Colorado School of Mines, Golden, Colorado, 75 p. Tinker, S. W., 1998, Shelf-to-basin facies distributions and sequence stratigraphy of a steep-rimmed carbonate margin: Capitan depositional system, McKittrick Canyon, New Mexico and Texas: Journal of Sedimentary Research, v. 68, no. 6, p Wehner, S. C., and J. Prieditis, 1996, CO 2 huff-n-puff: initial results from a waterflooded ssc reservoir: Proceedings of the Society of Petroleum Engineers Permian Basin Oil and Gas Recovery Conference, SPE Paper 35223, p Pranter et al. 113