Scott W. Tinker

Building the 3-D Jigsaw Puzzle: Applications of Sequence Stratigraphy to 3-D Reservoir Characterization, Permian Basin

Reservoir characterization involves the quantification, integration, reduction, and analysis of geological, petrophysical, seismic, and engineering data. This is no small task. A principal goal of reservoir characterization is to derive a spatial understanding of interwell heterogeneity. Traditionally, geologic attempts to characterize interwell heterogeneity have been done using hand-drawn or computer-generated two-dimensional (2-D) maps and cross sections. Results can be improved dramatically using three-dimensional (3-D) interpretation and analysis techniques. Three-dimensional reservoir characterization requires the same input data used in 2-D approaches, and the cost is equal to, and commonly lower than, traditional 2-D methods. The product of 3-D reservoir characterization is a 3-D reservoir model. The language used to communicate the results of a 3-D reservoir model is visualization; i.e., visual images of numerical data. All of the available log and core data in a model area are incorporated in a 3-D model, but the data are depicted as colored cells rather than as log traces. The integrity of the 3-D reservoir model is largely a function of the stratigraphic framework. Interpreting the correct stratigraphic framework for a subsurface reservoir is the most difficult and creative part of the 3-D modeling process. Sequence and seismic str tigraphic interpretation provide the best stratigraphic framework for 3-D reservoir modeling. The purpose of this paper is to discuss the process of 3-D deterministic reservoir modeling and to illustrate the advantages of using a sequence stratigraphic framework in 3-D modeling. Mixed carbonate and siliciclastic sediment outcrop and subsurface examples from the Permian basin of west Texas and New Mexico will be used as examples, but the concepts and techniques can be applied to reservoirs of any age. Three-dimensional reservoir modeling results in an improved geologic interpretation; provides a means of integrating geological, petrophysical, geophysical, and engineering data; and allows for immediate model updates as new data are acquired. As a result of 3-D reservoir characterization, reservoir management decisions, data quality control, volumetric calculations, numerical sim lation input, and communication between disciplines are improved.

Log-derived thickness and porosity of the Barnett Shale, Fort Worth basin, Texas: Implications for assessment of gas shale resources

This study estimates reservoir quality and free-gas storage capacity of the Barnett Shale in the main natural-gas producing area of the Fort Worth basin by mapping log-derived thickness, porosity, and porosity-feet. In the Barnett Shale, the density porosity (DPHI) log curve is a very useful tool to quantitatively assess shale gas resources, and gamma-ray (GR) and neutron porosity log curves are important factors in identifying the shale gas reservoir. The key data were digital logs from 146 wells selected based on the availability of GR and density log curves, log quality, and good spatial distribution. The Barnett Shale pay zone was determined on the basis of (1) DPHI >5%, (2) high GR values (commonly >∼90 API units), (3) no significant intercalated carbonate-rich beds, and (4) individual pay zones being thick enough to be commercially successful for the current design of horizontal wells. In the study area, the Barnett Shale pay zone varies from about 165 ft (50 m) to 420 ft (128 m) in thickness (H). Average DPHI values of individual wells for the pay zone vary from 8.5 to 14.0%. Porosity-feet maps of the pay zone show that areas of high DPHI-H values coincide with areas of high natural gas production, indicating that log-derived porosity-feet maps are a good method for evaluating reservoir quality and assessing natural gas resource in the Barnett Shale play. A limitation to this method is shown in the northwestern corner of the study area, which is located in the liquids-rich window with lower thermal maturity.

Regional assessment of the Eagle Ford Group of South Texas, USA: Insights from lithology, pore volume, water saturation, organic richness, and productivity correlations

AbstractA comprehensive regional investigation of the Eagle Ford Shale linking productivity to porosity-thickness (PHIH), lithology (Vclay), pore volume (PHIT), organic matter (TOC), and water-saturation (SW) variations has not been presented to date. Therefore, isopach maps across the Eagle Ford Shale play west of the San Marcos Arch were constructed using thickness and log-calculated attributes such as TOC, Vclay, SW, and porosity to identify sweet spots and spatial distribution of these geologic characteristics that influence productivity in shale plays. The Upper Cretaceous Eagle Ford Shale in South Texas is an organic-rich, calcareous mudrock deposited during a second-order transgression of global sea level on a carbonate-dominated shelf updip from the older Sligo and Edwards (Stuart City) reef margins. Lithology and organic-matter deposition were controlled by fluvial input from the Woodbine delta in the northeast, upwelling along the Cretaceous shelf edge, and volcanic and clastic input from distan...

Log-derived thickness and porosity of the Barnett Shale, Fort Worth basin, Texas

This study estimates reservoir quality and free-gas storage capacity of the Barnett Shale in the main natural-gas producing area of the Fort Worth basin by mapping log-derived thickness, porosity, and porosity-feet. In the Barnett Shale, the density porosity (DPHI) log curve is a very useful tool to quantitatively assess shale gas resources, and gamma-ray (GR) and neutron porosity log curves are important factors in identifying the shale gas reservoir. The key data were digital logs from 146 wells selected based on the availability of GR and density log curves, log quality, and good spatial distribution. The Barnett Shale pay zone was determined on the basis of (1) DPHI >5%, (2) high GR values (commonly >∼90 API units), (3) no significant intercalated carbonate-rich beds, and (4) individual pay zones being thick enough to be commercially successful for the current design of horizontal wells. In the study area, the Barnett Shale pay zone varies from about 165 ft (50 m) to 420 ft (128 m) in thickness (H). Average DPHI values of individual wells for the pay zone vary from 8.5 to 14.0%. Porosity-feet maps of the pay zone show that areas of high DPHI-H values coincide with areas of high natural gas production, indicating that log-derived porosity-feet maps are a good method for evaluating reservoir quality and assessing natural gas resource in the Barnett Shale play. A limitation to this method is shown in the northwestern corner of the study area, which is located in the liquids-rich window with lower thermal maturity.

Operation of a Public Geologic Core and Sample Repository in Houston, Texas

The Bureau of Economic Geology (BEG), building on an initial gift from BP, and with the continuing support of the Department of Energy (DOE), has established the first regional core and sample research center in Houston, Texas. The Houston Research Center (HRC) provides a state-of-the-art core layout facility, two fully equipped meeting rooms, and a comprehensive technical library, all available for public use. This document summarizes the activities, upkeep, increase in staff, and public impact on industry and the community that were accomplished at the Houston Research Center during its first two years of operation.

OPERATION OF A PUBLIC GEOLOGIC CORE AND SAMPLE REPOSITORY IN HOUSTON TEXAS

In the spring of 2002, the Department of Energy provided an initial 1-year grant to the Bureau of Economic Geology (BEG) at The University of Texas at Austin (UT). The grant covered the one-year operational expenses of a worldclass core and cuttings facility located in Houston, Texas, that BP America donated to the BEG. The DOE investment of

3-D Reservoir Characterization for Improved Reservoir Management

300,000, matched by a

Sequence Stratigraphy and Characterization of Carbonate Reservoirs

75,000 UT contribution, provided critical first-year funds that were heavily leveraged by the BP gift of

Shelf-To-Basin Facies Distributions and Sequence Stratigraphy of a Steep-Rimmed Carbonate Margin: Capitan Depositional System, Mckittrick Canyon, New Mexico and Texas

7.0 million in facilities and cash. DOE also provided a one-month extension and grant of

Well economics across ten tiers in low and high Btu (British thermal unit) areas, Barnett Shale, Texas

30,000 for the month of May 2003. A 5-year plan to grow a permanent endowment in order to manage the facility in perpetuity is well under way and on schedule. The facility, named the Houston Research Center, represents an ideal model for a strong Federal, university, and private partnership to accomplish a national good. This report summarizes the activities supported by the initial DOE grant during the first 13 months of operation and provides insight into the activities and needs of the facility in the second year of operation.