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Using a geology-based assessment methodology, the U.S. Geological Survey estimated means of 806 million barrels of oil and 17.0 trillion cubic feet of gas within the greater Taranaki Basin and East Coast Basin of New Zealand.
The potential of Lower Cretaceous sandstones of the Travis Peak Formation in the northern Gulf Coast Basin to harbor a basin-centered gas accumulation was evaluated by examining (1) the depositional and diagenetic history and reservoir properties of Travis Peak sandstones, (2) the presence and quality of source rocks for generating gas, (3) the burial and thermal history of source rocks and time of gas generation and migration relative to tectonic development of Travis Peak traps, (4) gas and water recoveries from drill-stem and formation tests, (5) the distribution of abnormal pressures based on shut-in-pressure data, and (6) the presence or absence of gas-water contacts associated with gas accumulations in Travis Peak sandstones. The Travis Peak Formation (and correlative Hosston Formation) is a basinward-thickening wedge of terrigenous clastic sedimentary rocks that underlies the northern Gulf Coast Basin from eastern Texas across northern Louisiana to southern Mississippi. Clastic influx was focused in two main fluvial-deltaic depocenters—one located in northeastern Texas and the other in southeastern Mississippi and northeastern Louisiana. Across the main hydrocarbon-productive trend in eastern Texas and northern Louisiana, the Travis Peak Formation is about 2,000 ft thick. Most Travis Peak hydrocarbon production in eastern Texas comes from drilling depths between 6,000 and 10,000 ft. Significant decrease in porosity and permeability occurs through that depth interval. Above 8,000-ft drilling depth in eastern Texas, Travis Peak sandstone matrix permeabilities often are significantly higher than the 0.1-millidarcy (mD) cutoff that characterizes tight-gas reservoirs. Below 8,000 ft, matrix permeability of Travis Peak sandstones is low because of pervasive quartz cementation, but abundant natural fractures impart significant fracture permeability. Although pressure data within the middle and lower Travis Peak Formation are limited in eastern Texas, overpressured reservoirs caused by thermal generation of gas, typical of basin-centered gas accumulations, are not common in the Travis Peak Formation. Significant overpressure was found in only one Travis Peak sandstone reservoir in 1 of 24 oil and gas fields examined across eastern Texas and northern Louisiana. The presence of gas-water contacts is perhaps the most definitive criterion indicating that a gas accumulation is conventional rather than a “sweet spot” within a basin-centered gas accumulation. Hydrocarbon-water contacts within Travis Peak sandstone reservoirs were documented in 17 fields and probably occur in considerably more fields across the productive Travis Peak trend in eastern Texas and northern Louisiana. All known hydrocarbon-water contacts in Travis Peak reservoirs in eastern Texas, however, occur within sandstones in the upper 500 ft of the formation. Although no gas-water contacts have been reported within the lower three-fourths of the Travis Peak Formation in northeastern Texas, gas production from that interval is limited. The best available data suggest that most middle and lower Travis Peak sandstones are water bearing in northeastern Texas. Insufficient hydrocarbon charge relative to permeability of Travis Peak reservoirs might be responsible for lack of overpressure and basin-centered gas within the Travis Peak Formation. Shales interbedded with Travis Peak sandstones in eastern Texas are primarily oxidized flood-plain deposits with insufficient organic-carbon content to be significant sources of oil and gas. The most likely source rocks for hydrocarbons in Travis Peak reservoirs are two stratigraphically lower units, the Jurassic-age Bossier Shale of the Cotton Valley Group, and laminated, lime mudstones of the Jurassic Smackover Formation. Hydrocarbon charge, therefore, might be sufficient for development of conventional gas accumulations, but it is insufficient for development of basin-centered gas as a result of the absence of proximal source rocks and a lack of effective migration pathways from stratigraphically or geographically distant source rocks.
The Upper Cretaceous–Pliocene strata of New Zealand record ~100 m.y. of Zealandia’s evolution, including development of the Hikurangi convergent margin and Alpine transform plate boundary. A comprehensive, new detrital zircon U-Pb data set (8315 analyses from 61 samples) was generated along a ~700 km transect of the East Coast Basin of New Zealand. Age distributions were analyzed and interpreted in terms of published data available for Cambrian–Cretaceous igneous and metasedimentary source terranes using a Monte Carlo mixture modeling approach. Results indicate a widespread Early Cretaceous transition in sediment source from the Gondwana interior to the Median Batholith magmatic arc prior to Late Cretaceous rifting from Antarctica. Submergence of Zealandia during a Late Cretaceous–Paleogene drift phase led to major drainage reorganization and the influx of Eastern Province sediment to the East Coast Basin. A long-lived sediment conduit that transported extraregional Western Province detritus to the south-central East Coast Basin may have developed along a structural precursor to the Alpine Fault. Marked Neogene increase of Upper Jurassic–Lower Cretaceous Torlesse Composite Terrane sediment to the central East Coast Basin resulted from exhumation of the Axial Ranges, convergence along the Hikurangi subduction margin, and concurrent development of the Alpine Fault. Concurrent influx of contemporaneous Neogene zircon in the northern East Coast Basin indicated the onset of subduction-related volcanism of the Northland–Coromandel Volcanic Arc. Middle Miocene–Pliocene exhumation and dextral translation of the Nelson region along the Alpine Fault resulted in the eastward routing of Western Province sediment to the central East Coast Basin. Finally, topography developed across the plate boundary and ultimately partitioned continental drainage of Zealandia, such that sediment from the Murihiku, Caples, and Rakaia Terranes in the Otago region was routed to the southern extent of the East Coast Basin. These results illuminate the evolution of the Zealandia continental drainage divide in response to the initiation of the Pacific-Australian plate boundary and demonstrate the power of mixture modeling and large data sets for deciphering sediment routing in dynamic tectonic environments.
The extensive use of ground water throughout the Central and West Coast Basins of Los Angeles County during the first half of the 20th century resulted in declining water levels, widespread seawater intrusion, and deterioration of water quality along most reaches of the coast. In order to control seawater intrusion in the West Coast Basin, freshwater is injected into a series of wells at two seawater barrier projects. In order to better understand the processes of seawater intrusion and the efficiency of current barrier operation, data were collected from multiple-well monitoring sites installed by the U.S. Geological Survey, from local observation wells, and from production wells. The occurrence and areal extent of native, saline, and recently injected ground water near the coast were defined through the collection and analysis of inorganic and isotopic water-quality data and geophysical logs. Most water in the West Coast Basin with a dissolved-solids concentration less than 500 milligrams per liter generally has a sodium-bicarbonate to sodium/calcium-bicarbonate character. Water with a dissolved-solids concentration greater than 1,000 milligrams per liter also contains variable amounts of calcium and sodium, but chloride is predominant. Most of these high-dissolved-solids wells are perforated in the Upper aquifer systems; several have dissolved-chloride values near that of seawater. Elevated chloride concentrations were measured at many wells in both the Upper and Lower aquifer systems inland from the barrier projects. Although water levels have increased in many wells over the last 30 years, some of the wells do not show a corresponding decrease in dissolved chloride. A detailed assessment of saline ground water was provided by examining the ratios of chloride to bromide, iodide, and boron. Seawater-freshwater mixing lines were constructed using all three ratios. These ion ratios also identify water affected by mixing with injected imported water and oil-field brine water. Isotopic data -oxygen-18, deuterium, strontium-87, boron-11, tritium, and carbon-14-also were collected. The stable isotopes oxygen-18 and deuterium were used to distinguish between isotopically heavier water that originated in the Los Angeles Forebay, isotopically lighter water that originated in the Montebello Forebay, local recharge, and water containing a mixture of seawater and imported water. Tritium data were used to identify recent water (less than 50 years old) present in the Upper and Lower aquifer systems inland from the seawater barrier projects, and present locally near the Dominguez Gap. Carbon-14 data indicate that water with uncorrected ages ranging from about 4,000 years to more than 20,000 years before present occurs in the Lower aquifer systems and in the Pico unit. Borehole electromagnetic conductivity logs, combined with gamma-ray logs, were used to identify potential saline zones throughout the entire well depth; this provides an indicator of intrusion in zones that are not being monitored by a piezometer. Temperature logging was used to track the thermal effects of the cooler water used for injection. Specific-conductance logs provided a screening-level indicator of poor-quality water in monitoring wells.
The Bureau of Economic Geology at the University of Texas at Austin (UT-BEG) is leading the Gulf Coast Carbon Ore, Rare Earth, and Critical Minerals (CORE-CM) Initiative to assess the potential to produce critical minerals (CMs), including rare earth elements (REEs) from coal, coal ash, and produced water related to oil and gas production, and related materials (alumina processing waste [red mud], heavy mineral sands, graphite, and zeolite) within the Gulf Coast Basin. This project represents the first phase in a long-term program and provides reconnaissance data that will be foundational for future work by assessing resources and suggesting plans to be conducted in future work and expanding stakeholder engagement. The project includes several tasks designed to identify, characterize, and assess several necessary aspects for development of CMs and REEs in the Gulf Coast Basin.
Historical ground-water development of the Central and West Coast Basins in Los Angeles County, California through the first half of the 20th century caused large water-level declines and induced seawater intrusion. Because of this, the basins were adjudicated and numerous ground-water management activities were implemented, including increased water spreading, construction of injection barriers, increased delivery of imported water, and increased use of reclaimed water. In order to improve the scientific basis for these water management activities, an extensive data collection program was undertaken, geohydrological and geochemical analyses were conducted, and ground-water flow simulation and optimization models were developed. In this project, extensive hydraulic, geologic, and chemical data were collected from new multiple-well monitoring sites. On the basis of these data and data compiled and collected from existing wells, the regional geohydrologic framework was characterized. For the purposes of modeling, the three-dimensional aquifer system was divided into four aquifer systems?the Recent, Lakewood, Upper San Pedro, and Lower San Pedro aquifer systems. Most pumpage in the two basins is from the Upper San Pedro aquifer system. Assessment of the three-dimensional geochemical data provides insight into the sources of recharge and the movement and age of ground water in the study area. Major-ion data indicate the chemical character of water containing less than 500 mg/L dissolved solids generally grades from calcium-bicarbonate/sulfate to sodium bicarbonate. Sodium-chloride water, high in dissolved solids, is present in wells near the coast. Stable isotopes of oxygen and hydrogen provide information on sources of recharge to the basin, including imported water and water originating in the San Fernando Valley, San Gabriel Valley, and the coastal plain and surrounding hills. Tritium and carbon-14 data provide information on relative ground-water ages. Water with abundant tritium (greater than 8 tritium units) is found in and downgradient from the Montebello Forebay and near the seawater barrier projects, indicating recent recharge. Water with less than measurable tritium is present in, and downgradient from, the Los Angeles Forebay and in most wells in the West Coast Basin. Water from several deep wells was analyzed for carbon-14. Uncorrected estimates of age for these samples range from 600 to more than 20,000 years before present. Chemical and isotopic data are combined to evaluate changes in chemical character along flow paths emanating from the Montebello and Los Angeles Forebays. A four-layer ground-water flow model was developed to simulate steady-state ground-water conditions representative of those in 1971 and transient conditions for the period 1971?2000. Model results indicate increases in ground-water storage in all parts of the study area over the simulated thirty-year period. The model was used to develop a three-dimensional ground-water budget and to assess impacts of two alternative future (2001?25) ground-water development scenarios?one that assumes continued pumping at average current rates and a second that assumes increasing pumping from most wells in the Central Basin. The model simulates stable or slightly increasing water levels for the first scenario and declining water levels (25 to 50 ft in the Central Basin) in the second scenario. Model sensitivity to parameter values and to the assumed Orange County boundary condition was evaluated. Particle tracking was applied to simulate advective transport of water from the spreading ponds, the coastline, and the seawater injection barriers. Particle tracking results indicate that most flow within the Upper San Pedro aquifer system occurs within about 20 percent of the total aquifer system thickness and that virtually all water injected into the seawater barrier projects has flowed inland. The simulation model was linked with optimizatio
In 1995, the U.S. Geological Survey (USGS), in cooperation with the Water Replenishment District of Southern California (WRDSC) , began a study to examine ground-water resources in the Central and West Coast Basins in Los Angeles County, California. The study characterizes the geohydrology and geochemistry of the regional ground-water flow system and provides extensive data for evaluating ground-water management issues. This report is a compilation of geologic, hydrologic, and water-quality data collected from 24 recently constructed multiple-well monitoring sites for the period 1995–2000. Descriptions of the collected drill cuttings were compiled into lithologic logs, which are summarized along with geophysical logs—including gamma-ray, spontaneous potential, resistivity, electromagnetic induction, and temperature tool logs—for each monitoring site. At selected sites, cores were analyzed for magnetic orientation, physical and thermal properties, and mineralogy. Field and laboratory estimates of hydraulic conductivity are presented for most multiple-well monitoring sites. Periodic water-level measurements are also reported. Water-quality information for major ions, nutrients, trace elements, deuterium and oxygen-18, and tritium is presented for the multiple-well monitoring locations, and for selected existing production and observation wells. In addition, boron-11, carbon-13, carbon-14, sulfur-34, and strontium-87/86 data are presented for selected wells.
Using a geology-based assessment methodology, the U.S. Geological Survey estimated undiscovered, technically recoverable mean resources of 152 million barrels of oil and 47.9 trillion cubic feet of gas in reservoirs of the Haynesville Formation within the onshore United States and State waters of the Gulf Coast Basin.
Large submarine slides and associated shelf-margin embayments represent an intermediate member in the continuum of unstable shelf-margin features. On seismic profiles, they may resemble submarine canyons, but are different in their size, morphology, origin, and hydrocarbon exploration potential. Two large Neogene submarine slides, located in the northwestern Gulf Coast Basin, formed on the upper slope and flanks of prominent shelf-margin deltas. The basal detachment surface of each slide is a structural discontinuity that may be misinterpreted as an erosional unconformity and, therefore, misidentified as a stratigraphic boundary separating depositional sequences. Regional stratigraphic correlations indicate that both slides were initiated after the continental platform wa flooded. The condensed sections deposited during the rise in relative sea level contain the basal detachment surfaces. Beyond these observations, the relationships between the slides and sea level fluctuations are uncertain. The shelf-margin embayments created by the slides apparently were partly excavated during periods of lowered relative sea level and were filled during the subsequent relative sea level rise and highstand. Eventually the preslide morphology of the shelf margin was restored by coalesced prograding deltas. Submarine slides exhibit landward-dipping, wavy, mounded, and chaotic seismic reflections that are manifestations of slump blocks and other mass transport material. Composition of these internally derived slide deposits depends on the composition of the preexisting shelf margin. Embayment fill above the slide consists mostly of externally derived mudstones and sandstones deposited by various disorganized slope processes, as well as more organized submarine channel-levee systems. Thickest slope sandstones, which are potential hydrocarbon reservoirs, commonly occur above the basal slide mudstones where seismic reflections change from chaotic patterns to overlying wavy or subhorizontal reflections.
The lower Eagle Ford Group (LEFG) is one of the most productive continuous hydrocarbon plays in the United States but few associated produced waters data and minimal interpretation have been published. This effort focuses on results from compositional and isotopic data from 39 produced water samples collected from horizontal wells producing from the LEFG in south central Texas. The depth of the LEFG increases by approximately 1 km across the study area, from northwest (2.9 km) to southeast (3.9 km). Associated increases in calculated reservoir temperature (125-165 C), development of reservoir over-pressuring (400-800 bars total pressure), and increased thermal maturity (heavy oil to gas condensate) also occur along this trend. Produced water salinity starts at nearly 100 g/L in the shallowest samples and decreases linearly with depth to <35 g/L. Comparison of Br/Cl and ⁸⁷Sr/⁸⁶Sr data between LEFG produced waters and the Louann salt, suggests that halite recycling is the mechanism behind salinity greater than seawater. Decreasing salinity with depth and thermal maturity in the Gulf Coast Basin have previously been shown to be a result of release of inter-layer water during smectite to illite conversion. The produced water samples show increasing 18O and decreasing 2H with depth, which is attributed temperature-dependent isotope fractionation of O and H exchange between seawater and clays and calcite with increasing temperature. Multiple sources of data indicate that the waters in the LEFG are not connate, but rather entered the unit prior to smectite-illite conversion. Presence of allochthonous water in many major tight oil and shale gas plays in the U.S., including the LEFG, suggests there is unknown mechanism allowing for water advection into low permeability reservoirs.
The U.S. Geological Survey (USGS), in cooperation with the U.S. Department of Energy, is reevaluating the resource potential of selected domestic basin-centered gas accumulations. Basin-centered gas accumulations are characterized by presence of gas in extensive low-permeability (tight) reservoirs in which conventional seals and trapping mechanisms are absent, abnormally high or low reservoir pressures exist, and gas-water contacts are absent. In 1995, the USGS assessed one basin-centered gas play and two conventional plays within the trend of Jurassic and Cretaceous Cotton Valley Group fluvial-deltaic and barrier island/strand plain sandstones across the onshore northern Gulf of Mexico Basin. Detailed evaluation of geologic and production data provides new insights into these Cotton Valley plays. Two Cotton Valley sandstone trends are identified based on reservoir properties and gas-production characteristics. Transgressive blanket sandstones across northern Louisiana have relatively high porosity and permeability and do not require fracture stimulation to produce gas at commercial rates. South of this trend, and extending westward into eastern Texas, massive sandstones of the Cotton Valley trend exhibit low porosity and permeability and require fracture stimulation. The high permeability of Cotton Valley blanket sandstones is not conducive to the presence of basin-centered gas, but low permeability massive sandstones provide the type of reservoir in which basin-centered gas accumulations commonly occur. Data on source rocks, including burial and thermal history, are consistent with the interpretation of potential basin centered gas within Cotton Valley sandstones. However, pressure gradients throughout most of the blanket- and massive sandstone trends are normal or nearly normal, which is not characteristic of basin-centered gas accumulations. The presence of gas-water contacts in at least seven fields across the blanket-sandstone trend together with relatively high permeabilities and high gas-production rates without fracture stimulation indicate that fields in this trend are conventional. Within the tight massive-sandstone trend, permeability is sufficiently low that gas-water transition zones are vertically extensive and gas-water contacts either have not been encountered or are poorly defined. With increasing depth through these transition zones, gas saturation decreases and water saturation increases until eventually gas saturations become sufficiently low that, in terms of ultimate cumulative production, wells are noncommercial. Such progressive increase in water saturation with depth suggests that poorly defined gas-water contacts probably are present below the depth at which wells become noncommercial. The interpreted presence of gas-water contacts within the tight, Cotton Valley massive-sandstone trend suggests that gas accumulations in this trend, too, are conventional, and that a basin-centered gas accumulation does not exist within Cotton Valley sandstones in the northern Gulf Basin.
The “2800’ sandstone” of the Olla oil field is an oil and gas-producing reservoir in a coal-bearing interval of the Paleocene–Eocene Wilcox Group in north-central Louisiana, USA. In the 1980s, this producing unit was flooded with CO 2 in an enhanced oil recovery (EOR) project, leaving ∼30% of the injected CO 2 in the 2800’ sandstone post-injection. This study utilizes isotopic and geochemical tracers from co-produced natural gas, oil and brine to determine the fate of the injected CO 2 , including the possibility of enhanced microbial conversion of CO 2 to CH 4 via methanogenesis. Stable carbon isotopes of CO 2 , CH 4 and DIC, together with mol% CO 2 show that 4 out of 17 wells sampled in the 2800’ sandstone are still producing injected CO 2 . The dominant fate of the injected CO 2 appears to be dissolution in formation fluids and gas-phase trapping. There is some isotopic and geochemical evidence for enhanced microbial methanogenesis in 2 samples; however, the CO 2 spread unevenly throughout the reservoir, and thus cannot explain the elevated indicators for methanogenesis observed across the entire field. Vertical migration out of the target 2800’ sandstone reservoir is also apparent in 3 samples located stratigraphically above the target sand. Reservoirs comparable to the 2800’ sandstone, located along a 90-km transect, were also sampled to investigate regional trends in gas composition, brine chemistry and microbial activity. Microbial methane, likely sourced from biodegradation of organic substrates within the formation, was found in all oil fields sampled, while indicators of methanogenesis (e.g. high alkalinity, δ 13 C-CO 2 and δ 13 C-DIC values) and oxidation of propane were greatest in the Olla Field, likely due to its more ideal environmental conditions (i.e. suitable range of pH, temperature, salinity, sulfate and iron concentrations).
The Upper Cretaceous Tuscaloosa marine shale (TMS) potential production area encompasses 20.4 million acres across central Louisiana (LA), southern Mississippi (MS), southwestern Alabama (AL), and a small southwestern section of the Florida panhandle (Hackley et al., 2018). It remains a minor and largely undeveloped unconventional shale oil play with production from the TMS confined along the east-west LA-MS State boundary (Fig. 1). The mean undiscovered, technically recoverable resources in the TMS are estimated at 1.5 billion barrels of oil and 4.6 trillion cubic feet of gas (Hackley et al., 2018). Geochemical analyses of source rock solvent extracts and oil samples indicate that, in the play area, the TMS is the primary source of shale oil produced from the TMS as well as of accumulated oils in the underlying conventional reservoirs of the lower Tuscaloosa (Hackley et al., 2020). The API gravity of TMS oils ranges from approximately 34 to 46 degrees (Hackley et al., 2020; Croke et al., 2020).
Building on a geology-based assessment of undiscovered, technically recoverable hydrocarbon resources within the Haynesville Formation, the U.S. Geological Survey estimated the water and proppant necessary for development of the remaining resources associated with the Haynesville Sabine Uplift Continuous Gas Assessment Unit. Additionally, projections have been made on the volume of wastewater expected as a byproduct of possible future development. This fact sheet presents an overview of the methodology, along with the inputs and results of the Haynesville water and proppant assessment.
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Coal beds are one of the most promising reservoirs for geologic carbon dioxide (CO₂) sequestration, as CO₂ can strongly adsorb onto organic matter and displace methane; however, little is known about the long-term fate of CO₂ sequestered in coal beds. The "2800' sand" of the Olla oil field is a coal-bearing, oil and gas-producing reservoir of the Paleocene–Eocene Wilcox Group in north-central Louisiana. In the 1980s, this field, specifically the 2800' sand, was flooded with CO₂ in an enhanced oil recovery (EOR) project, with 9.0×10⁷m³ of CO₂ remaining in the 2800' sand after injection ceased. This study utilized isotopic and geochemical tracers from co-produced natural gas, oil and brine from reservoirs located stratigraphically above, below and within the 2800' sand to determine the fate of the remaining EOR-CO₂, examining the possibilities of CO₂ migration, dissolution, mineral trapping, gas-phase trapping, and sorption to coal beds, while also testing a previous hypothesis that EOR-CO₂ may have been converted by microbes (CO₂-reducing methanogens) into methane, creating a microbial "hotspot". Reservoirs stratigraphically-comparable to the 2800' sand, but located in adjacent oil fields across a 90-km transect were sampled to investigate regional trends in gas composition, brine chemistry and microbial activity. The source field for the EOR-CO₂, the Black Lake Field, was also sampled to establish the δ¹³C-CO₂ value of the injected gas (0.9‰ +/- 0.9‰). Four samples collected from the Olla 2800' sand produced CO₂-rich gas with δ¹³C-CO₂ values (average 9.9‰) much lower than average (pre-injection) conditions (+15.9‰, average of sands located stratigraphically below the 2800' sand in the Olla Field) and at much higher CO₂ concentrations (24.9 mole %) than average (7.6 mole %, average of sands located stratigraphically below the 2800' sand in the Olla Field), suggesting the presence of EOR-CO₂ and gas-phase trapping as a major storage mechanism. Using δ¹³C values of CO₂ and dissolved organic carbon (DIC), CO₂ dissolution was also shown to be a major storage mechanism for 3 of the 4 samples from the Olla 2800' sand. Minor storage mechanisms were shown to be migration, which only affected 2 samples (from 1 well), and some EOR-CO₂ conversion to microbial methane for 3 of the 4 Olla 2800' sand samples. Since methanogenesis was not shown to be a major storage mechanism for the EOR-CO₂ in the Olla Field (CO₂ injection did not stimulate methanogenesis), samples were examined from adjacent oil fields to determine the cause of the Olla microbial "hot-spot". Microbial methane was found in all oil fields sampled, but indicators of methanogenesis (e.g. alkalinity, high δ¹³C-DIC values) were the greatest in the Olla Field, and the environmental conditions (salinity, pH, temperature) were most ideal for microbial CO₂ reduction in the Olla field, compared to adjacent fields.
No abstract available.