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1
Geel, C., S. Nolte, and E. M. Bordy. "Geomechanical properties of the Permian black shales in the southern main Karoo Basin: lessons from compositional and petrophysical studies." South African Journal of Geology 124, no. 3 (September 1, 2021): 735–50. http://dx.doi.org/10.25131/sajg.124.0026.
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Abstract Permian black shales from the lower Ecca Group of the southern main Karoo Basin (MKB) have a total organic carbon (TOC) of up to ~5 wt% and have been considered primary targets for a potential shale gas exploration in South Africa. This study investigates the influence of shale composition, porosity, pressure (P) and temperatures (T) on their geomechanical properties such as compressive strength and elastic moduli. On average, these lower Ecca Group shales contain a high proportion, ~50 to 70 vol%, of mechanically strong minerals (e.g., quartz, feldspar, pyrite), ~30 to 50 vol% of weak minerals (e.g., clay minerals, organic matter) and ~0 to 50 vol% of intermediate minerals (e.g., carbonates), which have highly variable mechanical strength. Constant strain rate, triaxial deformation tests (at T ≤100°C; P ≤50 MPa) were performed using a Paterson-type high pressure instrument. Results showed that the Prince Albert Formation is the strongest and most brittle unit in the lower Ecca Group in the southern MKB followed by the Collingham and then the Whitehill Formation. Compressive strength and Young’s moduli (E) increase with increasing hard mineral content and decrease with increasing mechanically weak minerals and porosity. On comparison with some international shales, for which compositional and geomechanical data were measured using similar techniques, the lower Ecca Group shales are found to be geomechanically stronger and more brittle. This research provides the foundation for future geomechanical and petrophysical investigations of these Permian Ecca black shales and their assessment as potential unconventional hydrocarbon reservoirs in the MKB.
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Baiyegunhi, Christopher, Zusakhe Nxantsiya, Kinshasa Pharoe, Temitope L. Baiyegunhi, and Seyi Mepaiyeda. "Petrographical and geophysical investigation of the Ecca Group between Fort Beaufort and Grahamstown, in the Eastern Cape Province, South Africa." Open Geosciences 11, no. 1 (July 17, 2019): 313–26. http://dx.doi.org/10.1515/geo-2019-0025.
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Abstract The outcrop of the Ecca Group in the Eastern Cape Province was investigated in order to reveal petrographic and geophysical characteristics of the formations that make up the group which are vital information when considering fracking of the Karoo for shale gas. The petrographic study reveals that the rocks of the Ecca Group are both argillaceous and arenaceous rock with quartz, feldspar, micas and lithics as the framework minerals. The sandstones are graywackes, immature and poorly sorted, thus giving an indication that the source area is near. The observed heavy minerals aswell as the lithic grains signify that the minerals are of granitic, volcanic and metamorphic origin. The porosity result shows that of all the formations that make up the Ecca Group, the Whitehill Formation is the most porous with an average porosity of about 2.1% and also least dense with an average dry density of about 2.5 g/cm3. The least porous unit is the Ripon Formation with porosity of about 0.8% but has the highest dry density of approximately 2.8 g/cm3. The magnetic map shows some ring-like structures which coincide with dolerites that were mapped in the field. As revealed by the depth slices result, dolerite intrusions are pervasive in the northern part of the study area, extending to a depth of about 6000 m below the ground surface. The appearance of dolerite intrusions at the targeted depth (3000 - 5000 m) for gas exploration could pose a serious threat to fracking of the Karoo for shale gas.
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Mosavel, H., D. I. Cole, and A. M. Siad. "Shale gas potential of the Prince Albert Formation: A preliminary study." South African Journal of Geology 122, no. 4 (December 1, 2019): 541–54. http://dx.doi.org/10.25131/sajg.122.0036.
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Abstract Recent investigations of the shale gas potential in the main Karoo Basin have concentrated on the Whitehill Formation within the Ecca Group. This study focuses on the shale gas potential of the underlying Prince Albert Formation using the parameters of volume porosity, permeability, total organic carbon (TOC), vitrinite reflectance and Rock-Eval data. Shale samples were retrieved from three surface localities in the southern part of the main Karoo Basin and from core of three boreholes drilled through the Prince Albert Formation near Ceres, Mervewille and Willowvale. The sampling localities occur near the borders of the prospective shale gas areas (“sweet spots”) identified for the Whitehill Formation. Kerogen was found to be Type IV with hydrogen indices less than 65 mg/g. Shale porosities are between 0.08 and 5.6% and permeabilities between 0 and 2.79 micro-Darcy, as determined by mercury porosimetry. TOC varies between 0.2 and 4.9 weight % and vitrinite reflectance values range from 3.8 to 4.9%. Although the porosity and TOC values of the Prince Albert Formation shales are comparable with, but at the lower limits of, those of the gas-producing Marcellus shale in the United States (porosities between 1 and 6% and TOC between 1 and 10 weight %), the high vitrinite reflectance values indicate that the shales are overmature with questionable potential for generating dry gas. This overmaturity is probably a result of an excess depth of burial, tectonic effects of the Cape Orogeny and dolerite intrusions. However, viable conditions for shale gas might exist within the “sweet spot” areas, which were defined for the Whitehill Formation.
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Geel, Claire, Hans-Martin Schulz, Peter Booth, Maarten deWit, and Brian Horsfield. "Shale Gas Characteristics of Permian Black Shales in South Africa: Results from Recent Drilling in the Ecca Group (Eastern Cape)." Energy Procedia 40 (2013): 256–65. http://dx.doi.org/10.1016/j.egypro.2013.08.030.
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Hohne, D., F. de Lange, S. Esterhuyse, and B. Sherwood Lollar. "Case study: methane gas in a groundwater system located in a dolerite ring structure in the Karoo Basin; South Africa." South African Journal of Geology 122, no. 3 (September 1, 2019): 357–68. http://dx.doi.org/10.25131/sajg.122.0025.
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Abstract In the past few years numerous assumptions were made on groundwater in the Karoo Basin and related shale gas development, but not many baseline studies were conducted on groundwater and on boreholes where methane currently occurs. This article focuses on one of these boreholes (BHA) in the Ubuntu Local Municipality area, located close to a dolerite ring structure, which is releasing methane gas. Water samples were analysed for macro and trace elements, environmental isotopes and methane concentrations. Chemical analyses results indicate that groundwater at this borehole may be a mixture between deep groundwater, shallow groundwater and meteoric water. A rise in the groundwater level and subsequent flowing artesian conditions that was observed, support the theory that mixing between deeper groundwater from the Ecca Group and shallower water from the Beaufort Group is taking place. These water level reactions could be due to possible seismic activity within close proximity to the dolerite ring structure and/or due to recharge and interflow to BHA.
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Schulz, H. M., B. Linol, M. de Wit, B. Schuck, I. Schaepan, and R. Wirth. "Early diagenetic signals archived in black shales of the Dwyka and Lower Ecca Groups of the southern Karoo Basin (South Africa): Keys to the deglaciation history of Gondwana during the Early Permian, and its effect on potential shale gas storage." South African Journal of Geology 121, no. 1 (March 1, 2018): 69–94. http://dx.doi.org/10.25131/sajg.121.0004.
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Baiyegunhi, Christopher, and Kuiwu Liu. "Sedimentary facies, stratigraphy, and depositional environments of the Ecca Group, Karoo Supergroup in the Eastern Cape Province of South Africa." Open Geosciences 13, no. 1 (January 1, 2021): 748–81. http://dx.doi.org/10.1515/geo-2020-0256.
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Abstract The stratigraphy of the Ecca Group has been subdivided into the Prince Albert, Whitehill, Collingham, Ripon, and Fort Brown Formations in the Eastern Cape Province, South Africa. In this article, we present detailed stratigraphic and facies analyses of borehole data and road-cut exposures of the Ecca Group along regional roads R67 (Ecca Pass), R344 (Grahamstown-Adelaide), R350 (Kirkwood-Somerset East), and national roads N2 (Grahamstown-Peddie) and N10 (Paterson-Cookhouse). Facies analysis of the Ecca Group in the study area was performed to deduce their depositional environments. Based on the lithological and facies characteristics, the stratigraphy of the Prince Albert, Whitehill, Collingham, and Fort Brown Formations is now subdivided into two informal members each, while the Ripon Formation is subdivided into three members. A total of twelve lithofacies were identified in the Ecca Group and were further grouped into seven distinct facies associations (FAs), namely: Laminated to thin-bedded black-greyish shale and mudstones (FA 1); Laminated black-greyish shale and interbedded chert (FA 2); Mudstone rhythmite and thin beds of tuff alternation (FA 3); Thin to thick-bedded sandstone and mudstone intercalation (FA 4); Medium to thick-bedded dark-grey shale (FA 5); Alternated thin to medium-bedded sandstone and mudstone (FA 6); and Varved mudstone rhythmite and sandstone intercalation (FA 7). The FAs revealed gradually change of sea-level from deep marine (FA 1, FA 2, FA 3 and FA 4, FA 5, and FA 6) to prodelta environment (FA 7). This implies that the main Karoo Basin was gradually filling up with Ecca sediments, resulting in the gradual shallowing up of the water depth of the depositional basin.
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BAIYEGUNHI, Christopher, Kuiwu LIU, Nicola WAGNER, Oswald GWAVAVA, and Temitope L. OLONINIYI. "Geochemical Evaluation of the Permian Ecca Shale in Eastern Cape Province, South Africa: Implications for Shale Gas Potential." Acta Geologica Sinica - English Edition 92, no. 3 (June 2018): 1193–217. http://dx.doi.org/10.1111/1755-6724.13599.
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de V. Wickens, H., and D. I. Cole. "Lithostratigraphy of the Kookfontein Formation (Ecca Group, Karoo Supergroup), South Africa." South African Journal of Geology 120, no. 3 (September 1, 2017): 447–58. http://dx.doi.org/10.25131/gssajg.120.3.447.
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Abstract The Permian Kookfontein Formation forms part of the upper Ecca Group in the southwestern part of the main Karoo Basin of South Africa. It occupies a stratigraphic position between the underlying Skoorsteenberg Formation and the overlying Waterford Formation, with its regional extent limited to the cut-off boundaries of the Skoorsteenberg Formation. The Kookfontein Formation has an average thickness of 200 m, coarsens upwards, and predominantly comprises dark grey shale, siltstone and thin- to thick-bedded, fine- to very fine-grained, feldspathic litharenite. Characteristic upward-coarsening and thickening successions and syn-sedimentary deformation features reflect rapid deposition and progradation of a predominantly fluvially-dominated prodelta and delta front slope environment. The upward increase in the abundance of wave–ripple marks further indicates a gradual shallowing of the depositional environment through time. The upper contact with the Waterford Formation is gradational, which indicates a transition from deposition in an unstable upper slope/shelf margin environment to a more stable shelf setting.
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Wickens, H. de V., and D. I. Cole. "Lithostratigraphy of the Skoorsteenberg Formation (Ecca Group, Karoo Supergroup), South Africa." South African Journal of Geology 120, no. 3 (September 1, 2017): 433–46. http://dx.doi.org/10.25131/gssajg.120.3.433.
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Abstract The Middle Permian Skoorsteenberg Formation is part of the Ecca Group (Karoo Supergroup) of South Africa. It is also known as the ‘Tanqua fan complex’ due to its origin as a deep-water sedimentation unit associated with a prograding deltaic system. The Skoorsteenberg Formation crops out over approximately 650 km2 along the western margin of the Main Karoo Basin. It thins out in a northerly and easterly direction and therefore has a limited extent with cut-off boundaries to the south and north. It is underlain by the Tierberg Formation and overlain by the Kookfontein Formation, the latter being limited to the regional distribution of the Skoorsteenberg Formation. The Skoorsteenberg Formation has a composite thickness of 400 m and comprises five individual sandstone packages, separated by shale units of similar thickness. The sandstones are very fine- to fine-grained, light greyish to bluish grey when fresh, poorly sorted and lack primary porosity and permeability. The Tanqua fan complex is regarded as one of the world’s best examples of an ancient basin floor to slope fan complex associated with a fluvially dominated deltaic system. It has served as analogue for many deep-water systems around the world and continues to be a most sought after “open-air laboratory” for studying the nature of fine-grained, deep-water sedimentation. The fan systems are essentially tectonically undeformed, outstandingly well exposed and contain an inexhaustible amount of information on the deep-water architecture of lower slope to basin floor turbidite deposits.
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Xu, Han Yue, Hai Tao Xue, Shuang Fang Lu, Wen Biao Huang, and Lei Shi. "Evaluation on Shale Gas Potential in the Sheling Group Yitong Basin." Advanced Materials Research 941-944 (June 2014): 2584–87. http://dx.doi.org/10.4028/www.scientific.net/amr.941-944.2584.
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Yitong Basin is a Tertiary depression bas in Jilin Province , and from north to south were Chaluhe , Luxiang and Moliqing depression. As the depth is larger , high maturity of organic matter , more than 1% , mainly shale gas. Based on the geochemical parameters of sheling group , using chemical kinetics method study the birth hydrocarbon volume, using the sum of the largest shale gas tolerance capabilities , based on the adsorption isotherm experiments, combined hydrocarbon volume , calculated the shale gas resources in the region , the results showed that the total amount of resources sheling group Yitong Basin shale gas level was 238.215 billion square . Indicates that the area has huge shale gas resource potential
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Zhang, Xin, Jun Yuan, Pei Xue, Jing Jing Fan, and Jin Wang. "Shale Gas Resources Evaluation of the Songliao Basin." Applied Mechanics and Materials 508 (January 2014): 129–32. http://dx.doi.org/10.4028/www.scientific.net/amm.508.129.
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The Qingshankou and Nenjiang group in upper cretaceous of Songliao basin is a set of dark shale. Analyze the shale thickness, organic matter type, organic matter abundance, vitrinite reflectance, mineral composition of the permo-carboniferous coal-bearing strata. Consider that the thickness of shale in the Songliao basin is larger, despite the organic matter abundance is good, but maturity is lower, less of the formation of oil and gas.
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Wong, Joanna, and Mohammad Bahar. "Shale gas resource assessment in the Merlinleigh Sub-basin, Carnarvon Basin." APPEA Journal 55, no. 2 (2015): 452. http://dx.doi.org/10.1071/aj14087.
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The recent shale gas developments in the US have encouraged exploration for shale gas resource in WA. In the largely unexplored Carnarvon Basin, the Merlinleigh Sub-basin is predominately of Permian strata and has been shown to contain high-quality gas-prone source rocks from geochemical data. Three main potential shale layers, the Gneudna Formation, Wooramel Group and the Byro Group, were identified based on the shale ranking parameters. Geochemical data was collected and analysed for the type of kerogen, total organic content (TOC), generation potential and thermal maturity. These parameters enabled a gas-in-place resource estimation to be made for each of the formations. The TOC data from various wells were validated by using petrophysical logs and the ÎlogR method. In comparison with the geochemical data, both values produced a good match, validating both sets of data. The three layers were ranked according to their geochemical parameters and any petrophysical or geomechanical characteristics. It was identified that the Wooramel Group contains the best quality source rocks, followed by the Byro Group. The Gneudna Formation was found to have poor quality source rocks. The Monte Carlo method by Crystal Ball was selected to estimate the probabilistic resources of these three layers. According to the P50 estimations, the Byro Group, Wooramel Group and the Gneudna Formation contained resources of 51.6 tcf, 40.1 tcf and 1.4 tcf, respectively.
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Wong, Joanna, and Mohammad Bahar. "Shale gas resource assessment in the Merlinleigh Sub-basin, Carnarvon Basin." APPEA Journal 55, no. 2 (2015): 471. http://dx.doi.org/10.1071/aj14106.
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The recent shale gas developments in the US have encouraged exploration for shale gas resource in WA. In the largely unexplored Carnarvon Basin, the Merlinleigh Sub-basin is predominately of Permian strata and has been shown to contain high-quality gas-prone source rocks from geochemical data. Three main potential shale layers, the Gneudna Formation, Wooramel Group and the Byro Group, were identified based on the shale ranking parameters. Geochemical data was collected and analysed for the type of kerogen, total organic content (TOC), generation potential and thermal maturity. These parameters enabled a gas-in-place resource estimation to be made for each of the formations. The TOC data from various wells were validated by using petrophysical logs and the ΔlogR method. In comparison with the geochemical data, both values produced a good match, validating both sets of data. The three layers were ranked according to their geochemical parameters and any petrophysical or geomechanical characteristics. It was identified that the Wooramel Group contains the best quality source rocks, followed by the Byro Group. The Gneudna Formation was found to have poor quality source rocks. The Monte Carlo method by Crystal Ball was selected to estimate the probabilistic resources of these three layers. According to the P50 estimations, the Byro Group, Wooramel Group and the Gneudna Formation contained resources of 51.6 tcf, 40.1 tcf and 1.4 tcf, respectively.
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Ekundayo, Jamiu M., and Reza Rezaee. "Numerical Simulation of Gas Production from Gas Shale Reservoirs—Influence of Gas Sorption Hysteresis." Energies 12, no. 18 (September 4, 2019): 3405. http://dx.doi.org/10.3390/en12183405.
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The true contribution of gas desorption to shale gas production is often overshadowed by the use of adsorption isotherms for desorbed gas calculations on the assumption that both processes are identical under high pressure, high temperature conditions. In this study, three shale samples were used to study the adsorption and desorption isotherms of methane at a temperature of 80 °C, using volumetric method. The resulting isotherms were modeled using the Langmuir model, following the conversion of measured excess amounts to absolute values. All three samples exhibited significant hysteresis between the sorption processes and the desorption isotherms gave lower Langmuir parameters than the corresponding adsorption isotherms. Langmuir volume showed positive correlation with total organic carbon (TOC) content for both sorption processes. A compositional three-dimensional (3D), dual-porosity model was then developed in GEM® (a product of the Computer Modelling Group (CMG) Ltd., Calgary, AB, Canada) to test the effect of the observed hysteresis on shale gas production. For each sample, a base scenario, corresponding to a “no-sorption” case was compared against two other cases; one with adsorption Langmuir parameters (adsorption case) and the other with desorption Langmuir parameters (desorption case). The simulation results showed that while gas production can be significantly under-predicted if gas sorption is not considered, the use of adsorption isotherms in lieu of desorption can lead to over-prediction of gas production performances.
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Lebega, Olga. "FACTORS AND GEOLOGICAL AND ECONOMIC INDICATORS THAT MEASURE GAS AND SHALE DEPOSITS VALUE." Economic Analysis, no. 27(2) (2017): 162–71. http://dx.doi.org/10.35774/econa2017.02.162.
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Introduction. The article investigates the natural geological, technical, technological, economic and environmental conditions of the economic activity concerning the exploration and mining of natural gas from shale formations. Purpose. The article aims to is the identify, characterize and classify the factors that determine the value of natural gas fields which are connected with the shale rocks. Particular attention is given to the characterization of parameters that allow to carry out a quantitative assessment of the impact of these factors on the formation of spendings and the efficiency of shale gas extraction processes. The method (methodology). The methodological basis of the study is a set of scientific methods. Among them we can single out method of theoretical generalization, method of details, method of grouping, method of comparison, method of graphics, systems and factor methods. Results. It has been worked out the classification of the factors and parameters that determine the value and effectiveness of the exploration and development of deposits of natural gas which are connected with shale formations. The identified factors and indicators for determination their quantitative measurement are divided into four groups: natural and geological group, physical and chemical group, technical and technological group, economic and environmental group. In each group some specific factors and indicators and methodological approaches for their quantitative characterization and evaluation are identified and described.
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Shar, Abdul Majeed, Waheed Ali Abro, Aftab Ahmed Mahesar, and Kun Sang Lee. "Simulation Study to Evaluate the Impact of Fracture Parameters on Shale Gas Productivity." April 2020 39, no. 2 (April 1, 2020): 432–42. http://dx.doi.org/10.22581/muet1982.2002.19.
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The production from shale gas reservoirs has significantly increased due to technological advancements. The shale gas reservoirs are very heterogeneous and the heterogeneity has a significant effect on the quality and productivity of reservoirs. Hence, it is essential to study the behavior of such reservoirs for accurate modelling and performance prediction. To evaluate the impact of fracture parameters on shale gas reservoir productivity using CMG (Computer Modelling Group) stars simulation software was the main objective of this study. In this paper, a comprehensive analysis considering an example shale gas reservoir was conducted for production performance analysis considering uniform and non-uniform fractures configurations. Several simulations were performed by considering the multi-stage hydraulically fractured reservoir. The sensitivities conducted includes the different cases of moderate and severe heterogeneity along with variable fractures half-length, effect of changing fracture spacing, variable fracture conductivities. The simulation results showed that by increasing conductivity of fracture increases the gas production rate significantly. Moreover, cases of reservoir permeability heterogeneity were analyzed which show the significant effect on gas rate and on cumulative gas production. The results of this study can be used to improve the effectiveness in designing and developing of shale gas reservoirs and also to improve the accuracy of analyzing heterogeneous shale gas reservoir performance.
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Johnson, Ray, Geoff Hokin, David Warner, Rod Dawney, Mike Dix, and Tim Ruble. "An emerging shale gas play in the Northern Territory." APPEA Journal 52, no. 2 (2012): 672. http://dx.doi.org/10.1071/aj11086.
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As attention to unconventional oil and gas resources increases, historical oil and gas flows in shale reservoirs across the world are being given renewed attention. Such is the case of the shaly and carbonate deposits of the McArthur and Nathan groups in the Northern Territory. The Batten Trough is a Proterozoic depocenter with potential for a shale gas play in the Barney Creek Shale and potential for conventional gas accumulations in the underlying Coxco Dolomite. This Barney Creek Shale gas play is evidenced by a number of mineral exploration drill holes that encountered live oil and gas shows within the McArthur Group. The most prominent was a mineral exploration hole drilled at the Glyde River prospect by Amoco in 1979. This well reportedly flowed gas and condensates at 140 psi for six months before it was sealed at the surface, which certainly shows permeability values greater than micro-darcies reported for many North American shale plays; thus, an exploration program of this prospective area has been planned by Armour Energy in EP 171 on several targets adjacent to the Emu Fault Zone near both Glyde and Caranbirini, along with other anticline related targets adjacent to the Abner Range. This extended abstract details how the targets were identified, the plan for data acquisition (e.g. seismic, drilling, logging and testing), and the proposed completion strategy to test this highly prospective target.
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Liu, Qing-You, Lei Tao, Hai-Yan Zhu, Zheng-Dong Lei, Shu Jiang, and John David McLennan. "Macroscale Mechanical and Microscale Structural Changes in Chinese Wufeng Shale With Supercritical Carbon Dioxide Fracturing." SPE Journal 23, no. 03 (December 14, 2017): 691–703. http://dx.doi.org/10.2118/181369-pa.
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Summary Waterless fracturing for shale-gas exploitation using supercritical carbon dioxide (scCO2) is both effective and environmentally friendly, and has become an extensive research topic. Previous researchers have focused on the chemical and physical properties and microstructure of sandstone, carbonate, and shale caprock, rather than on the properties of shale-gas formations. The macroscale mechanical properties and microscale fracture characteristics of Wufeng Shale exposed to scCO2 (at greater than 31.8°C and 7.29 MPa) are still not well-understood. To study the macroscale and microscale changes of shale subjected to scCO2, we obtained Chinese Wufeng Shale crops (Upper Ordovician Formation) from Yibin, Sichuan Basin, China. The shale samples were divided into two groups. The first group was exposed to scCO2, and the second group was exposed to nitrogen (N2). Scanning-electron-microscope (SEM) and X-ray-diffraction (XRD) images were taken to study the original microstructure and mineral content of the shale. To study the macroscale mechanical changes of Wufeng Shale immersed in scCO2 or N2 for 10 hours, triaxial tests with controlled coring angles were conducted. SEM and XRD images were taken after the triaxial tests. In the SEM images, tight bedding planes and undamaged minerals (with sharp edges and smooth surfaces) were found in N2-treated samples both before and after testing, indicating that exposure to N2 did not affect the microstructures. However, the SEM images for the microstructure scCO2-treated samples before and after testing were quite different. The bedding planes were damaged, which left some connected microfractures and corrosion holes, and some mineral types were broken into small particles and left with uneven mineral surfaces. This shows that scCO2 can change rock microstructures and make some minerals (e.g., calcite) fracture more easily. The complex microscale fractures and the decrease in strength for scCO2-treated shale aid the seepage and gathering of gas, enhancing shale-gas recovery. Knowledge of the multiscale physical and chemical changes of shale exposed to scCO2 is not only essential for scCO2 fracturing, but it is also important for scCO2 jets used to break rock and for the geological storage of CO2.
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Higley, Debra, Catherine Enomoto, and Heidi Leathers-Miller. "Controls on Petroleum Resources for the Devonian Marcellus Shale in the Appalachian Basin Province, Kentucky, West Virginia, Ohio, Pennsylvania, and New York." Mountain Geologist 56, no. 4 (October 1, 2019): 323–64. http://dx.doi.org/10.31582/rmag.mg.56.4.323.
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Greater than 33 trillion cubic feet of gas, 68 million barrels of natural gas liquids (NGL), and 192 million barrels of water have been produced from the Middle Devonian Marcellus Shale of the Hamilton Group in the Appalachian Basin. These volumes are from more than 11,700 non-commingled wells. Areas of greatest production and future potential for gas and NGL from the Marcellus Shale are within and near the northeast-trending Rome trough in northern West Virginia and Pennsylvania. Southernmost New York, eastern Ohio, western Virginia, and Maryland also contain petroleum potential and (or) reserves. A confluence of factors enhances gas and NGL reserves and resources in the Marcellus Shale. These include (1) brittleness based on lithofacies composition; (2) thickness and distribution of brittle and organic-rich shale; (3) measured thermal maturity of 1% vitrinite reflectance and greater; (4) at least 2 weight percent total organic carbon; (5) dense and complex fracturing and faulting; (6) presence of evaporite beds in the underlying Silurian Salina Group; (7) potential overpressure; (8) current depths of 1,370 m (4,500 ft) and greater, and (9) predominately horizontal wells with laterals that are oriented to the northwest or southeast, or roughly perpendicular to the direction of maximum horizontal stress, and that cross major fault and fracture sets.
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Ndlovu, M. S., M. Demlie, and M. Butler. "Hydrogeological setting and hydrogeochemical characteristics of the Durban Metropolitan District, eastern South Africa." South African Journal of Geology 122, no. 3 (September 1, 2019): 299–316. http://dx.doi.org/10.25131/sajg.122.0026.
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Abstract Population and economic growth within the Durban Metropolitan region in eastern South Africa have increased the demand for water supply. Though the region’s water supply comes mainly from surface water sources, the ever-increasing demand means that all available water supply sources including groundwater will be looked at, particularly in the peri-urban areas. However, the state of the groundwater resource in the region is poorly understood. This study aims to contribute towards improved understanding of the state of groundwater resources in the Metropolitan District through an integrated hydrogeological, hydrochemical and environmental isotope investigations. Results of the hydrogeological and hydrogeochemical characterization identified at least five hydrostratigraphic units of varying hydraulic and hydrochemical characteristics: the weathered and fractured basement aquifers of the Mapumulo Group, Oribi Gorge, Mzimlilo and Mkhomazi Suites characterized by average borehole yield and transmissivity (T) of 1.2 l/s, and 3.9 m2/day, respectively, and hydrochemical facies of Ca-Mg-HCO3;the fractured Natal Group sandstone characterised by average borehole yield and hydraulic conductivity (K) of 5.6 l/s and 2.8 m/day, respectively and with Na-Mg-HCO3-Cl dominant water type;the fractured aquifers of the Dwyka Group diamictite and tillite characterized by average borehole yield of 0.4 l/s, transmissivity of 1.3 m2/day and Na-Cl-HCO3 dominant water type;the Vryheid Formation of the Ecca Group characterized by average borehole yield of 2.5 l/s, T of 4.9 m2/day, K values 0.17 m/day, and Na-Cl-HCO3 water type. The Pietermaritzburg Formation of the Ecca Group is characterized by a shale lithology with very low borehole yields and average transmissivity of 0.28 m2/d with Na-Ca-Cl dominant water type. It is considered as an aquiclude than an aquifer;the intergranular aquifer of the Maputaland Group which comprises the Bluff, Berea type sands and harbour beds (recent alluvium and estuarine deposits). These units collectively have average borehole yield of 14.8 l/s, transmissivity of up to 406 m2/day and a mainly Na-Cl-HCO3 hydrochemical signature. The region receives mean annual precipitation (MAP) of 935 mm/yr of which an estimated 6.6% recharges the various aquifers. Environmental isotope data (2H, 18O and 3H) indicated that groundwater is recharged from modern precipitation. High concentrations of tritium, as high as 92 T.U., measured around landfill sites, indicates groundwater contamination from leachate leakage posing a risk to human and environmental health.
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Lits, Brieuc. "Astroturf lobbying in the EU: The case of shale gas exploration." Networking Knowledge: Journal of the MeCCSA Postgraduate Network 12, no. 2 (September 12, 2019): 3–18. http://dx.doi.org/10.31165/nk.2018.112.521.
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This paper seeks to shed light on astroturf lobbying, a strategy that recently invaded the European public. Its purpose is to simulate citizen support for a specific issue whilst keeping its identity secret. The public sphere is envisaged as a constellation of issues around which gravitate interest groups that try to influence the debate, and doing so by carefully frame their messages. In the case of the shale gas debate in the EU, the question that emerged is to see whether astroturf groups convey the economic frames used by the oil and gas companies they represent, or if they mobilised environmental frames such as shale gas opponents. Results show that the astroturf group mostly emphasized the safety of hydraulic fracturing and tried to counter the environmental frames of competing NGOs.
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Cui, Yun Hai, Hai Ping Yang, Jian Feng, and Yu Song. "Application of Cementing Technology for Shale Gas Horizontal Well in Jiaoshiba Block of Fuling Area." Applied Mechanics and Materials 733 (February 2015): 130–35. http://dx.doi.org/10.4028/www.scientific.net/amm.733.130.
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In response to the difficulties happened during shale gas horizontal well cementation in shale reservoir of Jiaoshiba Long maxi group in Fuling, through continuous laboratory tests and analysis on site, this paper achieves the following research results: the method of enhancing cleaning efficiency by further improving ahead fluid system; the method of reducing the shrinkage of cement rock and improving anti-gas channeling ability of cement slurry by perfecting the cement slurry system; method of strengthening the supervision of the placement of centralizers by placing the centralizers reasonably; water substitution method with large flow rate of whole well. All these methods form a comprehensive technology, which is applied in 7 wells, such as JY 29-4HF, JY 8-1HF, and JY 15-2HF and so on. All the cement evaluations are great, which indicates that the comprehensive technology is suitable for shale gas horizontal well cementation in Jiaoshiba.
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Miller, Douglas E., Steve A. Horne, and John Walsh. "Precise inversion of logged slownesses for elastic parameters in a gas shale formation." GEOPHYSICS 77, no. 4 (July 1, 2012): B197—B206. http://dx.doi.org/10.1190/geo2011-0334.1.
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Dipole sonic log data recorded in a vertical pilot well and the associated production well are analyzed over a [Formula: see text]-ft section of a North American gas shale formation. The combination of these two wells enables angular sampling in the vertical direction and over a range of inclination angles from 54° to 90°. Dipole sonic logs from these wells show that the formation’s average properties are, to a very good approximation, explained by a transversely isotropic medium with a vertical symmetry axis and with elastic parameters satisfying [Formula: see text], but inconsistent with the additional ANNIE relation ([Formula: see text]). More importantly, these data clearly show that, at least for fast anisotropic formations such as this gas shale, sonic logs measure group slownesses for propagation with the group angle equal to the borehole inclination angle. Conversely, the data are inconsistent with an interpretation that they measure phase slownesses for propagation with the phase angle equal to the borehole inclination angle.
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Liu, Yang. "Remote Sensing of Forest Structural Changes Due to the Recent Boom of Unconventional Shale Gas Extraction Activities in Appalachian Ohio." Remote Sensing 13, no. 8 (April 9, 2021): 1453. http://dx.doi.org/10.3390/rs13081453.
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Dense unconventional shale gas extraction activities have occurred in Appalachian Ohio since 2010 and they have caused various landcover changes and forest fragmentation issues. This research investigated the most recent boom of unconventional shale gas extraction activities and their impacts on the landcover changes and forest structural changes in the Muskingum River Watershed in Appalachian Ohio. Triple-temporal high-resolution natural-color aerial images from 2006 to 2017 and a group of ancillary geographic information system (GIS) data were first used to digitize the landcover changes due to the recent boom of these unconventional shale gas extraction activities. Geographic object-based image analysis (GEOBIA) was then employed to form forest patches as image objects and to accurately quantify the forest connectivity. Lastly, the initial and updated forest image objects were used to quantify the loss of core forest as the two-dimensional (2D) forest structural changes, and initial and updated canopy height models (CHMs) derived from airborne light detection and ranging (LiDAR) point clouds were used to quantify the loss of forest volume as three-dimensional (3D) forest structural changes. The results indicate a consistent format but uneven spatiotemporal development of these unconventional shale gas extraction activities. Dense unconventional shale gas extraction activities formed two apparent hotspots. Two-thirds of the well pad facilities and half of the pipeline right-of-way (ROW) corridors were constructed during the raising phase of the boom. At the end of the boom, significant forest fragmentation already occurred in both hotspots of these active unconventional shale gas extraction activities, and the areal loss of core forest reached up to 14.60% in the densest concentrated regions of these activities. These results call for attention to the ecological studies targeted on the forest fragmentation in the Muskingum River Watershed and the broader Appalachian Ohio regions.
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Materka, Edyta. "Kashubians versus Global Energy Companies: A Global-Local Encounter at the Heart of Poland's Shale Gas Revolution." Human Geography 5, no. 2 (July 2012): 72–92. http://dx.doi.org/10.1177/194277861200500206.
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In 2011, Poland jumped into the ‘shale gas revolution’ with global energy companies and American geopolitical interests at its side. Poland's northern province of Pomerania, split into hundreds of shale gas exploration concessions, became known as the ‘United States of American Oil Companies’. This paper explores the global-local encounter between global energy companies and the Kashubians, an ethnic-group minority in Pomerania. It takes a multi-scalar approach to introduce the (inter) national discourses legitimating and challenging shale gas exploration as green energy policy. Then, it surveys Kashubians’ local discourses against shale gas exploration in their agrarian movement to protect ancient, ethnic lands, rural environments, agricultural livelihoods and private economic interests. A disconnect is demonstrated between the discourses on the global and local spheres of the debate. I conclude that global-local encounters are violent desecrations of the local when government institutions are too politically involved in the economic benefits of the global encroachment. Due to the failure of local representative democracy, the ‘local’ is forced to seek political networks across the spatial grid that may or may not help gain leverage in their local struggles. Lastly, postsocialist ethnographers are encouraged to link minority voices in Central and Eastern European States to the global debates.
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Parvin, Afroza, A. S. M. Woobaidullah, and Md Jamilur Rahman. "Sequence stratigraphic analysis of the Surma Group in X Gas Field, Surma Basin, Bengal Delta." Journal of Nepal Geological Society 58 (June 24, 2019): 39–52. http://dx.doi.org/10.3126/jngs.v58i0.24572.
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This study builds a high-resolution sequence stratigraphic framework for the Surma Group in the X Gas field. At first, electrofacies and depositional sequences were interpreted from wire line logs. Then, the field wide configurations of these sequences have been identified in seismic using reflection terminations (of flap, onlap, top lap and down lap relationship). Finally, wire line log and seismic interpretations were integrated to establish sequences stratigraphic framework in the Surma Group.
Electrofacies analysis has revealed four major facies associations namely: (i) Bell shaped fining upward facies corresponds to retrogradational shoreface to tidal flat deposits, (ii) Funnel shaped coarsening upward facies corresponds to progradational shoreface to tidal flat, (iii) Cylindrical aggradational facies interpreted as stacked channel and (iv) Symmetrical or Bow shaped facies corresponds to heterolithic unit. The succession of Surma group of about 3100+ m has been divided into twelve depositional sequences. With exception of depositional sequence 1, 11 and 12, most of them are composed of three system tracts: sandy lowstand system tract, shaley transgressive system tract and heterolithic to shaley highstand system tract. Repetitive occurrence of incised valley, shoreface sand as well as tidal channel sand separated by transgressive system tract shelfal mud resulted in sand-shale alternation in the Surma Group. The lower depositional sequences (up to sequence-6) are shale dominated and equivalent to the Lower Surma Group. The upper six sequences are sand dominated, have more channel incisions and sequence boundary representing the Upper Surma Group
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Bao, Yuan, Yiwen Ju, Zhongshan Yin, Jianlong Xiong, Guochang Wang, and Yu Qi. "Influence of reservoir properties on the methane adsorption capacity and fractal features of coal and shale in the upper Permian coal measures of the South Sichuan coalfield, China." Energy Exploration & Exploitation 38, no. 1 (September 22, 2019): 57–78. http://dx.doi.org/10.1177/0144598719877527.
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Pore structure plays an essential role in the reservoir heterogeneity and methane adsorption capacity. Significant progress has been made in the pore structure classification of porous materials (such as coal and shale). Considering the pore structure characterization of the coal measures and the measuring range of high-pressure mercury intrusion porosimetry and low-pressure N2/CO2 gas adsorption, an integrated classification for coal and shale is provided. They are micropore (<2 nm), mesopore (2–100 nm), macropore A (100 nm–1 µm), macropore B (1–10 µm), and micro-fracture (>10 µm). For coal and shale samples from Guxu mining area, the micropores and mesopores largely control the gas adsorption while micro-fractures and macropore B are significant for the storage and flow of free gas. The fractal dimensions calculated from limited N2 adsorption data are not suitable for the coal samples which are not developed in mesopore and macropore A; these samples are precisely corresponding to the N2 adsorption/desorption isotherms of group B (reversible isotherm). Furthermore, the main factors influencing the methane adsorption capacity of coal and shale in the coal measures are micropore frequency, micro-fracture width, clay mineral composition, and total organic carbon content.
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Xu, Chenxi, Haitao Xue, Qi Dong, Shuangfang Lu, Guohui Chen, Yuying Zhang, Jinbu Li, et al. "CH4 and CO2 Adsorption Mechanism in Kaolinite Slit Nanopores as Studied by the Grand Canonical Monte Carlo Method." Journal of Nanoscience and Nanotechnology 21, no. 1 (January 1, 2021): 108–19. http://dx.doi.org/10.1166/jnn.2021.18445.
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To confirm the rules and transformation conditions of shale gas adsorption and establish a model for evaluating the adsorption capacity of shale gas quantitatively, it is necessary to reveal the shale gas adsorption mechanism. The adsorption mechanism of CH4 and CO2 in Kaolinite slit nanopores has been studied under the simulated conditions of 90 °C and 30 or 50 MPa by the grand canonical Monte Carlo (GCMC) method. The results indicate that CH4 is controlled only by the Van der Waals forces on the mineral surface because CH4 is nonpolar, while CO2 is controlled by both Van der Waals forces and Coulomb forces due to a certain electric quadrupole moment, which makes the adsorption capacity of CO2 on kaolinite greater than that of CH4. Due to the overlapping adsorption potential on the kaolinite surface of micropores (1 nm), the peak of the density profile is higher in the micropores than the peak in the mesopores (4 nm), resulting in the filling effect in the micropores. On the surface of the silicon-oxygen octahedron, the adsorption site for CH4 and CO2 is in the center of the silicone hexagon-ring, and CO2 with a quadrupole moment shifts near the polar oxygen atoms. In contrast, the adsorption sites of CH4 are relatively dispersed on the surface of the aluminum-oxygen octahedron with a hydroxyl group, while the adsorption sites of CO2 are concentrated in the location of the aggregated oxygen atoms. When CH4 and CO2 coexist, CO2 tends to be adsorbed prior to CH4. With the proportion of CO2 increasing, the competitive adsorption effect is gradually aggravated, which suggests the rationality of injecting CO2 to improve the recovery efficiency of shale gas. These findings can provide theoretical support for shale gas exploration and development.
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He, Pei, Li Jun Cheng, Ming Gong, Ke Xiong Song, and Yu Zhu. "Flow Field Characteristic Study of Horizontal Section PDC Bit in the Southeast of Chong Qing Wu Feng – Long Ma Xi Shale Reservoir." Applied Mechanics and Materials 316-317 (April 2013): 807–14. http://dx.doi.org/10.4028/www.scientific.net/amm.316-317.807.
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The Southeast of Chong Qing Wu Feng – Long Ma Xi group is a national shale gas exploration and development key formation. Shale contains high clay minerals,It makes serious borehole instability and large of cuttings transport.The segment length of the horizontal well, is easy to form cuttings bed.Strong shale plastic makes ROP low. In this paper, It calculates the closed N-S equation based on the k-ε two-equation model by using numerical simulation method,studys the Φ 215.9 mm PDC bit´s nozzle diameters. When the center nozzle diameter is 12.70mm in a long horizontal section shale reservoir,It reachs the diameter of external nozzle is 8.74mm ~ 11.13mm optimal for PDC bit downhole flow field.The center and peripheral nozzle diameter of PDC bit should have a certain class difference, 2 ~ 5 grades is optimal. When the peripheral nozzle diameter is 11.13mm, the center of the nozzle diameter should be greater than or equal to 11.13mm for PDC bit flow field.The center nozzle diameter can not be smaller than the external diameter of the nozzle. The study can guide the shale reservoir horizontal section PDC bit design,improve ROP and cleaning rock,reduce the probability of cuttings settlement in the horizontal section.
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Guo, Sen, Yan-Ming Zhu, Yu Liu, and Xin Tang. "Characteristics and Controlling Factors of Nanopores of the Niutitang Formation Shale from Jiumen Outcrop, Guizhou Province." Journal of Nanoscience and Nanotechnology 21, no. 1 (January 1, 2021): 284–95. http://dx.doi.org/10.1166/jnn.2021.18455.
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This paper studies the characteristics and controlling factors of nanopores in organic-rich shale in the Niutitang Formation. Six samples were collected from the bottom of the formation at the Jiumen Outcrop, Guizhou Province. Experiments were conducted to investigate the pore structures of these high-maturity shale samples. The TOC contents vary between 4.81–17.51% with an average of 10.18%. The XRD data show that these samples are dominated by quartz (44%–71%), with a significant amount of clay minerals, such as illite, with a content of 8%–27.5%. Based on the low-pressure liquid N2 sorption measurements, the pore structures can be divided into two groups. Group A including samples of N-2, N-3 and N-4, mainly develop slit-shaped pores, mesopores and macropores. Group B shown from samples N-1, N-5 and N-6, are mainly composed of narrow slitlike pores, which may provide more space for shale gas than slit-shaped pores. The mesopores, macropores, porosity and specific surface areas of group B are more developed than those of group A. With the comparison of pore structures in shales with various organic matter and mineral contents, the dissolution of quartz and feldspar can be the important factor controlling pore development. The evolution of diagenesis is closely related to pore evolution. This diagenesis has various types and complex effects on the pores, mainly including compaction, dissolution and cementation.
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Thompson, Mark. "THE DEVELOPMENT GEOLOGY OF THE TUBRIDGI GAS FIELD." APPEA Journal 32, no. 1 (1992): 44. http://dx.doi.org/10.1071/aj91005.
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The Tubridgi Gas Field is located in the south of the Barrow Sub-basin, onshore in the Carnarvon Basin, Western Australia. The accumulation was discovered by Pan Pacific Petroleum NL in June 1981 with the drilling of the Tubridgi-1 well. Subsequent to Tubridgi-1, eight appraisal wells have been drilled, six of which were successful. The latest wells, Tubridgi-7 and-8, drilled in September 1990 by current operator Doral Resources NL, have enabled geological and petrophysical models for the field to be refined. These models were utilised for reserve determinations which were used to negotiate gas supply contracts and secure project financing to ensure the fields successful commercial development. Tubridgi gas is trapped within a broad, low relief, northeast-trending anticlinal closure. Reservoirs for the accumulation are the Middle to Upper Triassic Mungaroo Formation, Upper Cretaceous Flacourt Formation of the Barrow Group and Birdrong Sandstone of the Cretaceous Winning Group. All three units exhibit porosities averaging 29-30 per cent, with permeabilities of 3-16 D in the Mungaroo and Flacourt Formations and 157 mD in the Birdrong Sandstone. Vertical seal for the accumulation is the Muderong Shale of the Winning Group.The Tubridgi Gas Field is the first onshore Carnarvon Basin hydrocarbon accumulation to be commercially developed. Gas production into the Dampier-to-Bunbury Natural Gas Pipeline commenced on 26 September 1991 and within one month had reached contract volumes averaging 22 MMCFD (623 000 m3/d). Field life is anticipated to be ten years.
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Hall, Lisa, Tony Hill, Liuqi Wang, Dianne Edwards, Tehani Kuske, Alison Troup, and Chris Boreham. "Unconventional gas prospectivity of the Cooper Basin." APPEA Journal 55, no. 2 (2015): 428. http://dx.doi.org/10.1071/aj14063.
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The Cooper Basin is an Upper Carboniferous–Middle Triassic intracratonic basin in northeast SA and southwest Queensland. The basin is Australia's premier onshore hydrocarbon-producing province and is nationally significant due to its provision of domestic gas for the east coast gas market. Exploration activity in the region has recently expanded with numerous explorers pursuing newly identified unconventional hydrocarbon plays. While conventional gas and oil prospects can usually be identified by 3D seismic, the definition and extent of the undiscovered unconventional gas resources in the basin remain poorly understood. This extended abstract reviews the hydrocarbon prospectivity of the Cooper Basin with a focus on unconventional gas resources. Regional basin architecture, characterised through source rock distribution and quality, demonstrates the abundance of viable source rocks across the basin. Petroleum system modelling, incorporating new compositional kinetics, source quality and total organic carbon (TOC) map, highlight the variability in burial, thermal and hydrocarbon generation histories between depocentres. The study documents the extent of a number of unconventional gas play types, including the extensive basin-centred and tight gas accumulations in the Gidgealpa Group, deep-dry coal gas associated with the Patchawarra and Toolachee formations, as well as the less extensive shale gas plays in the Murteree and Roseneath shales.
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Sloan, M. W. "FLOUNDER — A COMPLEX INTRA-LATROBE OIL AND GAS FIELD." APPEA Journal 27, no. 1 (1987): 308. http://dx.doi.org/10.1071/aj86025.
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The Flounder Field is the deepest producing field in the Gippsland Basin. Since discovery in 1968 by Flounder 1, five delineation wells and 15 development wells have been drilled on the structure. The main T-1.1 oil and gas reservoir is trapped at the crest of a highly faulted anticline within the Latrobe Group. The Flounder structure has a complex deformational history with the Latrobe Group sequence undergoing two main phases of deformation. Late Cretaceous to Late Paleocene north-west trending normal faults are overprinted by a Late Eocene to mid Miocene north-east trending anticline. Generally within the Latrobe sequence in the Gippsland Basin, faulting destroys the integrity of the anticlinal features by breaking the lateral continuity of potential intra-formational seals. However, at the Flounder Field, the estuarine sands of the T-1.1 reservoir are overlain by a marine shale of adequate thickness to provide an effective seal across the faults.The T-1.1 oil and gas reservoir has excellent reservoir parameters. Separate gas caps are trapped in the multiple faulted crests of the structure and have had a major influence on the development of the field due to the resultant variation in gross oil column thickness.In addition, several small oil accumulations have been structurally and stratigraphically trapped in sediments filling the Tuna-Flounder Channel and the deeper Latrobe Group sequence.The Flounder Field commenced production in December 1984. Current estimated reserves for the T-1.1 reservoir are 155 billion cubic feet (BCF) (wet) gas and 115 million barrels (MMB) of oil, a dramatic increase over the 1978 pre-development estimated reserves of 86 BCF (wet) gas and 57 MMB oil.
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Latif, Khalid, Muhammad Hanif, Syed Anjum Shah, Irfan U. Jan, Muhammad Younis Khan, Hamid Iqbal, Abdullah Khan, Syed Mamoon Siyar, and Mohibullah Mohibullah. "Source rock potential assessment of the Paleocene coal and coaly shale in the Attock-Cherat Range of Pakistan." Journal of Petroleum Exploration and Production Technology 11, no. 6 (May 11, 2021): 2299–313. http://dx.doi.org/10.1007/s13202-021-01172-8.
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AbstractIn this study the hydrocarbon generation potential of the coal and coaly shale samples collected from coal mines in Attock-Cherat Range of Pakistan is optically and analytically evaluated. These samples, representing the Paleocene Hangu Formation, are analyzed across a range of thermal maturity stages to understand their hydrocarbon generation potential. The visual examination of maceral type and values of vitrinite reflectance have been considered while interpreting the geochemical results for the coal and associated sediments from the Paleocene Hangu Formation. The maceral group is dominated by vitrinite, mainly collodetrinite, followed by inertinite and liptinite, and suggests Type III kerogen for the samples. The geochemical parameters suggest that the samples are post mature, however, the vitrinite reflectance measurements show late mature conditions for a gas-prone generation. The overall petrographical and geochemical data suggest that the coal and coaly shale appear to occupy the gas window and fall in the dry gas zone. Based on the maceral types and Rock–Eval data, an anoxic to terrestrial environment is inferred for the deposition of the coal and associated sediments. The vitrinite reflectance, Rock–Eval pyrolysis, and the type and frequency of macerals show that the coal is of good quality, i.e., medium to high volatile bituminous and hard brown coal, mature, and is lying in the gas window. Oxygen index is continuously low throughout the analyzed interval, which further supports that the coal is of good quality.
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Wen, Tao, M. Clara Castro, Jean-Philippe Nicot, Chris M. Hall, Daniele L. Pinti, Patrick Mickler, Roxana Darvari, and Toti Larson. "Characterizing the Noble Gas Isotopic Composition of the Barnett Shale and Strawn Group and Constraining the Source of Stray Gas in the Trinity Aquifer, North-Central Texas." Environmental Science & Technology 51, no. 11 (May 18, 2017): 6533–41. http://dx.doi.org/10.1021/acs.est.6b06447.
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Apergis, Nicholas, Tasawar Hayat, and Tareq Saeed. "Fracking and infant mortality: fresh evidence from Oklahoma." Environmental Science and Pollution Research 26, no. 31 (October 11, 2019): 32360–67. http://dx.doi.org/10.1007/s11356-019-06478-z.
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Abstract This paper explores the impact of shale gas and oil fracking wells on infants’ health at birth across Oklahoma counties. The empirical analysis makes use of the Dumitrescu-Hurlin causality test, as well as the (long-run) Pooled Mean Group method. The results clearly document that there is a unidirectional relationship between fracking activities and three alternative indexes of infants’ health at birth, as well as a significant impact of fracking on infants’ health indicators. In addition, the results illustrate the substantial role of fracking through the drinking water quality channel.
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He, Jin Gang, Kao Ping Song, Jing Yang, Song He, Li Yan Sun, Di He, and Xin Zeng. "The Effect of the Fracture Surface for Stress Sensitivity in Shale Reservoir." Advanced Materials Research 779-780 (September 2013): 1427–30. http://dx.doi.org/10.4028/www.scientific.net/amr.779-780.1427.
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Due to the characteristics of the ultra-low permeability, facture system becomes the key to the deployment of shale gas, and the following stress sensitivity damage will restrict the engineering effect. The essay takes the Niutitang group of black shale as the research object, which carried out for natural fracture rock sample and artificial fracture rock sample study of stress sensitivity evaluation in order to compare differences between them. The experimental results show that the natural fracture rock sample is medium to strong stress sensitivity, while the artificial fracture rock sample is from strong to the extreme strong stress sensitivity. Natural fracture is more flattening than the artificial fracture formation because of leaching action. The processed SEM image can reflect structure information on the two-dimensional surface. Its surface structure conforms to the fractal structure characteristics. Whats more, fracture it can also reflect the three-dimensional information of the fracture surface through grey value, which provides a new imaging method for the research of surface microstructure for fracture.
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Khatiwada, Murari, G. Randy Keller, and Kurt J. Marfurt. "A window into the Proterozoic: Integrating 3D seismic, gravity, and magnetic data to image subbasement structures in the southeast Fort Worth basin." Interpretation 1, no. 2 (November 1, 2013): T125—T141. http://dx.doi.org/10.1190/int-2013-0041.1.
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The Fort Worth basin (FWB) is one of the most fully developed shale gas fields in North America. Although there are hundreds of drilled wells in the basin, almost none of them reach the Precambrian basement. Imaged by perhaps 100 3D seismic surveys, the focus on the relatively shallow, flat-lying Barnett Shale objective has resulted in little published work on the basement structures underlying the Lower Paleozoic strata. Subtle folds and systems of large joints are present in almost all 3D seismic surveys in the FWB. At the Cambro-Ordovician Ellenburger level, these joints are often diagenetically altered and exhibit collapse features at their intersections. We discovered how the basement structures relate to overlying Paleozoic reservoirs in the Barnett Shale and Ellenburger Group. In support of our investigation, the Marathon Oil Company provided a high-quality, wide-azimuth, 3D seismic data near the southeast fringe of the FWB. In addition to the seismic volume, we integrated the seismic results with gravity, magnetic, well log, and geospatial data to understand the basement and subbasement structures in the southeast FWB. Major tectonic features including the Ouachita frontal thrust belt, Lampasas arch, Llano uplift, and Bend arch surround the southeast FWB. Euler deconvolution and integrated forward gravity modeling helped us extend our interpretation beyond the 3D seismic survey into a regional context.
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Uvarova, Yulia, Alexey Yurikov, Marina Pervukhina, Maxim Lebedev, Valeriya Shulakova, Ben Clennell, and David Dewhurst. "Microstructural characterisation of organic-rich shale before and after pyrolysis." APPEA Journal 54, no. 1 (2014): 249. http://dx.doi.org/10.1071/aj13025.
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Organic-rich shales, traditionally considered as source rocks, have recently become an ambitious goal for the oil and gas industry as important unconventional reservoirs. Understanding of the initiation and development of fractures in organic-rich shales is crucially important as fractures could drastically increase the permeability of these otherwise low-permeable rocks. Fracturing can be induced by rapid decomposition of organic matter caused by either natural heating, such as emplacement of magmatic bodies into sedimentary basins, or thermal methods used for enhanced oil recovery. In this work the authors study fracture initiation and development caused by dry pyrolysis of Kimmeridge shale, which is characterised with a high total organic carbon content of more than 20%. X-ray diffraction (XRD) analysis exhibits high carbonate (both calcite and dolomite) and low clay (illite) content. Field emission gun scanning electron microscopy (FEG-SEM) shows that kerogen is presented either as a load-bearing matrix or as a filling of the primary porosity with pores being of micron size. Cylindrical samples of the Kimmeridge shale are heated up to temperatures in the range of 330–430°C. High-resolution X-ray microtomographic (micro-CT) images are obtained. The microtomographic images are processed using AVIZO (Visualization Sciences Group) to identify and statistically characterise large kerogen-filled pores and pre-existing and initiated cracks. The relationship between the total area of fractures and the temperature experienced by the sample has been obtained. Total organic carbon content is determined for samples subjected to heating experiments. This approach enables a quantitative analysis of fracture initiation and development in organic-rich shales during heating.
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Srivastava, Raj K., Sam S. Huang, and Mingzhe Dong. "Comparative Effectiveness of CO2 Produced Gas, and Flue Gas for Enhanced Heavy-Oil Recovery." SPE Reservoir Evaluation & Engineering 2, no. 03 (June 1, 1999): 238–47. http://dx.doi.org/10.2118/56857-pa.
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Summary A large number of heavy oil reservoirs in Canada and in other parts of the world are thin and marginal and thus unsuited for thermal recovery methods. Immiscible gas displacement appears to be a very promising enhanced oil recovery technique for these reservoirs. This paper discusses results of a laboratory investigation, including pressure/volume/temperature (PVT) studies and coreflood experiments, for assessing the suitability and effectiveness of three injection gases for heavy-oil recovery. The gases investigated were a flue gas (containing 15 mol % CO2 in N2), a produced gas (containing 15 mol?% CO2 in CH4), and pure CO2 . The test heavy-oil (14° API gravity) was collected from Senlac reservoir located in the Lloydminster area, Saskatchewan, Canada. PVT studies indicated that the important mechanism for Senlac oil recovery by gas injection was mainly oil viscosity reduction. Pure CO2 appeared to be the best recovery agent, followed by the produced gas. The coreflood results confirmed these findings. Nevertheless, produced gas and flue gas could be sufficiently effective flooding agents. Comparable oil recoveries in flue gas or produced gas runs were believed to be a combined result of two competing mechanisms—a free-gas mechanism provided by N2 or CH4 and a solubilization mechanism provided by CO2. This latter predominates in CO2 floods. Introduction A sizable number of heavy-oil reservoirs in Canada1 and in other parts of the world are thin and shaly. Some of these reservoirs are also characterized by low-oil saturation, heterogeneity, low permeability, and bottom water.2,3 For example, about 55% of 1.7 billion m3 of proven heavy-oil resource in the Lloydminster and Kindersley region in Saskatchewan, Canada, is contained in less than 5 m (15 ft.) pay zone and nearly 97% is in less than 10 m (30 ft.) pay zone.4,5 Primary and secondary methods combined recover only about 7% of the proven initial oil in place (IOIP).1 Such reservoirs are not amenable to thermal recovery methods: heat is lost excessively to surroundings and steam is scavenged by bottomwater zones.6,7 The immiscible gas displacement appears to be a very promising enhanced oil recovery (EOR) process for these thin reservoirs. The immiscible gas EOR process has the potential to access more than 90% of the total IOIP.1,7 It could, according to previous studies,6–12 recover up to an additional 30% IOIP incremental over that recovered by initial waterflood for some moderately viscous oils. For the development of a viable immiscible gas process applicable to moderately viscous heavy oils found in this sort of reservoirs, we selected three injection gases for study: CO2 reservoir-produced gas (RPG), and flue gas (FG) from power plant exhausts. Extensive literature is available on CO2 flooding for heavy-oil recovery, dealing with pressure/volume/temperature (PVT) behavior,3,6,7,13-15 oil recovery characteristics from linear and scaled models,3,6-8,10-12,15,16 numerical simulation, and field performance.17–19 However, only limited data are available on flue gas and produced gas flooding.20–22 To determine the most suitable gas for EOR application from laboratory investigations, we need knowledge of the physical and chemical interaction between gas, reservoir oil, and formation rock; and information on the recovery potential for various injection gases for a targeted oil. The test oil selected for this study was from the Senlac reservoir (14° API) located in northwest Saskatchewan (Lloydminster area). The PVT properties for the oil/injection gas mixtures were measured and compared. A comparative study of the oil recovery behavior for Senlac dead oil and Senlac reservoir fluid was carried out with different injection gases to assess their relative effectiveness for EOR. Senlac Reservoir Geology The Senlac oil pool is located within the lower Cretaceous sand/shale sequence of the Mannville Group. The Mannville thickens northward and lies unconformably on the Upper Devonian Carbonates of the Saskatchewan Group. The trapping mechanism for the oil is mainly stratigraphic. The lower Lloydminster oil reservoir is a wavy, laminated, very fine- to fine-grained, well sorted, and generally unconsolidated sandstone. It exhibits uniform dark oil staining throughout, interrupted by a number of shale beds of 2 to 9 m (6 to 27 ft) thick, which are distributed over the entire reservoir. The reservoir is overlain by a shale/siltstone/sandstone sequence and lies on a 3 m (9 ft) thick coal seam. The detailed reservoir (Senlac) data and operating characteristics are provided in Ref. 5. The reservoir temperature is 28°C (82.4°F) and the reservoir pressure varies between 2.5 and 4.1 MPa (363 and 595 psia). The virgin pressure of the reservoir at discovery was 5.4 MPa (783 psia) and the gas/oil ratio (GOR) was 16.2 sm3/m3 (89.8 sft3 /bbl). The reservoir matrix has a porosity of about 27.7% by volume and permeability of about 2.5 mD. The average water saturation is about 32% pore volume (PV). The pattern configuration for oil production is five-spot on a 16.2 ha (40 acre) drainage area. The estimated primary and secondary (solution gas and waterflood) recovery is 5.5% of the initial oil in place. Experiment Wellhead Dead Oil and Brine. Senlac wellhead dead oil and formation brine (from Well 16-35-38-27 W3M) were supplied by Wascana Energy, Inc. The oil was cleaned for the experiments by removal of basic sediment and water (BS&W) through high-speed centrifugation. The chemical and physical properties of cleaned Senlac stock tank oil are shown in Table 1. The formation brine was vacuum filtered twice to remove iron contamination from the sample barrels.
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Babikir, Ismailalwali A. M., Ahmed M. A. Salim, and Deva P. Ghosh. "Lithogeomorphological facies analysis of Upper Miocene coal-prone fluviodeltaic reservoirs, Northern Malay Basin." Interpretation 7, no. 3 (August 1, 2019): T565—T579. http://dx.doi.org/10.1190/int-2018-0103.1.
Full textAbstract:
The Group E stratigraphic unit is a significant gas producer in the Northern Malay Basin. However, due to the thinly bedded nature of the sandstone reservoirs, thick shale, and abundant coal beds, accurate seismic attributes interpretation of lithology and fluid prediction has been a daunting task. To address this problem, we have conducted an integrated seismic sedimentology workflow using spectral decomposition, color blending, waveform classification, prestack seismic inversion, and stratal slicing to characterize the lithogeomorphological facies of the coal-bearing reservoirs. On spectral decomposition and waveform classification maps, we clearly identified depositional elements such as the distributary channel, distributary mouth bar, subaqueous levee, and interdistributary fill. We computed the elastic properties through prestack seismic inversion to obtain good lithology discrimination between coal and gas-charged sandstone. Both lithologies are characterized by low acoustic impedance, but the compressional to shear velocity ratio ([Formula: see text]) of coal is high compared to gas-charged sandstone. The current interpretation indicated that the Group E interval was deposited in a delta plain setting. The varying flow directions of the distributary channels in the area support the hypothesis that describes the Malay Basin during Miocene time as a narrow gulf, connected to an open sea to the south and flanked by deltas and fan deltas.
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Clenton, P. N. "THE SNAPPER DEVELOPMENT, GIPPSLAND BASIN." APPEA Journal 28, no. 1 (1988): 29. http://dx.doi.org/10.1071/aj87003.
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The Eocene N-I reservoir at the top of the Latrobe Group at Snapper is the second largest gas accumulation discovered to date in the Gippsland Basin. Oil reserves exist in a four to eight metre oil leg below this gas pool and in various small intra-Latrobe Group reservoirs.Development drilling took place in two phases, between 1981 and 1987, with exploitation of the N-I gas reserves being the long term aim. However, initial emphasis has been to maximise production from the N-I oil column. This was the first significant development of a thin oil column in the Gippsland Basin and required detailed study of the reservoir stratigraphy, accurate mapping and the drilling of a number of costly, ultra-high angle wells.The N-I oil leg required intensive development because each well provides only limited drainage, despite the generally excellent reservoir quality. Recovery is limited by gas and water coning, shale and coal units that act as barriers to drainage and, in some areas, by the presence of dolomitic cement in the reservoir.After all 27 conductors had been used for development drilling, 5 unsuccessful or depleted wells were redrilled to additional N-I oil development targets. The Federal Government granted a 'Substantial New Development' classification to these wells before they were drilled. This provided a reduction in excise on part of the oil produced from them. The targets were small and difficult to reach and would not have been viable without this reduction.
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Taylor, Dennis, Aleksai E. Kontorovich, Andrei I. Larichev, and Miryam Glikson. "PETROLEUM SOURCE ROCKS IN THE ROPER GROUP OF THE MCARTHUR BASIN: SOURCE CHARACTERISATION AND MATURITY DETERMINATIONS USING PHYSICAL AND CHEMICAL METHODS." APPEA Journal 34, no. 1 (1994): 279. http://dx.doi.org/10.1071/aj93026.
Full textAbstract:
Organic rich shale units ranging up to 350 m in thickness with total organic carbon (TOC) values generally between one and ten per cent are present at several stratigraphic levels in the upper part of the Carpentarian Roper Group. Considerable variation in depositional environment is suggested by large differences in carbon:sulphur ratios and trace metal contents at different stratigraphic levels, but all of the preserved organic matter appears to be algal-sourced and hydrogen-rich. Conventional Rock-Eval pyrolysis indicates that a type I-II kerogen is present throughout.The elemental chemistry of this kerogen, shows a unique chemical evolution pathway on the ternary C:H:ONS diagram which differs from standard pathways followed by younger kerogens, suggesting that the maturation histories of Proterozoic basins may differ significantly from those of younger oil and gas producing basins. Extractable organic matter (EOM) from Roper Group source rocks shows a chemical evolution from polar rich to saturate rich with increasing maturity. Alginite reflectance increases in stepwise fashion through the zone of oil and gas generation, and then increases rapidly at higher levels of maturation. The increase in alginite reflectance with depth or proximity to sill contacts is lognormal.The area explored by Pacific Oil and Gas includes a northern area where the Velkerri Formation is within the zone of peak oil generation and the Kyalla Member is immature, and a southern area, the Beetaloo sub-basin, where the zone of peak oil generation is within the Kyalla Member. Most oil generation within the basin followed significant folding and faulting of the Roper Group.
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Swarbrick, R. E., and R. R. Hillis. "THE ORIGIN AND INFLUENCE OF OVERPRESSURE WITH REFERENCE TO THE NORTH WEST SHELF, AUSTRALIA." APPEA Journal 39, no. 1 (1999): 64. http://dx.doi.org/10.1071/aj98004.
Full textAbstract:
The dominant cause of overpressure in basins is rapid loading of fine-grained sediments in which incomplete dewatering leads to additional overburden load being supported partly by the pore fluids. The principal controls on the magnitude of overpressure created are permeability and compressibility of the fine-grained rocks, coupled with the loading or sedimentation rate. High magnitude overpressure requires rapid sedimentation and/or evolution of sediment permeability to nanoDarcy values at shallow depth. By contrast, most fluid expansion mechanisms can be shown to be ineffective at generating large magnitude overpressure at realistic basin conditions. Only gas generation (either directly from kerogen or by oil to gas cracking) has the potential to create large magnitude overpressure, and only if the connected reservoir volume is very restricted.The origin of overpressure in the North West Shelf, especially the Northern Carnarvon Basin has previously been suggested to be due to petroleum generation, principally because the top of overpressure is coincident with, or lies below, the hydrocarbon generation window. To achieve high magnitude overpressure by this mechanism requires large volumes of gas generative source rocks connected to reservoirs of extremely limited extent. The volume of reservoir rocks in the basins is relatively high, and gas generation appears to be only a secondary mechanism. The most likely origin of overpressure is burial of the Jurassic and Lower Cretaceous group sediments (including the Muderong Shale) with early development of the Muderong Shale as a pressure seal. Lateral stress cannot be discounted as an additional mechanism of overpressure generation. However, lateral strain appears to be significantly less than vertical strain.Overpressure has the potential to influence the petroleum system in the North West Shelf if there has been high magnitude overpressure for prolonged periods of geological time. Normally pressured units today may have had a history of overpressure in the geological past. Reservoir quality can be enhanced by overpressure, but trap seal integrity either strengthened or weakened by overpressure. Timing of maturation and migration of hydrocarbon can also be affected.
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Lowery, Christopher M., and R. Mark Leckie. "Biostratigraphy of the Cenomanian–turonian Eagle Ford Shale of South Texas." Journal of Foraminiferal Research 47, no. 2 (April 1, 2017): 105–28. http://dx.doi.org/10.2113/gsjfr.47.2.105.
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Abstract The Cenomanian–Turonian Eagle Ford Shale of south Texas occupies an important gateway between the Western Interior Seaway (WIS) of North America and the Gulf of Mexico. While the Eagle Ford north of the San Marcos Arch and its stratigraphic equivalents to the east of the Sabine Arch are shallow-water sediments dominated by terrigenous clastics, the more distal localities in south Texas are dominated by hemi-pelagic carbonates draped over an Early Cretaceous carbonate platform, called the Comanche Platform, and adjacent submarine plateaus and basins. This region was strongly affected by major oceanographic changes during the Cenomanian-Turonian, particularly a significant transgression that drove localized upwelling and organic matter burial in the Lower Eagle Ford prior to the global Oceanic Anoxic Event 2 (OAE2). These pre-OAE2 organic-rich shales are the basis of Eagle Ford shale gas play, which has spurred commercial and academic research into many aspects of the geology of the Eagle Ford Group. Much of this research has been fairly locally focused, and little effort has been made to understand the timing of events across the platform. We compared new data from three study sites across south Texas—Lozier Canyon in Terrell Co.; Bouldin Creek in Travis Co., near the San Marcos Arch in the center of the Comanche Platform; and Swift Energy's Fasken Core in Webb Co., off the platform on the Rio Grande Submarine Plateau—as well as published data from near Big Bend National Park on the western margin, and from Atacosta and Karnes counties on the eastern margin. Using these data we document the occurrence of key foraminiferal species across the platform and present a regional biostratigraphic scheme incorporating five global planktic foraminiferal zones (and contemporaneous occurrences that may serve as proxies for the zonal markers, which tend to be rare in Texas) and four local origination or acme events that serve as useful secondary markers. The succession of events is: 1) highest occurrence (HO) Favusella washitensis, 2) lowest occurrence (LO) Rotalipora cushmani, 3) “Benthonic Zone”, 4) HO R. cushmani and/or Thalmaninella greenhornensis, 5) “Heterohelix shift”, 6) LO “Anomalina W”, 7) LO Helvetoglobotruncana helvetica, 8) HO H. sp., and 9) LO Dicarinella concavata. Overall, we show that lithologic and geochemical trends through most of the Eagle Ford, particularly the oxygenation at the onset of OAE2 and the concurrent shift to more carbonate-rich lithologies, are synchronous across the Comanche Platform. However, the transition from the Eagle Ford Group to the Austin Chalk varies in age. While Austin Chalk deposition began in the middle Turonian Marginotruncana schneegansi Zone on the Rio Grande Submarine Plateau, a transgressive surface on the Comanche Platform (known as the “Rubble Zone” in central Texas) represents a condensed interval at the top of the Eagle Ford that ends in the upper Turonian D. concavata Zone. This is part of a transgressive disconformity that extends north through the WIS, where it is associated with the Juana Lopez Calcarenite.
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Burrett, M. R. Bendall C. F., and H. J. Askin. "PETROLEUM SYSTEMS IN TASMANIA'S FRONTIER ONSHORE BASINS." APPEA Journal 40, no. 1 (2000): 26. http://dx.doi.org/10.1071/aj99002.
Full textAbstract:
Sedimentary successions belonging to three petroleum su persy stems can be recognised in and below the Late Carboniferous to Late Triassic onshore Tasmania Basin. These are the Centralian, Larapintine and Gondwanan. The oldest (Centralian) is poorly known and contains possible mature source rocks in Upper Proterozoic dolomites. The Larapintine 2 system is represented by rocks of the Devonian fold and thrust belt beneath the Tasmania Basin. Potential source rocks are micrites and shales within the 1.8 km-thick tropical Ordovician Gordon Group carbonates. Conodont CAI plots show that the Gordon Group lies in the oil and gas windows over most of central Tasmania and probably under much of the Tasmania Basin. Potential reservoirs are the upper reefal parts of the Gordon Group, paleokarsted surfaces within the Gordon Group and the overlying sandstones of the Siluro-Devonian Tiger Range and Eldon Groups. Seal rocks include shales within the Siluro-Devonian and Upper Carboniferous-Permian tillites and shales.The Gondwanan supersystem is the most promising supersystem for petroleum exploration within the onshore Tasmania Basin. It is divided into two petroleum systems— the Early Permian Gondwanan 1 system, and the Late Permian to Triassic Gondwanan 2 system. Excellent source rocks occur in the marine Tasmanite Oil Shale and other sections within the Lower Permian Woody Island and Quamby Formations of the Gondwanan 1 system and within coals and freshwater oil shales of the Gondwanan 2 system. These sources are within the oil and gas windows across most of the basin and probably reached peak oil generation at about 100 Ma. An oil seep, sourced from a Tasmanites-rich, anoxic shale, is found within Jurassic dolerite 40 km WSW of Hobart. Potential Gondwanan 1 reservoirs are the glaciofluvial Faulkner Group sandstones and sandstones and limestones within the overlying parts of the glaciomarine Permian sequence. The Upper Permian Ferntree Mudstone Formation provides an effective regional seal. Potential Gondwanan 2 reservoirs are the sandstones of the Upper Permian to Norian Upper Parmeener Supergroup. Traps consisting of domes, anticlines and faults were formed probably during the Early Cretaceous. Preliminary interpretation of a short AGSO seismic profile in the Tasmania Basin shows that, contrary to earlier belief, structures can be mapped beneath extensive and thick (300 m) sills of Jurassic dolerite. In addition, the total section of Gondwana to Upper Proterozoic to Triassic sediments appears to be in excess of 8,500 m. These recent studies, analysis of the oil seep and drilling results show that the Tasmanian source rocks have generated both oil and gas. The Tasmania Basin is considered prospective for both petroleum and helium and is comparable in size and stratigraphy to other glaciomarine-terrestrial Gondwanan basins such as the South Oman and Cooper Basins.
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Johnson, R. L., Jr, C. W. Hopkins, and M. D. Zuber. "TECHNICAL CHALLENGES IN THE DEVELOPMENT OF UNCONVENTIONAL GAS RESOURCES IN AUSTRALIA." APPEA Journal 40, no. 1 (2000): 450. http://dx.doi.org/10.1071/aj99026.
Full textAbstract:
Unconventional gas resources, defined as low- permeability sandstone, coal seam and naturally- fractured shale gas reservoirs, represent a huge potential resource for future natural gas supply in Australia and around the world. Because low individual well-production rates are often the norm, unconventional reservoir development may involve the drilling of hundreds of wells to make the economics attractive. Thus, careful planning, sound development strategies and cost control are critical for project success.Virtually all unconventional gas resources must be stimulated to be economic; stimulation costs are often the most significant amount of the total well expenditure. Thus, a cost-effective method for reservoir characterisation and fracture treatment optimisation is required. Because of marginal economics, techniques used to analyse the process and results are often oversimplified; this can lead to confusing or inadequate descriptions of the complex behavior of a hydraulically-fractured, low- permeability reservoir and in some cases bad development decisions. Detailed data collection programs and fracture treatment optimisation strategies are essential to adequately address the technical issues involved in unconventional reservoir development.Besides the technical challenges associated with unconventional gas development, good forethought is necessary as to the planning and execution of the overall project. The development scenarios for coal seam and low-permeability sandstone gas resources are highly statistical and succeed or fail based on the average performance of the group of wells within the project. Following proven guidelines and methods during development while integrating key technologies into the planning and optimisation process are essential for success in unconventional reservoir development.
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Lawton, David E., and Paul P. Roberson. "The Johnston Gas Field, Blocks 43/26a, 43/27a, UK Southern North Sea." Geological Society, London, Memoirs 20, no. 1 (2003): 749–59. http://dx.doi.org/10.1144/gsl.mem.2003.020.01.62.
Full textAbstract:
abstractThe Johnston Field is a dry gas accumulation located within blocks 43/26a and 43/27a of the UK Southern North Sea. The discovery well was drilled in 1990 and after the drilling of one appraisal well in 1991, a development plan was submitted and approved in 1993. Initially two development wells were drilled from a four slot sub-sea template, with commercial production commencing in October 1994. A further horizontal development well was added to the field in 1997.The field has a structural trap, fault bounded to the SW and dip-closed to the north, east and south. This field geometry has been established using high quality 3D seismic data, enhanced by seismic attribute analysis. The sandstone reservoir interval consists of the Early Permian, Lower Leman Sandstone Formation of the Upper Rotliegend Group. This reservoir consists of a series of interbedded aeolian dune, fluvial, and clastic sabkha lithofacies. The quality of the reservoir is variable and is principally controlled by the distribution of the various lithofacies. The top seal and fault bounding side seal are provided by the overlying clay stone of the Silverpit Shale Formation and the evaporite dominated Zechstein Supergroup.The field has been developed using a phased development plan, with the acquisition of a 3D seismic survey allowing for the optimized drilling of a high deliverability horizontal well.Current mapped gas initially-in-place estimates for the field are between 360 and 403 BCF, with an estimated recovery factor of between 60 and 75%.
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Higley, Debra, and Catherine Enomoto. "Burial History Reconstruction of the Appalachian Basin in Kentucky, West Virginia, Pennsylvania, and New York, Using 1D Petroleum System Models." Mountain Geologist 56, no. 4 (October 1, 2019): 365–96. http://dx.doi.org/10.31582/rmag.mg.56.4.365.
Full textAbstract:
Nine 1D burial history models were built across the Appalachian basin to reconstruct the burial, erosional, and thermal maturation histories of contained petroleum source rocks. Models were calibrated to measured downhole temperatures, and to vitrinite reflectance (% Ro) data for Devonian through Pennsylvanian source rocks. The highest levels of thermal maturity in petroleum source rocks are within and proximal to the Rome trough in the deep basin, which are also within the confluence of increased structural complexity and associated faulting, overpressured Devonian shales, and thick intervals of salt in the underlying Silurian Salina Group. Models incorporate minor erosion from 260 to 140 million years ago (Ma) that allows for extended burial and heating of underlying strata. Two modeled times of increased erosion, from 140 to 90 Ma and 23 to 5.3 Ma, are followed by lesser erosion from 5.3 Ma to Present. Absent strata are mainly Permian shales and sandstone; thickness of these removed layers increased from about 6200 ft (1890 m) west of the Rome trough to as much as 9650 ft (2940 m) within the trough. The onset of oil generation based on 0.6% Ro ranges from 387 to 306 Ma for the Utica Shale, and 359 to 282 Ma for Middle Devonian to basal Mississippian shales. The ~1.2% Ro onset of wet gas generation ranges from 360 to 281 Ma in the Utica Shale, and 298 to 150 Ma for Devonian to lowermost Mississippian shales.