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Abstract The combination of extended-length horizontal drilling and high volume hydraulic fracturing has led to previously unimaginable production increases, yet the recovery potential of unconventional oil and gas resources remains largely unrealized. Recovery factors for unconventional oil and gas wells are typically reported at < 20% in gas shale reservoirs and < 10% in the oil plays. Neutrally buoyant ultra-lightweight proppants have been demonstrated to effectively provide production from fracture area that is otherwise unpropped and thus, non-contributive with conventional sand/slickwater hydraulic fracturing processes. Production simulations illustrate that treatment designs incorporating neutrally buoyant ULW proppant treatment designs tailored for contemporary unconventional well stimulations deliver cumulative production increases of 30% to over 50% compared to the typical large volume sand/slickwater treatments. Unfortunately, production simulation results may not sufficiently lessen risk uncertainties for operators planning high-cost multi-stage horizontal stimulations. Therefore, several field trial projects using the neutrally buoyant ULW proppant in extended-length horizontal unconventional wells are currently in progress to validate the production simulations. Since the initial 4-stage fracturing stimulation incorporating neutrally buoyant ultra-lightweight proppant in 2007, deployment has occurred in fracture stimulating hundreds of oil and gas wells spanning multiple basins and reservoirs. Most of the wells are vertical or relatively short lateral wells common to asset development practices predating the unconventional shale completions mania, but many were targeted at the same unconventional reservoirs as the current multi-stage horizontal completions. Several published case histories have documented the production enhancement benefits afforded by the legacy ULW proppant wells, but questions remained as to how those lessons might be correlated to provide engineers confidence in the current production simulations. Well completion and production information was mined from the various accessible databases for the neutrally buoyant ULW proppant wells. The scope of the legacy data compiled for analysis was limited to the reservoirs common to the current field trials and production simulations, ie. unconventional oil and gas shale reservoirs. Production performance contributions of neutrally buoyant ULW proppant in past applications were compared with the production uplift observed in applications and/or simulated application of neutrally buoyant ultra-lightweight proppant fracturing treatments in current multi-stage horizontal reservoirs. The lessons learned from this investigation provide the practicing engineer the means to confidently assess production simulation data for multi-stage horizontal unconventional completions incorporating neutrally buoyant ulw proppant in the treatment designs.
Abstract The Permian Basin in West Texas contains one of the thickest deposits of Permian rocks found anywhere in the world. The Embar-B lease located in southern Andrews County on the Central Basin Platform (a regional structural high in the Permian Basin) has been producing from the Leonardian Clearfork formation for over 70 years. The Clearfork formation is primarily a subtidal and intertidal carbonate rock characterized as moderate quality reservoir. Most Permian Basin fields have multiple stacked reservoirs with varying degrees of reservoir quality and there is typically a need in these maturing fields to increase reservoir contact. In 2009, a drilling campaign was launched in Embar-B with a focus on expanding the completion interval to include what was previously considered marginal pay in the deeper Wichita Albany formation. The Wichita Albany, also Leonardian in age, is composed mostly of marginal quality tidal flat rocks and is characterized by high fracture gradients and low permeability. These characteristics required an advancement in completion practices to achieve a successful stimulation. The combination of improved completions practices and an expanded target interval resulted in production double that of previous wells. This success has driven a need for an innovative development strategy and continued optimization of completion practices. Geomodeling, volumetrics, reservoir simulation, seismic attribute analysis and oil fingerprinting were all used for reservoir characterization and to determine an allocation method for commingled wells. This lead to the identification of several Clearfork/Wichita Albany locations with significant reserves potential. Re-evaluation of the completion strategy using a multidisciplinary approach indicated the need to reduce the number of perforation clusters, add a diversion mechanism, and develop multiple hydraulic fracturing designs based on reservoir quality and presence of natural fractures. Results from recent drilling programs have exceeded expectations bringing lease production up from 200 BOEPD in 2009 to a peak rate of 3153 BOEPD in 2015.
Abstract This paper presents the integrated approach for the redevelopment of the waterflood in Howard-Glasscock field located primarily in Howard County, Texas. Originally discovered in 1925, the majority of production is now commingled across the Guadalupe, Glorieta and Clearfork formations. This is a mature field which is currently in the midst of a 5 and 10 acre infill drilling program that began in 2009. Emphasis has primarily been focused on drilling producing wells, but the basis for this project was to optimize an existing waterflood to guide the development strategy of the field moving forward. A study of the production of the wells drilled since 2009 identified stronger performance in wells with offset waterflood support. On average, waterflood was responsible for a 22% improvement in the expected recovery per well, despite a lack of patterns or a comprehensive waterflood management plan. As a result, a multi-disciplined team was commissioned to design a strategy for the redevelopment of the flood and more active management of the daily operations. Geology and reservoir engineering aspects were used to characterize the reservoir in conjunction with classical waterflood methods to understand the current performance and validate the expectations for secondary recovery. Fracture orientation was studied based on cases of early breakthrough and was utilized in pattern identification and well placement to maximize sweep and discourage direct communication between injectors and producers. Further, the success of the waterflood in Howard-Glasscock relies on the ability to control the flow of water over a 2,000 foot vertical interval. To address this, the team has implemented a surveillance plan with improved monitoring and communication with the operations team to enhance the collection of data and in order to react to the dynamics of a waterflood. The rapid response to injection observed in this field requires proper surveillance and timely control of water flow which ultimately drives the success of the program by moving water from high water cut intervals to bypassed oil zones. This paper details the systematic approach that was used to design the redevelopment plan for a waterflood in a 90 year old field. The scope of work is being implemented and represents an adjustment in the development plan of Howard-Glasscock moving forward. Ultimately, the enhanced performance observed in recent drilling programs and the continued success of development in this mature field hinges on understanding and managing the waterflood moving forward.
Abstract In this paper we will describe fairly simplistic completion techniques which have dramatically changed the economics of completion in the Yeso and San Andres formations in southeastern New Mexico. The design optimization process will be described and comparisons made with offset operators for several years of production. For many years the standard completion technique for the Yeso and other carbonate formations in Southeastern New Mexico was the use of large volumes of hydrochloric acid. The acid was sometimes heated, sometimes gelled. The acid was combined with various diverting aids to achieve what was considered excellent stimulation. In 2006 it was decided to reevaluate stimulation procedures and the oil company decided to use a similar process being utilized in Shale plays and many unconventional reservoirs. The Yeso and San Andres, with some natural fracturing and most of other criteria needed for successful use of what is termed "Waterfrac Sweep", were considered good candidates. This process uses only water and small proppant concentrations pumped at a high rate. The process has found success in virtually every shale play in the US as well as many conventional reservoirs such as the Granite Wash, Cotton Valley, Mesa Verde, Travis Peak, Atoka, and Olmos. The paper will document the results of more than 100 fracs showing long term production data and comparisons to offset operators using more complex and more expensive systems. We will go through the completion process as it was used in large casing, thus in many instances totally eliminating the need for friction reducers. Very minimal chemicals are used plus proppant sizes no larger than 40/70 in concentrations not exceeding 2.5 pounds per gallon. Based on oil production data we feel infinite conductivity production is being achieved through propped open fractures instead of proppant packs. There are countless naturally fractured carbonate reservoirs throughout the world that can benefit from this very straightforward stimulation procedure.
Summary A considerable portion of the world's hydrocarbon endowment is in carbonate reservoirs. Carbonate reservoirs usually exhibit low porosity and may be fractured. These two characteristics along with oil-to-mixed wet rock properties usually result in lowered hydrocarbon recovery rates. When enhanced oil recovery (EOR) strategies are pursued, the injected fluids will likely flow through the fracture network and bypass the oil in the rock matrix. The high permeability in the fracture network and the low equivalent porous volume result in early breakthrough of the injected fluids. Infill drilling programs and well conformance strategies—mostly gas and water shutoff—have been effectively used to mitigate the early breakthrough and increase oil recovery. In most cases, however, 40 to 50% of the original oil in place (OOIP) is not produced. A large number of EOR field projects in carbonate reservoirs have been referenced in the literature since the early 1970s. These field projects demonstrate the technical feasibility of various EOR methods in carbonate reservoirs. However, because of the collapse in oil prices, most of the aforementioned project plans have been abandoned. This paper presents a comprehensive compilation of EOR (Gas, Chemical, and Thermal methods) field experiences in carbonate reservoirs within the US, as an attempt to identify key variables and project design parameters for future evaluation and revitalization of mature carbonate reservoirs. Carbon dioxide flooding [continuous or water-alternating gas (WAG)] is the dominant EOR process used in the US This is because of the high availability of low-cost CO2. CO2 EOR in particular represents the logical first step towards viable geologic carbon storage and sequestration. EOR chemical methods in carbonate reservoirs, especially polymer flooding, have been widely tested in US carbonate reservoirs. However, EOR chemical methods have made a marginal contribution, relatively, in terms of total oil recovered. Our study includes a brief overview of current laboratory (e.g. wettability changes and novel chemical additives) and field (e.g. injectivity enhancement) experiences in EOR chemical methods in carbonate formations. A brief discussion surrounding the screening methods used to identify viable EOR opportunities in carbonate fields based on past and present experiences is also included. Introduction Carbonate reservoirs are naturally-fractured geologic formations characterized by heterogeneous porosity and permeability distributions. In the case of low porosity and low permeability carbonate rocks (more specifically rock matrices), the fluid flow in the reservoir can be completely dependent on the fracture network while the matrix only plays a source role (analogous to tight sand formations and natural gas flow). In the case of porous carbonate rocks, fracture networks can cause uneven sweeping of the reservoir, leading to early breakthrough of injected fluids in the producing wells and resulting in low recovery factors. The abundance of carbonate reservoirs has been the subject of numerous studies attempting to characterize their heterogeneities, classify different types of fractured reservoirs, and determine how rock and fluid properties have an impact on ultimate recovery (Roehl et al. 1985; Allan and Qing Sun 2003; Carr et al. 2001; Grave et al. 2000; Benson et al. 1998; Wardlaw 1996). The TORIS database (maintained by the US Department of Energy) indicates 22% of the OOIP in the US is contained in shallow-shelf carbonate reservoirs. Currently in the US, these types of reservoirs exist in more than 14 states with over 70% of the OOIP located in reservoirs in Texas and New Mexico, mostly concentrated in the Permian Basin (Nuckols 1992, Xie et al. 2005). Over the last three decades, primary production, waterflooding, and CO2 floods, combined with infill drilling programs, have been the most widely used recovery methods. However, other EOR strategies have been tested in the past and there are currently several active research programs seeking alternatives to increase the recovery factor of these mostly light crude-oil reservoirs economically. Although the Permian Basin (west Texas and southeast New Mexico) can be considered mature, its potential for improved oil recovery is still very high. A recent study reports that there is an estimated 30 billion barrels of mobile oil in the Permian Basin, reiterating the strategic importance of EOR technologies for carbonate reservoirs and their impact on US oil production (Nuckols 1992; Xie et al. 2005; Seethepalli et al. 2004; Moritis 2004; Cole 2003; Moritis 2003; Dutton et al. 2004).
Zeng, Hongliu (Bureau of Economic Geology) | Kerans, Charles (Bureau of Economic Geology) | Lucia, Jerry (Bureau of Economic Geology) | John, A. (Jackson School of Geosciences, The University of Texas at Austin) | Katherine, G. (Jackson School of Geosciences, The University of Texas at Austin)
Summary We observed widespread existence of a collapsed paleocave system over the 40-mi2 area covered by a 3-D seismic survey in Hobbs field, Permian Basin, New Mexico. These karst collapse features originated at the top of the Clear Fork/Glorieta 2nd-order sequence boundary. Vertical collapse of cave systems created chimneylike, sloping features extending as high as 1,600 ft above the top of the Clear Fork/Glorieta into overlying San Andres carbonates. Major collapse features tend to be circular, with diameters ranging from 1,000 to 6,000 ft. Minor collapse features appear as troughs connecting major circular collapse dolines. These troughs are oriented in both NWSE and SW-NE directions, most likely defining dominant regional fracture trends. Limited well control reveals the beginnings of paleocaves in high-velocity/low-porosity carbonates that favor development of large, isolated solution caves. The distribution and origin of these collapsed paleocave systems are similar to those of published Ellenburger karst collapse chimneys in the Boonsville gas field, Texas. Introduction Paleocave systems in carbonate rocks are important hydrocarbon reservoirs in the Permian Basin and elsewhere. Paleocave reservoirs are extremely complex because of the combination of near-surface, porosity-generating dissolution processes and later burial processes, including collapse, faulting, and fracturing. These processes make it difficult to predict and map reservoir compartments. So far the most successful studies of paleocave reservoirs have been those using outcrop, core, and wireline-log data(e.g., Lucia, 1995, on Ellenburger paleocaves in Franklin Mountains; Kerans, 1988, on Ellenburger karst heterogeneity in west Texas; Loucks, 1999, on origin, burial, and spatial complexity of paleocave reservoirs). Hardage et al. (1996) pioneered seismic interpretation of the karst collapse features in Ellenburger carbonates in Boonsville field, Texas, revealing seismic detection power in characterizing karst reservoirs. In the Permian Basin, outcrop studies have revealed multiple paleocave karsting events in platformal carbonate depositional sequences; many of these events are detectable using seismic data. In this study, we report some results of a reservoir characterization project currently under way in Hobbs field, Permian Basin, New Mexico. Whereas the main target of the study is the upper San Andres reservoir, we observed widespread, large-scale, collapsed paleocave systems in the immediately underlying Clear Fork/Glorieta carbonate platform (hereafter referred as Glorieta). Although different in age and depositional/burial history, these systems are comparable to Ellenburger karst chimneys in Boonsville field, Texas (Hardage et al., 1996). Similar karst collapse features have not been reported in Permian Basin literature, suggesting a probable new exploration play. The top of the Clear Fork/Glorieta platform is a major 2nd-order sequence boundary, and, thus, the occurrence of paleokarst at this stratigraphic level should be expected. Because Hobbs is developed atop one of the major uplifts of the Permian Basin, we predict that similar structures associated with Ancestral Rocky Mountain deformation (Ye et al., 1996) and the uplift will have similar paleokarst development. Seismic Evidence of Cave Collapse
Abstract A considerable portion of the world's hydrocarbon endowment, and even more so if resources from the Middle East are excluded, are in carbonate reservoirs. Carbonate reservoirs usually exhibit low porosity and may be fractured. These two characteristics in addition to oil-to-mixed wet rock properties usually results in low recovery. When enhanced oil recovery (EOR) strategies are pursued, the injected fluids will likely flow is through the fracture network, bypassing oil in the rock matrix. The high permeability in the fracture network and its low equivalent porous volume result in early breakthrough of the injected fluids. Infill drilling programs and well conformance strategies, mostly gas and water shutoff, have been effectively used to mitigate the early breakthrough and increase oil recovery. However, in most cases, 40 to 50% of the original oil in place (OOIP) is not produced. A large number of EOR field projects in carbonate reservoirs have been reported in the literature since the early 70's. The field projects showed the technological capability to increase oil recovery and estimated long run costs for their operation. This increase in oil recovery would directly result in additional reserves extending the productive life of the different assets. However, the technical results were not matched by their economic viability given the price environment of the time. In some cases high upfront investments created insurmountable barriers for the technology's application despite the promise of higher returns. In other cases, the high marginal costs eliminated all benefits from the increased recovery. The latter was especially true for EOR processes based on chemical and thermal methods. Over the last three decades, many improvements have reduced the cost per incremental barrel as will be seen below. Carbon dioxide flooding (continuous or alternating with water-WAG) is the dominant EOR process in the United States, mostly due to the availability of appropriate CO2. CO2 EOR is also the stepping stone towards sequestering carbon which could become a future business opportunity if carbon trading ever is implemented. This paper presents an overview of EOR field experiences in carbonate reservoirs in the United States, an analysis of recent efforts and discusses briefly on new opportunities for novel chemical methods. The main EOR experiences reviewed are CO2 injection, polymer flooding, steam injection and in-situ combustion (air injection). Introduction Carbonate reservoirs are naturally fractured geologic formations characterized by heterogeneous porosity and permeability distributions. For example, in the case of low porosity and low permeability carbonate rocks (more specifically rock matrices), the fluid flow in the reservoir can be completely dependent on the fracture network, while the matrix only plays a source role, analogous to tight sand formations and natural gas flow. In the case of porous carbonate rocks, fracture networks can still cause uneven sweeping of the reservoir leading to early breakthrough of injected fluids in the producing wells, resulting in low recovery factors. Given the abundance of carbonate reservoirs, they have been the subject of numerous studies that have made attempts to characterize the heterogeneities of carbonate reservoirs, classify the different types or classes of fractured reservoirs and determine how rock and fluid properties of carbonate reservoirs impact ultimate recovery [1–6].
Abstract San Andres carbonate reservoirs have long been known to have a high degree of reservoir heterogeneity and poor recovery efficiencies. Fractures are one of several causes of this heterogeneity. The heterogeneity causes unpredictability in water and CO2 flooding. However, the correct placement of horizontal wells can take advantage of this problem. An integrated reservoir characterization study of the Mabee field incorporating oriented core, Formation Microscanner (FMS) wireline logs, seismic time slices, production character, curvature analysis, and interference testing was used to predict fracture orientation and areas of highest fracture density. These fracture characteristics were then applied to determine horizontal well loca-tion and orientation. Fracture orientation was evaluated through the analysis of oriented core, FMS logs, and interference testing, indicating a fracture orientation of N70W. Analysis of the induced fractures in the oriented core indicates that the direction of maxi-mum horizontal compressive stress is N45E. High fracture density was delineated by curvature analysis, relative seismic amplitude, and areas of higher production. Areas with high curvature corre-spond to areas of high relative seismic amplitude and higher production. The data integration indicates that four areas have high fracture density. The synthesis of fracture orientation and density, along with the production character, indicates the optimal location and orientation of horizontal wells. Introduction Low-permeability San Andres reservoirs of the Central Basin Platform contain significant volumes of remaining oil. The Mabee San Andres field lies on the northeastern edge of the Central Basin Platform (Fig. 1) and is part of the San Andres/Grayburg Platform Carbonate play. Ref. 1 reported recovery efficiencies for secondary recovery of approximately 30% and an unrecovered resource of 2.6 billion stock-tank barrels of oil. The low recovery efficiency and still-remaining resource are due largely to the signif-icant amount of heterogeneity found in these reservoirs. San Andres Platform Carbonate reservoirs are highly hetero-geneous because of the depositional facies, diagenesis, and frac-turing. Ref. 2 described how grainstone bar depositional facies significantly affected the production character in Dune (Grayburg) reservoirs. Ref. 3 described how areas of postdepositional dia-genesis were the most highly productive in the Jordan (San Andres) reservoir. Additionally, fractures have been cited as contributing significant heterogeneity to San Andres/Grayburg reservoirs. Ref. 4 sited fractures in the Arrowhead (Grayburg) reservoir as the reason that tracers broke through in 2 days between a five-spot well pat-tern. Ref. 5 described the influence of fractures in the Keystone East (San Andres) reservoir. Ref. 6 described how fractures in the Chaveroo and Cato (San Andres) reservoirs influenced flow and storage volume. Ref. 7 depicted natural fractures as dominating the permeability character in zones of the Levelland (San Andres) reservoir. This heterogeneity causes preferential fluid flow and often-early breakthrough in waterfloods. It is also the likely cause of water loss previously unaccounted for in San Andres waterflood operations. Ref. 5 described a northeast preferential flow direction coincident with their interpreted direction of maximum horizontal compressive stress. Ref. 8 cited the Fullerton Clear Fork, Keystone Colby, and Means (San Andres/Grayburg) reservoirs as having east-west preferential flow directions. It is reasonable that this similar preferential flow direction in several fields and several formations is due to open fractures. Both the direction of open fractures and the location of densely spaced fractures influence how fractures affect production. In this study we combine geologic and engineering information including interference tests, oriented core, Formation Microscanner (FMS) logs, production data and curvature analysis to evaluate the direc-tion of open fractures and the areas where they may be more densely spaced.
Summary This article presents the results of a multidisciplinary, four-dimensional (4D) (time-lapse), three-component (3C) (multicomponent) seismic study of a CO2 injection project in vacuum field, New Mexico. The ability to sense bulk rock/fluid properties with 4D, 3C seismology enables characterization of the most important transport property of a reservoir, namely, permeability. Because of the high volume resolution of the 4D, 3C seismology, we can monitor the sweep efficiency of a production process to see if reserves are bypassed by channeling around lower permeability parts of the reservoir and the rate at which the channeling occurs. In doing so, we can change production processes to sweep the reservoir more efficiently. Introduction Improving reservoir performance and enhancing hydrocarbon recovery while reducing environmental impact are critical to the future of the petroleum industry. To do this, it must be possible to characterize reservoir parameters including fluid properties and their changes with time, i.e., dynamic reservoir characterization. The objectives of our research arerepeated acquisition of a three-dimensional (3D), three-component (3C) seismic survey; demonstrate the ability of 3D, 3C, and four-dimensional (4D), 3C seismology to detect and monitor rock/fluid property change associated with a production process; incorporate geological, petrophysical, petroleum engineering, and other geophysical studies; refine the reservoir model and recommend procedures for scaling up from a pilot injection program to partial field flood to achieve maximum sweep efficiency and minimize bypassed reservoir zones; link bulk rock/fluid property variation monitored by time-lapse multicomponent (4D, 3C) seismic surveying to dynamic attributes of the reservoir including permeability, fluids, and flow characterization. Three-dimensional, 3C seismology involves seismic data acquisition in three orientations at each receiver location—two orthogonal horizontal and one vertical. When three source components are used, nine times the amount of data of a conventional P-wave 3D survey can be recorded. Horizontal components of source and receiver displacements enable shear- (S-) wave recording; this is a powerful complement to vertical P-wave recording. Three-dimensional, 3C seismic surveys provide significantly more information about the rock/fluid properties of a reservoir than can be achieved from conventional P-wave seismic surveys alone. By combining P- and S-wave recording, the seismic ability to determine rock/fluid property changes in the subsurface is increased. Seismic wave propagation includes travel time, reflectivity, and the effects of anisotropy and attenuation. In-situ stress orientation and relative magnitudes can be derived from seismic anisotropy. Rock/fluid properties, including lithology and porosity, may be obtained from comparative travel times or velocities of P and S waves. Other rock/fluid properties, including permeability, may be determined from comparative P and S anisotropy, travel time, reflectivity, and attenuation measurements. By combining P- and S-wave recording, seismic wave propagation characteristics can be transformed into reservoir parameters. Introducing time as the "fourth dimension," new time-lapse (4D), 3C seismology is a tool to monitor production processes and to determine reservoir property variations under changing conditions. Using 4D, 3C seismic monitoring as an integral part of dynamic reservoir characterization, refinements can be made to production processes to improve reservoir hydrocarbon recovery. VP/VS ratios for both the fast S1 shear component and slow S2 shear component may provide a tool for separating bulk rock changes due to fluid property variations from bulk rock changes due to effective stress variations. Changes in shear wave anisotropy may reflect varying concentrations of open fractures and low aspect ratio pore structure in both a spatial and temporal sense across the reservoir. The permeability of a formation, or the connectivity of the pore space, will be the target in 4D, 3C seismology. Refinements made to reservoir characterization techniques and their applications, now extending into the fourth dimension, are an important new area of research. Benefits of this research will include improved reservoir characterization and correlative increased hydrocarbon recovery and reduction in operating costs through improved reservoir management. Geologic Setting Since early Permian time, the general evolution of the portion of the Permian Basin which includes vacuum field is that of a progressively shallowing-upward carbonate platform. Aggrading and prograding cycles represent, respectively, the results of high stand and still stand sea levels. At the shelf edge these platform carbonates typically grade into reef-type deposits such as the Abo, Goat Seep, and Capitan formations. The San Andres is an exception; no reef-like rocks have been detected. Beyond the shelf edge, in the Delaware basin, clastic rocks, especially siliciclastics, were deposited during a lowstand sea level. Vacuum field is located on a large anticlinal structure that plunges slightly to the east-northeast. The San Andres and Grayburg formations correspond to the rim of a broad carbonate shelf province to the north and northwest, northwest shelf, and of a deeper intracratonic basin, Delaware basin, on the southeast and east. The overall area including the Midland basin, northern and eastern shelves, and central basin platform are part of a major restricted intracratonic basin which existed during Permian time. West Texas and southeast New Mexico were in the low latitudes throughout the late Paleozoic period, making them an ideal location for carbonate sedimentation. As a consequence of this tropical environment, broad carbonate shelves were established on the margins of the Delaware and Midland basins.
Abstract The Reservoir Characterization Project (RCP) is an industry sponsored consortium whose mission is to develop and apply 3-D and 4-D ("time-lapse"), 3-C seismology and associated technologies to improve reservoir performance and hydrocarbon recovery while reducing environmental impact. RCP Phase VI is the multidisciplinary, 4-D, 3-C study of a CO2 injection project in Vacuum field, a shallow shelf carbonate reservoir located on the Northwestern Shelf of the Permian Basin of West Texas and Southeastern New Mexico. The CO2 "huff-n-puff" in well Texaco CVU-97 at Vacuum Field and the repeated 3-D, 3-C seismic surveys were performed from October 30, 1995 to December 27, 1995. The initial 3-D, 3-C survey was acquired from October 28 through November 13. CO2 injection began November 13, 1995 and lasted until December 8, 1995. The "soak" period extended from December 8 through December 28, after which Texaco CVU-97 was returned to production. The second 3-D, 3-C survey was acquired during the "soak" period, from December 21 to December 28. The compressional data provides a measure of the bulk rock compressibility, rigidity and density, while shear wave data is sensitive to rigidity and density. The combined use of P-wave, S1 shear and S2 shear seismic data allow different views of the bulk rock properties in the subsurface. Our interpretation methodology strives to use these volumes to delineate spatial variations in the subsurface related to lithology, porosity, pore structure variations related to preferred permeability directions, and variations in pore fluid pressure and properties. Interval travel time comparisons between the P- and shear volumes are a robust and sensitive indicator of lithology, porosity and pore geometry, and the intensity of fracturing. In particular, the Ts1/Tp and Ts2/Tp measures show regions of lower Vp/Vs ratio in the southwest portion of the survey area. This portion of the reservoir produces less fluid with a lower water cut than do areas of the field exhibiting a higher Vp/Vs ratio. The Vp/Vs measure appears strongly correlated with the reservoir production characteristics. Anomalies between the two seismic surveys are readily visible on both the P-wave and S-wave seismic surveys. These anomalies arise in P-wave amplitude difference maps and variations in S-wave velocity anisotropy. An interpretation of these 4-D, 3-C seismic anomalies indicates that a CO2 miscible bank formed south of well CVU-97 near well CVU-200, and that the bank is contained by a permeability barrier near well CVU-200. P- wave and Si shear data are delineating reservoir zones where fluid compressibility and/or viscosity have changed due to CO2 injection and the subsequent migration of lighter hydrocarbons. The ability to sense bulk rock/fluid properties with 4-D, 3-C seismology enables characterization of the most important transport property of a reservoir, namely permeability. Because of the high volume resolution of the 4-D, 3-C seismic, we can monitor the sweep efficiency of a production process to see if reserves are bypassed by channeling around lower permeability parts of the reservoir and the rate at which the channeling occurs. In doing so, we can change production processes to sweep the reservoir more efficiently. P. 747