Comparative Engineering Field Studies and Gas Resources of the Travis Peak Formation, East Texas Basin

Data from eight fields producing from the Travis Peak Formation in the eastern East Texas Basin were used to define key engineering parameters for each field and to develop resource-reserve estimates. Field-average porosities range from 8 to 11 percent, and the median permeability for 191 wells is 0.088 md; field-average permeability ranges from 0.006 to 0.1 md. Gas productivity generally increases from south to north across the area studied with changes in the reservoir drive mechanism. Gas in place in the Travis Peak of the East Texas Basin is estimated to be 19.5 Tcf, assuming 12 percent of the area of the basin is ultimately productive.Bureau of Economic Geolog

Safety-based Injection Strategy for Carbon Dioxide Geological Sequestration in a Deep Saline Aquifer with Complex Sandstone-shale Sequences: A Case Study from Taiwan

AbstractThe purpose of this study was to decide the best injection strategy for CO2 geo-sequestration in a deep saline aquifer with complex bedded sandstone-shale sequences. The best injection strategy is decided based on the estimates of the safety index (SFI). Numerical simulation method was used in this study. The major conclusions from this study are: (1) Safe trapping mechanisms contribute to a lower risk of CO2 leakage by trapping CO2 as immobile blobs or changing the phase of CO2 from supercritical phase to aqueous, ionic, and mineral phases in the post-injection period. (2) For an aquifer with complex sandstone-shale sequences, the best injection strategy should be decided by the results of risk evaluation and the SFI estimation. (3) The well location affected the injection strategy. The risk of CO2 leakage was lower using a down-dip injection well than an up-dip well. (4) The best strategy for this case study was to use the down-dip well to inject CO2 into the bottom sandstone layer. The SFI for this scenario reached 0.99 at the storage time of 1000 years, which meant that the probability of CO2 leakage occurring was nearly zero

Exploration and Production Program for Locating and Producing Prospective Aquifers Containing Solution Gas and Free Gas- Texas Gulf Coast

This project was designed to locate and evaluate a prospective watered-out gas reservoir in the Texas Gulf Coast inland area. The prospective reservoir was to be suitable for application of enhanced gas recovery methods for producing the unconventional gas that remained in the reservoir after primary gas production ceased. A test well site would be located within a favorable prospect area. Previous work conducted by the Bureau of Economic Geology for the U.S. Department of Energy focused on the selection of test well sites in the Frio Formation and Wilcox Group of the Texas Gulf Coast. These studies were intended to make use of thermal energy, mechanical energy, and gas dissolved in formation waters by producing large volumes of hot water from deep, highly pressured formations. In this project, funded by the Gas Research Institute, interest shifted to locating prospective reservoirs containing significant quantities of free gas in addition to the gas dissolved in the water. Abandoned watered-out reservoirs and wet zones where large amounts of water must be produced to obtain the gas by co-production were identified. The present project, funded by the Gas Research Institute, shows their continuing interest in unconventional gas and in developing prospects that are favorable for co-production of gas and water from watered-out gas reservoirs. Guidelines used to screen gas fields along the Texas Gulf Coast resulted in the selection of the Port Arthur field, Jefferson County, Texas, as a suitable prospect for application of enhanced gas recovery methods. Several watered-out gas sandstones in this field have excellent reservoir characteristics. All 18 wells in the field have been plugged and abandoned by previous operators; hence, leasing problems should be simplified. Abundant shallow Miocene sands in the area are available for salt-water disposal. The "C" reservoir interval, located at an average depth of 11,130 ft, received the most extensive evaluation. Predicted gas recovery by natural flow is 5.1 billion standard cubic feet as reservoir pressure declines from 6,632 to 4,309 psig. A sample economic analysis showed a net present worth of $968,000 and a payout time of 3 years. This prospect has the potential to be economically profitable in addition to being a good research and development test for evaluating co-production techniques. It is recommended that a co-production well be drilled and tested on a site near the Meredith No. 2 Doornbos (Well 14).Bureau of Economic Geolog

Exploration and Production Program for Locating and Producing Prospective Aquifers Containing Solution Gas and Free Gas Texas Gulf Coast - Annual Report

The Port Arthur field in Jefferson County, Texas, has been identified as a promising candidate for secondary enhanced gas recovery methods due to its multiple watered-out gas reservoirs, thick aquifers, and gas stringer sandstones at depths ranging from 10,850 to 11,700 feet. Sidewall core data indicate an average porosity of 30 percent and average permeability of 60 millidarcies (md). Reservoir simulation studies suggest that approximately 3.91 billion standard cubic feet of unconventional gas can be recovered through natural flow from the 11 C" sandstone over a 10-year period, by reducing reservoir pressure from 6,500 to 4,018 pounds per square inch gauge (psig). The break-even gas price is estimated to be $3.45 per thousand standard cubic feet for a 15-percent rate of return. Additional gas recovery opportunities exist through co-production from other sandstones and by further reducing reservoir pressure using artificial lift methods. It is recommended to drill a design test well to a depth of 11,650 feet at a location near the Meredith No. 2 Doornbos (Well No. 14). This test well will help evaluate the feasibility and effectiveness of secondary enhanced gas recovery techniques in the Port Arthur field.Bureau of Economic Geolog

Geologic Analysis of Primary and Secondary Tight Gas Sand Objectives, Phase C

Previous assessments of blanket-geometry tight gas sandstones led to the selection of the Travis Peak Formation of the East Texas and North Louisiana Basins and the Corcoran and Cozzette Sandstones of the Piceance Creek Basin as major research objectives. The anticipated outcomes of this study include increased availability of tight gas resources and advancements in technology with high transferability. The work reported here encompasses all aspects of the depositional systems and reservoir geology of these units as fundamental components of resource characterization, with an emphasis on understanding controls on reservoir facies distribution and their relevance to low-permeability reservoir development. Six lithofacies of the Travis Peak (Hosston) Formation in East Texas and North Louisiana have been identified using electric logs. These facies comprise sand-rich fluvial-deltaic, silt-rich delta-front, clay- and carbonate-rich shelf, carbonate reef, and clay-rich open marine facies. The most well-developed facies in the East Texas area are the fluvial-deltaic and delta-front facies. Travis Peak rocks from the Clayton Williams #11 Sam Hughes well, Panola County, Texas, were primarily deposited in a fluvial environment within a coastal plain setting. Porosity and permeability control in the clean sandstones are primarily attributed to quartz overgrowths, chlorite cement, and solid organic matter, with approximately half of the remaining porosity being secondary, resulting from framework grain dissolution. Studies of Travis Peak gas production at Pinehill Southeast and Percy-Wheeler fields indicate an average permeability-thickness product of about 10 md-ft, with a range of 0.7 to 35 md-ft, indicating dry gas reservoirs. Well logs, core, and mud logs from Chapel Hill field in Smith County, Texas, were examined in preparation for a complete cooperative well program in the ARCO #11 Phillips well on the western margin of that field. Field studies of Corcoran-Cozzette Sandstones near Grand Junction, Colorado, suggest that the depositional environments of the Corcoran evolved from marine upper shoreface to non-marine, while the Cozzette sequence evolved from lower to upper shoreface. Porosity and water saturation calculations have been conducted by computer for seven Corcoran and Cozzette depositional units. A comparison of calculated water saturation with core-derived porosity and permeability indicates a fair to very good correlation of reservoir properties with clay content measured by gamma-ray log.Bureau of Economic Geolog

Case study on safety index for CO2 sequestration in a deep saline aquifer

This study evaluates the risk for CO2 leakage from a storage site using a risk assessment criterion, the safety index, which considers the contributions of residual gas, solubility, ionic, and mineral trapping mechanisms. We present a case of CO2 storage in a deep saline aquifer in Yutengping (YTP) sandstone, Tiehchanshan (TCS) field, Taiwan. The numerical method was used to estimate the amount of different CO2 phases sequestered by the various trapping mechanisms. The CO2 injection rate was 1 million tons per year for 20 years. The total simulation time was 1000 years. In the case of down-dip well injection, the safety index was 0.77 at the storage time of 1000 years and much higher than the safety index of 0.45 for the up-dip well. More mobile supercritical CO2 had to be sealed using a caprock in the up-dip well injection case. Injecting CO2 using a down-dip well is a better engineering strategy because the safety index is higher

The Travis Peak (Hosston) Formation: Geologic Framework, Core Studies, and Engineering Field Analysis

The Travis Peak Formation constitutes a 1,000- to 5,000-ft-thick elastic wedge that formed two major depocenters as it spread across a shallow, carbonate-supported shelf along the north flank of the Gulf Coast Basin. The depocenters, which developed in the northern part of the East Texas Basin and in northeast Louisiana, consisted of high-constructive delta complexes dominated by fluvial-deltaic facies. A delta-fringe facies tract, including tidal flat, distributary channel, bay, and nearshore shallow marine shelf facies, formed around the margins of the elastic wedge. These marginal-marine deposits within the upper Travis Peak constitute the most important productive facies of the formation within a nine-county area of research emphasis in the East Texas Basin. Three sandstone types within the upper Travis Peak have been defined from sedimentologic properties observed in core and have been interpreted as channel and sandy tidal flat deposits. Sandstones in the Travis Peak were found to be mineralogically mature, with detrital quartz constituting 89 to 99 percent of the framework constituents. Low permeability and occlusion of porosity is primarily due to quartz overgrowths, which average 21 percent of clean sandstones. Within six Travis Peak gas fields in the eastern East Texas Basin, reservoir engineering studies show that porosity ranges from 8 to 11 percent and water saturation ranges from 28 to 44 percent within intervals of net pay. Permeability-thickness product is low in the southern part of the study area and increases toward the center and northern parts. Upper limits of permeability for 157 wells range from 0.074 md (median value) to 0.084 md (thickness-weighted average). These data are derived largely from well tests that postdate fracture treatment; therefore, pre-frac in situ values are expected to be lower. Within Chapel Hill field, reservoir sandstone types with greatest lateral continuity were deposited as sandy tidal flats, including associated channel sandstones. Where channel patterns are evident, as indicated by the thickest net sandstone, their trend is northwest. Lower energy tidal flat deposition is characterized by increased mud content of sandstones, and local marine transgression resulted in deposition of mudstone and muddy limestone.Bureau of Economic Geolog

Assessment of Unconventional Gas Resource in Texas,oDispersed Gas Project GRI Contract No. 5080-321-0398 August- October

The assessment of various gas resources in Texas, including geopressured sandstones, co-production of gas and water, hydropressured sandstones, undiscovered gas, and wet gas-bearing shale, provides valuable insight into the potential reserves and recovery factors for each resource category. Here's a summary of the key findings: 1. **Geopressured Sandstones:** - In-place solution gas is estimated to be 690 trillion cubic feet (Tcf) with a recoverable gas of 28 Tcf, representing about 4% of the in-place solution gas. - Distribution of the resource is tabulated by formation, subdivision, and major fault zones. 2. **Co-production, Gas, and Water:** - This assessment considers non-associated natural gas in onshore and offshore Texas, with recoverable unconventional free gas calculated based on original gas-in-place, proven gas reserves, cumulative primary gas production, and recovery factors. 3. **Hydropressured Sandstones (or Aquifers):** - In-place solution gas data are provided for various areas in Texas, assuming a 3% recovery factor. 4. **Undiscovered Gas:** - Data from various sources are used to estimate undiscovered gas reserves, assuming a recovery factor of 10% of the original gas-in-place. 5. **Wet Gas-Bearing Shale:** - Estimated recoverable gas in onshore and offshore Texas is 2.7 Tcf, representing about 10% of the recoverable solution gas estimated for geopressured sandstones. 6. **Probability Factors:** - Probability factors are used to assess the reliability and accuracy of the data used in the assessment, providing insights into the confidence levels associated with the estimated reserves. Overall, the assessment provides valuable information for understanding the potential gas resources in Texas and the factors influencing their recoverability.Bureau of Economic Geolog