Browsing by Subject "reservoir characterization"

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A Robust Economic Technique for Crosswell Seismic Profiling
(1998) Hardage, Bob Adrian, 1939-; Simmons, James Layton, 1957-
This report is the final report describing work done under research project DEFG03-95ER14504, titled "A Robust Economic Technique for Crosswell Seismic Profiling," which was funded by the U.S. Department of Energy. The objective of this research program was to investigate a novel way to acquire crosswell tomographic data, that being to use a standard surface-positioned seismic energy source stationed in line with two wells that have downhole receiver arrays. This field technique differs from the traditional way that crosswell tomography is done, which requires that a downhole receiver array be in one well and that a downhole seismic source be in a second well. Several potential advantages can result from using a surface-based source rather than a downhole source to acquire crosswell tomographic data. Included in these advantages would be: (1) surface-based seismic sources emit more energy than do downhole seismic sources, thus receiver wells can be spaced at greater distances, (2) surface-based sources are more reliable than downhole sources and are more accessible if field repairs have to be done, and (3) downhole receivers can be deployed in a wider range of well conditions (cased hole, open hole, tubing, high-pressure lubricators, etc.) than can downhole sources, allowing crosswell tomography to be done in a wider variety of reservoirs. However, several potential shortcomings may occur if a surface-based source is used to acquire crosswell tomographic data. The principal concerns are: (1) source-to-receiver ray paths may not traverse the interwell space in a way that allows a robust tomographic inversion to be done, (2) errors in measuring arrival times may be too large for travel time inversion to be stable, and (3) the reduced bandwidths generated by surface-based sources may not allow some interwell targets to be detected.
An Investigation to Document Morrow Reservoirs That Can Be Better Detected with Seismic Shear (S) Waves Than With Compressional (P) Waves
(2001) Hardage, Bob Adrian, 1939-
Pennsylvanian-age Morrow reservoirs are a key component of a large fluvial-deltaic system that extends across portions of Colorado, Kansas, Oklahoma, and Texas. A problem that operators have to solve in some Morrow plays in this multi-state area is that many of the fluvial channels within the Morrow interval are invisible to seismic compressional (P) waves. This P-wave imaging problem forces operators in such situations to site infill, field-extension, and exploration wells without the aid of 3-D seismic technology. The objective of this project was to develop and demonstrate seismic technology that can improve drilling success in Morrow plays. Current P-wave technology commonly results in 8 percent of Morrow exploration wells not penetrating economic reservoir facies. Studies at Colorado School of Mines have shown that some of the Morrow channels that are elusive as P wave targets create robust shear (S) wave reflections (Rampton, 1995). These findings caused Isos Energy to conclude that exploration and field development of Morrow prospects should be done by a combination of P-wave and S-wave seismic imaging. To obtain expanded information about the P and S reflectivity of Morrow facies, 9-component vertical seismic profile (9-C VSP) data were recorded at three locations along the Morrow trend. These data were processed to create P and S images of Morrow stratigraphy. These images were then analyzed to determine if S waves offer an alternative to P waves, or perhaps even an advantage over P waves, in imaging Morrow reservoir targets. The study areas where these field demonstrations were done are defined in Figure 1. Well A was in Sherman County, Texas; well B in Clark County, Kansas; and well C in Cheyenne County, Colorado. Technology demonstrated at these sites can be applied over a wide geographical area and influence operators across the multi-state region spanned by Morrow channel plays. The scope of the investigation described here is significant on the basis of the geographical extent of Morrow reservoirs, the number of operators that can be affected, and the importance of Morrow hydrocarbon reserves to the nation's economy.
Analysis of Core Data-Kinder Morgan SU 228-4A
(2011) Lucia, F. Jerry
The Kinder Morgan SU 228-4A well, located in the south part of Sacroc field, Scurry County, Texas, was cored between the depths of 6,989 and 7,009 ft. The basic objective for this study is to describe the saturation profile in the bottom Sacroc reservoir. In other words, is there a transition zone or a residual oil zone (ROZ) at the base? Porosity and permeability were measured on core plugs, and a cross-plot of the results is illustrated in figure 1. The core was slabbed, and a basic core description prepared (fig. 2). The core is mainly a fossil wackestone with two thick beds and one thin bed of grain-dominated packstone (gdp) and one debris-flow interval. Some of the wackestone is highly stylolitized with associated tension gashes. Gdp beds are interpreted to be grain flows into deep-water muddy sediment. Thin sections were prepared from the ends of the core plugs; however, they are of poor quality and only a basic description was done to validate the core description.
Characterizing Marine Gas-Hydrate Reservoirs and Determining Mechanical Properties of Marine Gas-Hydrate Strata with 4-Component Ocean-Bottom-Cable Seismic Data
(2002) Hardage, Bob Adrian, 1939-; Backus, Milo M., 1932-; DeAngelo, M. V.
The research findings described in this report confirm that four-component ocean-bottom-cable (4-C OBC) seismic data provide valuable information about stratigraphy, lithofacies, and mechanical properties of sediments that cannot be extracted from conventional cable-towed P-wave marine seismic data. The key advantages of 4-C OBC data documented in this study that need to be considered for gas-hydrate applications are: 1. The ability to image inside gas-hydrate P-wave wipeout zones with C waves; 2. The increase in stratigraphic information that results from combining P-wave stratigraphic surfaces, seismic sequences, and seismic facies with C-wave stratigraphic surfaces, sequences, and facies; 3. The increased spatial resolution of shallow seafloor strata that results when the time coordinates of C-wave data are warped (transformed) to P-wave image time coordinating; 4. The mapping of lithofacies distributions using the lithofacies-sensitive velocity ratio, Vp/Vs; and 5. The estimation of the spatially averaged mechanical strength of ocean-floor strata using interval values of Vp and Vs to calculate elastic moduli. These technical advantages of 4-C OBC data will be discussed and illustrated in the main text of the report. Geologic and geophysical details developed during the investigation have been placed in appendices. The impact of the research findings can be understood by concentrating on the main text and ignoring the appendices. However, the appendices are important in that they document critical information and principles.
Cisco Carbonate Play: Palo Duro Basin
(American Association of Petroleum Geologists Southwest Section (AAPG SWS), 2023-05-06) Radjef, E.
Combining a New 3-D Seismic S-Wave Propagation Analysis for Remote Fracture Detection with a Robust Subsurface Microfracture-Based Verification Technique
(2004) Hardage, Bob Adrian, 1939-; Backus, Milo M., 1932-; DeAngelo, M. V.
Fractures within the producing reservoirs at McElroy Field could not be studied with the industry-provided 3C3D seismic data used as a cost-sharing contribution in this study. The signal-to-noise character of the converted-SY data across the targeted reservoirs in these contributed data was not adequate for interpreting azimuth-dependent data effects. After illustrating the low signal quality of the converted-SY data at McElroy Field, the seismic portion of this report abandons the McElroy study site and defers to 3C3D seismic data acquired across a different fractured carbonate reservoir system to illustrate how 3C3D seismic data can provide useful information about fracture systems. Using these latter data, we illustrate how fast-S and slow-S data effects can be analyzed in the prestack domain to recognize fracture azimuth, and then demonstrate how fast-S and slow-S data volumes can be analyzed in the poststack domain to estimate fracture intensity. In the geologic portion of the report, we analyze published regional stress data near McElroy Field and numerous formation multi-imager (FMI) logs acquired across McElroy to develop possible fracture models for the McElroy system. Regional stress data imply a fracture orientation different from the orientations observed in most of the FMI logs. This report culminates Phase 2 of the study, Combining a New 3-D Seismic S-Wave Propagation Analysis for Remote Fracture Detection with a Robust Subsurface Microfracture-Based Verification Technique. Phase 3 will not be initiated because wells were to be drilled in Phase 3 of the project to verify the validity of fracture-orientation maps and fracture-intensity maps produced in Phase 2. Such maps cannot be made across McElroy Field because of the limitations of the available 3C3D seismic data at the depth level of the reservoir target.
Estimation of Gas Permeabilities for the Maricopa Site, Arizona
(1998) Scanlon, Bridget R.; Angle, Edward S.; Liang, Jinhuo
Upward and downward migration of gases from waste-disposal facilities is a critical issue for low-level radioactive waste disposal. Gaseous radionuclides in low-level waste include H-3, C-14, and Rn-222. Upward migration of gases to the surface can be important, particularly during operation of the facility (Kozak and Olague, 1994). High tritium values (for example 1,100 TU at 24 m depth, 162 TU at 109 m depth) have been found adjacent to the Beatty site, Nevada, that cannot readily be explained by liquid or combined liquid and vapor transport (Prudic and Striegl, 1995; Striegl et al., 1996). Because disposal practices at Beatty varied in the past and included disposal of as much as 2,000 m3 of liquid waste, further research in tritium movement at Beatty is warranted. Transport mechanisms for gases include not only diffusion but also advection. Analysis of gas transport is important at many low-level waste disposal facilities as shown by the intensive program to monitor concentrations and concentration gradients of gaseous radionuclides proposed for the California low-level radioactive waste disposal facility (Harding Lawson & Assoc., 1991). Performance assessment calculations require information on parameters related to gas transport to predict long-term migration of gases in the subsurface. The purpose of this study is to evaluate different techniques of estimating gas transport parameters and monitoring subsurface gas migration. The objective of this study is to examine different techniques for evaluating gas permeability. Pneumatic pressure tests will be conducted to estimate vertical and horizontal air permeabilities at different levels. In addition, permeabilities will be calculated from atmospheric breathing data that will include evaluation of subsurface response to barometric pressure fluctuations. Computer simulations suggest that air from the surface can move several meters into the ground during typical barometric pressure cycles (Massmann and Farrier, 1992). Gas ports will be installed at different depths in two boreholes to evaluate atmospheric pumping. The results of this study will provide valuable information on subsurface gas transport processes and the various techniques to obtain data on parameters required for simulation of such processes. These data will be required for performance assessment calculations.
Geoscience/Engineering Characterization of the Interwell Environment in Carbonate Reservoirs Based on Outcrop Analogs, Permian Basin, West Texas and New Mexico - Petrophysical Characterization of the South Cowden Grayburg Reservoir, Ector County, Texas
(1997) Lucia, F. Jerry
Reservoir performance of the South Cowden Grayburg field suggests that only 21 percent of the original oil in place has been recovered. The purpose of this study is to construct a realistic reservoir model to be used to predict the location of the remaining mobile oil. Construction of reservoir models for fluid-flow simulation of carbonate reservoirs is difficult because they typically have complicated and unpredictable permeability patterns. Much of the difficulty results from the degree to which diagenetic overprinting masks depositional textures and patterns. For example, the task of constructing a reservoir model of a limestone reservoir that has undergone only cementation and compaction is easier than constructing a model of a karsted reservoir that has undergone cavern formation and collapse as well as cementation and compaction. The Permian-age carbonate-ramp reservoirs in the Permian Basin, West Texas, and New Mexico, are typically anhydritic dolomitized limestone. Because the dolomitization occurred soon after deposition, depositional fabrics and patterns are often retained, and a reservoir model can be constructed using depositional concepts. Recent studies of the San Andres outcrop in the Guadalupe Mountains (Kerans and others, 1994; Grant and others, 1994) and the Seminole San Andres reservoir in the Permian Basin (Lucia and others, 1995) illustrate how depositional fabric and patterns can be used to construct a reservoir model when depositional features are retained.
Hydrogeological and Geomechanical Evaluation of a Shallow Hydraulic Fracture at the Devine Fracture Pilot Site, Medina County, Texas
(55th U.S. Rock Mechanics/Geomechanics Symposium, 2021-06-18) Haddad, Mahdi; Ahmadian, Mohsen; Ge, Jun; Hosseini, Seyyed; Nicot, J.-P.; Ambrose, William
UT-Austin’s Devine Fracture Pilot Site (DFPS), 50 miles southwest of San Antonio, Texas, has been targeted for a comprehensive, multidisciplinary development of fracture diagnostics techniques cross-validated by ground-truth data acquisition near a recently created, 175-ft-deep, horizontal hydraulic fracture. To evaluate the fracture-diagnostic techniques at this site, we attempted to develop hydrogeological and geomechanical models on the basis of bottomhole-pressure measurements during injection tests with a predefined volumetric flow-rate profile, resembling a diagnostic fracture injection test (DFIT). History-matching efforts using a simplified layer-cake hydrogeological model resulted in the field-scale formation permeability of 9.87×10-15-m2 (10-mD) and Darcy-scale fracture permeability. Analysis of bottomhole pressure and injection-rate history showed that (1) the preexisting horizontal fracture was closed adjacent to the injection well and (2) the initial pump-pressure increase at a negligible volumetric injection rate led to near-well fracture reopening, conductivity increase, and abrupt injection-rate increase. To overcome hydrogeological-model limitations of predicting fracture reopening throughout injection, we extended the modeling to a finite-element, poroelastic analysis of horizontal-fracture growth using a cohesive-zone model. Using this fracture-reopening model, we were able to match the transient-pressure response during the entire experiment by adjusting the hydromechanical properties. The current study lays the foundation for future work that our team will be performing at this well-characterized fracture site.
Integrated Geological and Engineering Characterization of the Fullerton Clear Fork Field, Andrews County, Texas
(2005) Ruppel, Stephen C.
The elements of the research carried out on Fullerton field are presented in six chapters. In the first chapter, Ruppel and Jones describe the depositional facies and sequence stratigraphy of the reservoir based on integrated study of outcrops and subsurface data from Fullerton field. They also describe the key steps in using outcrop- and core-based facies-stacking patterns and wireline log response relationships to develop a robust reservoir framework having sufficient resolution and accuracy to form the basis for reservoir modeling and simulation. In addition, they document the products of diagenesis and using three-dimensional relationships of geochemical and porosity distribution data suggest models for dolomitization and porosity development. Finally, they describe the use of two modern techniques for improved reservoir imaging: (1) borehole imaging logs for improved definition of facies distribution and cycles, and (2) 3D seismic data, to better define the distribution of reservoir porosity.
Integrated Synthesis of the Permian Basin: Data Models for Recovering Existing and Undiscovered Oil Resources from the Largest Oil-Bearing Basin the U.S.
(2009) Ruppel, Stephen C.
The Permian Basin stands as the richest hydrocarbon basin in the United States. Over time, it has yielded nearly 30 billion barrels of oil from an estimated original oil in place of 106 billion barrels, representing nearly one-fourth of the total discovered oil resource in the United States. However, current annual production rates have seen a significant decline, plummeting from the peak of 665 million barrels per year in the early 1970s to less than 300 million barrels per year, barely half the peak production. Despite this decline, the Permian Basin still retains a substantial volume of oil. Studies conducted by the Bureau of Economic Geology (Tyler and Banta, 1989) estimate that existing reservoirs hold up to 30 billion barrels of mobile oil and 54 billion barrels of residual oil, which could be accessed through tertiary oil recovery technologies. Moreover, these studies suggest that an additional 3.5 billion barrels of oil and NGL resources are yet to be discovered in the basin. However, one significant obstacle hindering the revitalization of interest and commitment to tapping into this remaining resource has been the lack of up-to-date, fully integrated, and synthesized data sets on various aspects of the Permian Basin. These include the stratigraphic and depositional framework, facies architecture, reservoir properties and characteristics, play boundaries, and applicable reservoir models. The aim of this project was to address this need by creating and distributing a synthesis of Permian Basin data in readily accessible and usable digital formats.
Lacustrine Shale Gas Reservoir Characterization in the Yanchang Formation by Integrated Geological Facies, Geochemistry, Chemostratigraphy, SEM Pore Imaging, Petrography, and Geophysics
(2016) Zhang, T.; Zeng, Hongliu
During the past 2 years, researchers from the Bureau of Economic Geology (BEG) and Yanchang Petroleum Group (Yanchang) have worked closely to conduct an integrated research project titled "Lacustrine Shale Gas Reservoir Characterization in the Yanchang Formation by Integrated Geological Facies, Geochemistry, Chemostratigraphy, SEM Pore Imaging, Petrography, and Geophysics." On November 8, 2013, a team of executives, led by Dr. Xiangzeng Wang, Vice President and Chief Geologist of the Shaanxi Yanchang Petroleum Company, Ltd., visited the Bureau of Economic Geology (BEG) to sign a 2-year agreement for the project. Project objectives were to provide integrated studies of geological facies, hydrocarbon geochemical characterization, chemical stratigraphy, SEM pore imaging, and detailed petrographic study. These aspects were to be integrated to yield broader concepts about hydrocarbon generation and storage and the distribution of geological facies and fundamental rock attributes. Additionally, models were to be developed for evaluating sweet spots for shale gas that can be applied in making economic decisions. All project tasks have been on schedule, and collaboration between the BEG and Yanchang Petroleum has been very successful. A team of executives, led by Dr. Xiangzeng Wang, Vice President of the Shaanxi Yanchang Petroleum Company, Ltd., traveled to Austin twice during the research project for midterm and final project reviews. The Research Institute of Shaanxi Yanchang Petroleum sent five researchers to the BEG who were involved in specific research tasks relevant to their backgrounds and interests. A team of BEG researchers led by Dr. Scott Tinker, BEG Director; Eric Potter, BEG Energy Program Manager; and Drs. Tongwei Zhang and Hongliu Zeng, Principal Investigators (PIs) of the research project, traveled to Xi'an three times to conduct core description, data collection, and sampling. A field trip to Yanchang Formation outcrops took place during one visit, and presentations were given at the year-1 project review meeting and at the final project review meeting. BEG researchers also conducted a series of technology-transfer workshops at The Research Institute of Shaanxi Yanchang Petroleum. A large amount of new data collection has been conducted during the 2 years of the project. More than 60,000 raw data for 23 new analytical items are summarized in Table 1: 15 GB of petrographic data, 25 GB of SEM pore imaging data, and 216 core pictures were collected. Twenty oral presentations, nine poster presentations, three reports, and five abstracts were given in annual and final project review meetings (Table 2). Key results will be published in Interpretation, in a Special Section titled "Lacustrine shale characterization and shale resource potential in Ordos Basin, China," in May 2017.
Marcellus Shale BEG Natural Fracture Project Final Report
(2012) Gale, Julia F. W.; Laubach, Stephen E. (Stephen Ernest), 1955-
Operators in the Marcellus Shale gas play are aware of the importance of natural fractures, and there has been substantial work on the fracture systems in core and outcrop in the large region covered by this play (Eastern Shale Gas Project reports; Evans, 1980, 1994, 1995; Engelder et al., 2009 and references therein; Lash and Engelder, 2005, 2007, 2009). The most common fractures documented by these authors in core and outcrop are subvertical opening-mode fractures that are broadly strike parallel (J1) or cross-fold joints (J2). Evans (1995) also found strike-parallel veins that post-date the J2 set, and Lash and Engelder (2005) describe bitumen-filled microcracks developed during catagenesis. Gale and Holder (2010) found in a study of several gas-shales that narrow, sealed, subvertical fractures are typically present in most shale cores. In shale-gas plays that are produced using hydraulic fracturing stimulation, these fractures are nevertheless important because of their interaction with hydraulic treatment fractures (Gale et al., 2007). At the scale of hydraulic fracture stimulation, natural fracture patterns and in situ stress can be highly variable, even though a broad tectonic pattern may be consistent over hundreds of miles. Thus, site-specific evaluation of the natural fractures and in situ stress is necessary. Open fractures are observed in a few cases in core. Fracture-size scaling, coupled with a fracture-size control over sealing cementation and a subcritical growth mechanism that favors clustering, suggests that open fractures are likely to be concentrated in clusters spaced hundreds of feet apart (Gale, 2002; Gale et al., 2007). Our goal for this project is to characterize the fractures and identify the characteristic spatial arrangement of fractures, including potential clusters of large fractures. Our emphasis is on characterizing, quantifying, and modeling fractures that have grown in the subsurface in a chemically reactive environment through a combination of observation at a range of scales, detailed petrographic and microstructural observation of cement fills, and geomechanical modeling (cf. Marrett et al., 1999; Gale, 2002; Laubach 1997, 2003; Olson, 2004). Large natural fractures, open or sealed, are typically sparsely sampled in core or image logs. Yet these are the fractures that would have the most effect in augmenting gas flow or influencing the growth of hydraulic fractures. Our approach overcomes the sampling problem by use of fracture size and spatial scaling analysis coupled with geomechanical modeling. That is, we may make predictions about their attributes without sampling them. Fracture morphology, orientation, spatial organization, and cementation were analyzed using datasets from the project well-experiment area in SW Pennsylvania. We added a dataset from a field area to evaluate the use of outcrop fracture data in reservoir characterization in the Marcellus, thus expanding the relevance of the study beyond the well-experiment area in SW Pennsylvania.
Opportunities for Additional Recovery in University Lands Reservoirs -- Characterization of University Lands Reservoirs, Final Report
(1990) Tyler, N.; Bebout, Don G.; Garrett, C. M., Jr.; Guevara, Edgar H.; Hocott, Claude R.; Holtz, Mark H.; Hovorka, Susan D.; Kerans, C. (Charles), 1954-
In 1984, The University of Texas System funded a Bureau of Economic Geology project, "Characterization of University Lands Reservoirs," to assess in detail the potential for incremental recovery of oil from University Lands reservoirs by extended conventional methods. The objectives of the 5-year project were to quantify the volumes of unrecovered mobile oil remaining in reservoirs on University Lands, to determine whether the specific location of the unrecovered mobile oil could be delineated through integrated geoscience characterization of individual reservoirs, and to develop strategies to optimize recovery of this resource. Unrecovered mobile oil is mobile at reservoir conditions but is prevented from migrating to the wellbore by geologic complexities or heterogeneities. This final report describes results of the 5 years of research conducted on University Lands reservoirs. One hundred and one reservoirs, each of which has produced more than 1 million stock tank barrels (MMSTB) of oil, were included in a resource assessment and play analysis undertaken (1) to determine the volumes and distribution of all components of the University Lands resource base and (2) to select reservoirs for detailed analysis. These reservoirs collectively contained 7.25 billion barrels (BSTB) of oil at discovery, have produced 1.5 BSTB, and contain 200 MMSTB of reserves. Ultimate recovery at implemented technology is projected to be 24 percent of the original oil in place; thus, 5.5 BSTB of oil will remain after recovery of existing reserves. Unrecovered mobile oil (exclusive of reserves) amounts to 2.2 BSTB, and immobile, or residual, oil totals 3.3 BSTB.
Play Analysis and Digital Portfoilio of Major Oil Reservoirs in the Permian Basin
(2003) Dutton, Shirley P.
This 2-year PUMP project, now well underway, has made significant progress toward all goals and objectives. This report describes the work accomplished on the project during the first year. The target of the project is the Permian Basin of West Texas and southeast New Mexico (fig. 1), the largest petroleum-producing basin in the United States. The Permian Basin produced 18 percent of the total U.S. oil production in 1999, and it contains an estimated 23 percent of the proved oil reserves in the United States (EIA, 2000). Moreover, this region has the biggest potential for additional oil production in the country, containing 29 percent of estimated future oil reserve growth (Root and others, 1995). More than in any other region, increased use of preferred management practices in Permian Basin oil fields will have a substantial impact on domestic production. Production in the Permian Basin occurs from Paleozoic reservoirs, from Ordovician through Permian (fig. 2). Original oil in place (OOIP) in the Texas part of the basin alone was about 106 billion barrels (Bbbl) of oil (EIA, 2000). After reaching a peak production of more than 665 million barrels (MMbbl) per year in the early 1970s, Permian Basin oil production has continuously fallen. By 1999, production had fallen to less than 300 MMbbl, or half its peak production. Despite the continuing fall in production, the Permian Basin still holds a significant volume of oil. Although about 30 Bbbl of oil has been produced to date, this production represents only about 28 percent of the OOIP. Of the huge remaining resource in the basin, as much as 30 Bbbl of mobile oil remains as a target for improved technology and recovery strategies (Tyler and Banta, 1989).
Play Analysis and Digital Portfolio of Major Oil Reservoirs in the Permian Basin: Application and Transfer of Advanced Geological and Engineering Technologies for Incremental Production Opportunities
(2004) Dutton, Shirley P.; Kim, Eugene M.; Broadhead, Ronald F.
The Permian Basin of west Texas and southeast New Mexico has produced over 30 billion barrels (4.77 x 10^9 m³) of oil through 2000, most of it from 1,339 reservoirs having individual cumulative production greater than 1 million barrels (1.59 x 10^5 m³). These significant-sized reservoirs are the focus of this report. Thirty-two Permian Basin oil plays were defined, and each of the 1,339 significant-sized reservoirs was assigned to a play. The reservoirs were mapped and compiled in a Geographic Information System (GIS) by play. Associated reservoir information within linked data tables includes Railroad Commission of Texas reservoir number and district (Texas only), official field and reservoir name, year reservoir was discovered, depth to top of the reservoir, production in 2000, and cumulative production through 2000. Some tables also list subplays. Play boundaries were drawn for each play; the boundaries include areas where fields in that play occur but have less than 1 million barrels (1.59 x 10^5 m³) of cumulative production. This report contains a summary description of each play, including key reservoir characteristics and successful reservoir management practices that have been used in the play. The CD accompanying the report contains a PDF version of the report, the GIS project, PDF maps of all plays, and digital data files. Oil production from the reservoirs in the Permian Basin having cumulative production greater than 1 million barrels (1.59 x 10^5 m³) was 301.4 million barrels (4.79 x 10^7 m³) in 2000. Cumulative Permian Basin production through 2000 from these significant-sized reservoirs was 28.9 billion barrels (4.59 x 10^9 m³). The top four plays in cumulative production are the Northwest Shelf San Andres Platform Carbonate play (3.97 billion barrels [6.31 x 10^8 m³]), the Leonard Restricted Platform Carbonate play (3.30 billion barrels [5.25 x 10^8 mÂ³]), the Pennsylvanian and Lower Permian Horseshoe Atoll Carbonate play (2.70 billion barrels [4.29 x 10^8 m³]), and the San Andres Platform Carbonate play (2.15 billion barrels [3.42 x 10^8 m³]).
RCRL Studies of Thief Zones in SACROC Field
(2012) Lucia, F. Jerry
Geologic models of the northern platform of Sacroc have been constructed over several years (2001–present) by the Reservoir Characterization Research Laboratory (RCRL). These models show a complex stratigraphy of deposition, exposure (diagenesis), and erosion. Canyon units were deposited as depositional cycles, and the latest Canyon cycles have been heavily eroded. The Cisco units are composed of debris flows, biohermal buildups, and grain-dominated units representing many significant sea-level changes, culminating in a major exposure event before being engulfed in carbonate muds of Wolfcamp age. Geologic models have been converted to petrophysical models by RCRL using the rock fabric method. Porosity-permeability transforms have been defined for each stratigraphic unit using core data and thin-section analyses. Geologic models have been converted to porosity and permeability models using these transforms. Kinder Morgan has initiated a CO2 flood in the northern platform area. The company's injection program has uncovered numerous intervals in which the rate of injection is significantly higher than expected from the petrophysical model. These intervals are referred to as void space conduits by Kinder Morgan and as thief zones in this report. The problem facing Kinder Morgan is that the large volume of injected fluid taken by thief zones significantly decreases the volume of remaining-oil saturation contacted by injected fluids, resulting in poor recovery. This report summarizes efforts to explain the geological and petrophysical nature of these thief zones through an exhaustive study of core and log data from well 37-11. Thief zones are defined as having significantly higher flow rates than expected from matrix properties. At Sacroc, these zones are located by injection profiles, and the injection profile from 37-11 shows high variability in injection volume. Using core data, we calculated kh values for each perforated interval, as well for each injection and no-injection interval within each set of perforations. A positive relationship between kh and water injection is assumed. Unfortunately, in 37-11 only a polymer injection profile was available for this study. A positive relationship between kh and polymer injection is probably true as well.
Shear Wave Seismic Study Comparing 9C3D SV and SH Images with 3C3D C-Wave Images
(2004) Beecherl, John; Hardage, Bob Adrian, 1939-
The objective of this study was to compare the relative merits of shear-wave (S-wave) seismic data acquired with nine-component (9-C) technology and with three-component (3-C) technology. The original proposal was written as if the investigation would be restricted to a single 9-C seismic survey in southwest Kansas (the Ashland survey), on the basis of the assumption that both 9-C and 3-C S-wave images could be created from that one dataset. The Ashland survey was designed as a 9-C seismic program. We found that although the acquisition geometry was adequate for 9-C data analysis, the source-receiver geometry did not allow 3-C data to be extracted on an equitable and competitive basis with 9-C data. To do a fair assessment of the relative value of 9-C and 3-C seismic S-wave data, we expanded the study beyond the Ashland survey and included multicomponent seismic data from surveys done in a variety of basins. These additional data were made available through the Bureau of Economic Geology, our research subcontractor. Bureau scientists have added theoretical analyses to this report that provide valuable insights into several key distinctions between 9-C and 3-C seismic data. These theoretical considerations about distinctions between 3-C and 9-C S-wave data are presented first, followed by a discussion of differences between processing 9-C common-midpoint data and 3-C common-conversion-point data. Examples of 9-C and 3-C data are illustrated and discussed in the last part of the report. The key findings of this study are that each S-wave mode (SH-SH, SV-SV, or PSV) involves a different subsurface illumination pattern and a different reflectivity behavior and that each mode senses a different Earth fabric along its propagation path because of the unique orientation of its particle-displacement vector. As a result of the distinct orientation of each mode's particle-displacement vector, one mode may react to a critical geologic condition in a more optimal way than do the other modes. A conclusion of the study is that 9-C seismic data contain more rock and fluid information and more sequence and facies information than do 3-C seismic data; 9-C data should therefore be acquired in multicomponent seismic programs whenever possible.
STARR Progress Report
(2014) Ambrose, William A.
The State of Texas Advanced Resource Recovery program (STARR) has achieved its primary goal of boosting severance tax revenue for the State through research projects aimed at promoting the drilling of profitable oil and gas wells. Currently, the Bureau of Economic Geology (BEG) receives state funding to conduct research that aids oil and gas operators in either establishing new production or enhancing existing production across Texas. STARR operates under the mandate of being revenue neutral, meaning that the revenue generated from STARR projects must at least match the funds allocated by the Legislature. This progress report provides a detailed summary of the accomplishments of Project STARR over the past two years, from September 1, 2012, to August 31, 2014. According to the methodology approved by the State of Texas Comptroller's office, the credit attributed to the STARR program for the 2012—2014 biennium amounts to $140,766,560 (see table 1). With total income of $9 million over the current biennium, STARR demonstrates a positive revenue impact of 15.6. To date, the STARR program has concluded or is actively engaged in over 60 field (reservoir characterization) studies (see figs. 1 and 2). Figure 2 highlights 23 significant new reservoir characterization studies conducted during the 2012—2014 biennium. Additionally, STARR has initiated 8 new regional studies, encompassing areas such as the Eaglebine trend in southeastern Texas Gulf Coast, as well as the Cline Shale and Wolfcamp and Spraberry Formations in the Permian Basin of West Texas (see fig. 3). Furthermore, STARR includes eight supplementary program elements that complement the Oil and Gas Resources program. Each of these elements targets research relevant to critical economic opportunities or challenges in Texas concerning natural resources or geological conditions. These elements encompass geothermal resources, water-related issues affecting the Texas economy, mineral and earth resources, geological hazards, energy economics, baseline mapping for oil spill response, economic implications of environmental flows, and analysis of water-energy nexus issues.
Subsurface Gas Shale Samples of the Upper Devonian and Lower Mississippian woodford Shale, Core Sampling for Measured Vitrinite Reflectance Determination
(2013) Hentz, Tucker F.; Breton, Caroline L.; Ruppel, Stephen C.
This report summarizes activities carried out by the Bureau of Economic Geology (BEG) during fiscal year (FY) 2012 for the National Coal Resources Data System State Cooperative Program (NCRDS project). In a continuation of the sampling strategy for measured vitrinite-reflectance (Ro) determination initiated 4 years ago (Hentz and others, 2009) and conducted during the following three years (Hentz and others, 2010, 2011, 2012), this report provides a collection of oil- and gas-shale samples from the oil- and gas-productive Upper Devonian Woodford Shale of the Permian Basin in Texas and New Mexico (Fig. 1). In FY2009, 2010, and 2011, we provided samples of the Eagle Ford Shale from the San Marcos Arch and Maverick Basin areas, samples of the deeper Pearsall Formation from the Maverick Basin of the eastern part of Texas, and samples of the Smithwick Shale from the Fort Worth Basin of north Texas, respectively. As specified in our work plan for FY2010 through 2014 (Hentz, 2010), this year we have provided samples of the productive Upper Devonian Woodford Shale in the Permian Basin of West Texas and southeastern New Mexico.