Relevant bibliographies by topics / Gas shales

Academic literature on the topic 'Gas shales'

Author: Grafiati
Published: 11 March 2023

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Journal articles on the topic "Gas shales"

1

Jiang, Shu, Jinchuan Zhang, Zhiqiang Jiang, Zhengyu Xu, Dongsheng Cai, Lei Chen, Yue Wu, et al. "Geology, resource potentials, and properties of emerging and potential China shale gas and shale oil plays." Interpretation 3, no. 2 (May 1, 2015): SJ1—SJ13. http://dx.doi.org/10.1190/int-2014-0142.1.

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This paper describes the geology of organic-rich shales in China, their resource potentials, and properties of emerging and potential China shale gas and shale oil plays. Marine, lacustrine, and coastal swamp transitional shales were estimated to have the largest technically recoverable shale gas resource (25.08 trillion cubic meters or 886 trillion cubic feet) and 25 to 50 billion barrels of technically recoverable shale oil resource. The Precambrian Sinian Doushantuo Formation to Silurian Longmaxi black marine shales mainly accumulated in the intrashelf low to slope environments in the Yangtze Platform in South China and in the Tarim Platform in northwest China. The marine shales in the Yangtze Platform have high maturity (Ro of 1.3%–5%), high total organic carbon (mainly [Formula: see text]), high brittle-mineral content, and have been identified as emerging shale gas plays. The Lower Paleozoic marine shales in the Upper Yangtze area have the largest shale gas potential and currently top the list as exploration targets. The Carboniferous to Permian shales associated with coal and sandstones were mainly formed in transitional depositional settings in north China, northwest China, and the Yangtze Platform in south China. These transitional shales are generally rich in clay with a medium level of shale gas potential. The Middle Permian to Cenozoic organic-rich lacustrine shales interbedded with thin sandstone and carbonate beds are sporadically distributed in rifted basins across China. Their main potentials are as hybrid plays (tight and shale oil). China shales are heterogeneous across time and space, and high-quality shale reservoirs are usually positioned within transgressive systems tract to early highstand systems tract intervals that were deposited in an anoxic depositional setting. For China’s shale plays, tectonic movements have affected and disrupted the early oil and gas accumulation, making tectonically stable areas more favorable prospects for the exploration and development of shale plays.
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Li, Gang, Ping Gao, Xianming Xiao, Chengang Lu, and Yue Feng. "Lower Cambrian Organic-Rich Shales in Southern China: A Review of Gas-Bearing Property, Pore Structure, and Their Controlling Factors." Geofluids 2022 (June 25, 2022): 1–23. http://dx.doi.org/10.1155/2022/9745313.

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The Lower Cambrian shales are widely developed in southern China, with greater thicknesses and higher TOC contents. Although the shale gas resource potential has been suggested to be huge, the shale gas exploration and development is not satisfactory. At present, the gas-bearing property evaluation of the Lower Cambrian shale is still a hot spot of concern. According to previous works, this paper systematically summarizes the gas-bearing characteristics and controlling factors of the Lower Cambrian shales in southern China. The buried depth of Lower Cambrian shales mainly ranges from 3000 m to 6000 m, and the thickness of organic-rich shale intervals ( TOC > 2 % ) varies from 20 m to 300 m. The TOC content and EqVRo value are generally up to 2%-10% and 2.5%-6.0%, respectively. The gas content of the Lower Cambrian shales in the Weiyuan-Qianwei block of the Sichuan Basin and the western Hubei area generally exceeds 2 m3/t, and gas composition is dominated by CH4. In southeastern Chongqing, northwestern Hunan, and northern Guizhou areas, the gas content of the Lower Cambrian shales is generally <2 m3/t, and the N2 content is generally >60%. In the Lower Yangtze region, the Lower Cambrian shale reservoirs basically contain no gas. Higher maturity, lower porosity, and less-no organic pores are suggested to be responsible for low gas contents and/or the predominate of N2 in shale gas reservoirs. Strong tectonic deformation is an important factor leading to the massive gas loss from shale reservoirs, thus resulting in no gas or only a small amount of N2 in the Lower Cambrian shales. In a word, the Lower Cambrian shale gas plays with low maturity and relatively stable tectonic condition, especially deep-ultradeep zones, may be the favorable targets for shale gas exploration.
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Feng, Bing, Jiliang Yu, Feng Yang, Zhiyao Zhang, and Shang Xu. "Reservoir Characteristics of Normally Pressured Shales from the Periphery of Sichuan Basin: Insights into the Pore Development Mechanism." Energies 16, no. 5 (February 23, 2023): 2166. http://dx.doi.org/10.3390/en16052166.

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Reservoir characteristics and the occurrence mechanism of shale gas outside of the Sichuan Basin are the research hotspots of normally pressured shales in China. Taking shales on the Anchang syncline from the periphery of the Sichuan Basin as an example, X-ray diffraction, organic geochemistry, and rock physical experiments were carried out to analyze the reservoir characteristics and their main geological controls on the normally pressured shales. The mineralogical results show that the studied shales from the Anchang syncline are mainly siliceous shales with a high quartz content (average of 57%). The quartz content of these normally pressured shales is of biological origin, as shown by the positive correlation between the quartz and organic carbon (TOC) contents. The average porosity of the studied shales is about 2.9%, which is lower than shales inside the Sichuan Basin. Organic matter pores are likely the primary storage space of the normally pressured shale gas, as shown by the positive relationship between the TOC content and porosity. However, scanning electron microscopy observations on the studied shales show that the pores in these normally pressured shales are poorly preserved; many pores have been subjected to compression and deformation due to tectonic movements. Compared to shales inside the Sichuan Basin, the effective thickness of shales outside of the Sichuan Basin is thin and the stratum dip is large. Thus, shale gas outside of the Sichuan Basin is apt to escape laterally along the bedding of the strata. After losing a significant amount of shale gas, the gas pressure decreases to normal pressure, which makes it difficult for the pores to resist compaction from the overlying strata. This is probably why most shale gas reservoirs outside of the Sichuan Basin are normally pressured, while the shale strata inside the Sichuan Basin are commonly overpressured. This study provides insights to understand the pore development and hydrocarbon occurrence on normally pressured shales outside of the Sichuan Basin.
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Hill, Anthony, Sandra Menpes, Guillaume Backè, Hani Khair, and Arezoo Siasitorbaty. "Shale gas prospectivity in South Australia." APPEA Journal 51, no. 2 (2011): 718. http://dx.doi.org/10.1071/aj10098.

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Potential shale gas bearing basins in SA are primarily dominated by thermogenic play types and span the Neoproterozoic to Cretaceous. Whilst companies have only recently commenced exploring for shale gas in the Permian Cooper Basin, strong gas shows have been routinely observed and recorded since exploration commenced in the basin in 1959. The regionally extensive Roseneath and Murteree shales represent the primary exploration focus and reach maximum thicknesses of 103 m and 86 m respectively with TOC values up to 9%. These shales are in the gas window in large parts of the basin, particularly in the Patchawarra and Nappamerri troughs. Outside the Cooper Basin, thick shale sequences in the Crayfish Subgroup of the Otway Basin, in particular the Upper and Lower Sawpit shales and to a lesser extent the Laira Formation, have good shale gas potential in the deeper portions of the basin. TOC averages up to 3% are recorded in these shales in the Penola Trough; maturities in the range of 1.3–1.5% have been modelled. Thick Permian marine shales of the Arckaringa Basin have excellent source rock characteristics, with TOC’s ranging 4.1–7.4% and averaging 5.2% over an interval exceeding 150 m in the Phillipson Trough; however, these Type II source rocks are not sufficiently mature for gas generation anywhere in the Arckaringa Basin. Shale gas has the potential to rival CSM in eastern Australia; its potential is now being explored in SA.
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Jiang, Tao, Zhijun Jin, Hengyuan Qiu, Xuanhua Chen, Yuanhao Zhang, and Zhanfei Su. "Pore Structure and Gas Content Characteristics of Lower Jurassic Continental Shale Reservoirs in Northeast Sichuan, China." Nanomaterials 13, no. 4 (February 20, 2023): 779. http://dx.doi.org/10.3390/nano13040779.

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The Jurassic shale in the northeastern Sichuan Basin is one of the main target intervals for continental shale gas exploitation. Research on the pore structure and gas-bearing properties of shales is the key issue in target interval optimization. Through core observation, geochemistry, bulk minerals, scanning electron microscopy, nitrogen adsorption, and isothermal adsorption experiments, various lithofacies with different pore structure characteristics were clarified. In addition, the factors that control gas-bearing properties were discussed, and a continental shale gas enrichment model was finally established. The results show that the Jurassic continental shale in the northeastern Sichuan Basin can be classified into six lithofacies. Organic pores, intergranular pores, interlayer pores in clay minerals, intercrystalline pores in pyrite framboids, and dissolution pores can be observed in shale samples. Pore structures varied in different shale lithofacies. The contact angle of shales is commonly less than 45°, leading to complex wettability of pores in the shales. Free gas content is mainly controlled by the organic matter (OM) content and the brittleness in the Jurassic shale. The adsorbed gas content is mainly controlled by the OM content, clay mineral type, and water saturation of the shales. The enrichment mode of the Lower Jurassic continental shale gas in the northeastern Sichuan Basin is established. Paleoenvironments control the formation of organic-rich shales in the center part of lakes. The “baffle” layer helps the confinement and high pressure, and the complex syncline controls the preservation, forming the enrichment pattern of the complex syncline-central baffle layer.
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Faraj, Basim, and Daniel Jarvie. "Producibility and commerciality of shale resource systems: contrasting geochemical attributes of shale gas and shale oil systems." APPEA Journal 53, no. 2 (2013): 469. http://dx.doi.org/10.1071/aj12080.

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Increasing the producibility of petroleum from shale is a key challenge for this decade and beyond. While understanding of producing petroleum from shales has advanced rapidly during the past decade, many unknowns remain. In addition, fundamental differences remain between high-thermal maturity shale gas systems (gas-window shales) and oil-window shales. Although it is shown that oil is produced from the shale matrix similar to gas shales, it is not known what improvement to recovery factors should be expected due to the fundamental differences and uniqueness of shale oil systems. Some of the challenges in early exploration of shales in the oil window are related to the loss of oil from rock samples (cuttings, core), sample processing, storage conditions, sample preparation, oil type, API gravity, gas-oil ratio (GOR), rock lithofacies, and analytical conditions. It is shown that old cuttings may lose up to 300% of their free oil content simply due to evaporation, even in tight shale with black oil having a GOR of about 500 scf/bbl. When cuttings are compared with RSWC or core chips, the loss increases to almost 500%. Projection of oil content to match measured GOR values of oils or even extracts of organic-rich tight shales allows prediction of this oil loss—this impacts calculations of original oil in place (OOIP) and, hence, hydrocarbon recovery estimates from such systems.
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Jiao, Pengfei, Genshun Yao, Shangwen Zhou, Zhe Yu, and Shiluo Wang. "A Comparative Study of the Micropore Structure between the Transitional and Marine Shales in China." Geofluids 2021 (April 7, 2021): 1–14. http://dx.doi.org/10.1155/2021/5562532.

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To compare the micropore structure of marine-continental transitional shale with marine shale, organic geochemical, field emission scanning electron microscopy, and low-temperature nitrogen adsorption experiments were conducted on shale samples from the Shanxi Formation in the eastern Ordos Basin and the Longmaxi Formation in the southern Sichuan Basin. The results show that Shanxi Formation shale has a smaller specific surface area and pore volume than Longmaxi Formation shale; therefore, the transitional shales fail to provide sufficient pore spaces for the effective storage and preservation of natural gas. Both the transitional and marine shales are in an overmature stage with high total organic carbon content, but they differ considerably in pore types and development degrees. Inorganic pores and fractures are dominantly developed in transitional shales, such as intragranular pores and clay mineral interlayer fractures, while organic nanopores are rarely developed. In contrast, organic pores are the dominant pore type in the marine shales and inorganic pores are rarely observed. The fractal analysis also shows that pore structure complexity and heterogeneity are quite different. These differences were related to different organic types, i.e., type I of marine shale and type III of transitional shale. Marine Longmaxi shale has experienced liquid hydrocarbon cracking, gas generation, and pore-forming processes, providing good conditions for natural gas to be preserved. However, during the evolution of transitional Shanxi shale, gas cannot be effectively preserved due to the lack of the above evolution processes, leading to the poor gas-bearing property. The detailed comparison of the micropore structure between the transitional and marine shales is of great importance for the future exploitation of marine-continental transitional shale gas in China.
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Menpes, Sandra, and Tony Hill. "Emerging continuous gas plays in the Cooper Basin, South Australia." APPEA Journal 52, no. 2 (2012): 671. http://dx.doi.org/10.1071/aj11085.

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Recent off-structure drilling in the Nappamerri Trough has confirmed the presence of gas saturation through most of the Permian succession, including the Roseneath and Murteree shales. Basin-centred gas, shale gas and deep CSG plays in the Cooper Basin are now the focus of an escalating drilling and evaluation campaign. The Permian succession in the Nappamerri Trough is up to 1,000 m thick, comprising very thermally mature, gas-prone source rocks with interbedded sands—ideal for the creation of a basin-centred gas accumulation. Excluding the Murteree and Roseneath shales, the succession comprises up to 45% carbonaceous and silty shales and thin coals deposited in flood plain, lacustrine and coal swamp environments. The Early Permian Murteree and Roseneath shales are thick, generally flat lying, and laterally extensive, comprising siltstones and mudstones deposited in large and relatively deep freshwater lakes. Total organic carbon values average 3.9% in the Roseneath Shale and 2.4% in the Murteree Shale. The shales lie in the wet gas window (0.95–1.7% Ro) or dry gas window (>1.7% Ro) over much of the Cooper Basin. Thick Permian coals in the deepest parts of the Patchawarra Trough and over the Moomba high on the margin of the Nappamerri Trough are targets for deep CSG. Gas desorption analysis of a thick Patchawarra coal seam returned excellent total raw gas results averaging 21.2 scc/g (680 scf/ton) across 10 m. Scanning electron microscopy has shown that the coals contain significant microporosity.
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Zhang, Peng, Junwei Yang, Yuqi Huang, Jinchuan Zhang, Xuan Tang, and Chengwei Liu. "Shale Heterogeneity in Western Hunan and Hubei: A Case Study from the Lower Silurian Longmaxi Formation in Well Laidi 1 in the Laifeng-Xianfeng Block, Hubei Province." Geofluids 2022 (January 7, 2022): 1–15. http://dx.doi.org/10.1155/2022/8125317.

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Shale heterogeneity directly determines the alteration ability and gas content of shale reservoirs, and its study is a core research topic in shale gas exploitation and development. In this study, the shale from the Longmaxi Formation from well Ld1 located in western Hunan and Hubei is investigated. The shale’s heterogeneity is analyzed based on shale mineral rocks, microslices, geochemistry, and low-temperature N2 adsorption-desorption. It is found that the shales of the Longmaxi Formation from well Ld1 are mainly composed of siliceous shale, mixed shale, and clayey shale. The three types of shale facies exhibit strong heterogeneity in terms of the occurrence state of organic matter, organic content, mineral composition, microstructure and structure, brittleness, and micropore type. Sedimentation, late diagenesis, and terrigenous input are the main factors influencing the shale’s heterogeneity. With a total organic carbon (TOC) of 0.41%-4.18% and an organic matter maturity ( R o ) of 3.09%-3.42%, the shales of the Longmaxi Formation from well Ld1 are in an overmature stage, and their mineral composition is mainly quartz (5%-66%) and clay minerals (17.8%-73.8%). The main pore types are intergranular pores, intragranular pores, microfractures, and organic pores. The results of the low-temperature N2 adsorption-desorption experiment show that the shale pores are mainly composed of micropores and mesopores with narrow throats and complex structures, and their main morphology is of a thin-necked and wide-body ink-bottle pore. Based on the Frenkel-Halsey-Hill (FHH) model, the pore fractal dimension is studied to obtain the fractal dimension D 1 (2.73-2.76, mean 2.74) under low relative pressure ( P / P 0 ≤ 0.5 ) and D 2 (2.80-2.89, mean 2.85) under high relative pressure ( P / P 0 > 0.5 ). The shales of the Longmaxi Formation in the study area have a strong adsorption and gas storage capacity; however, the pore structure is complex and the connectivity is poor, which, in turn, imposes high requirements on reservoir reformation measures during exploitation. Moreover, the fractal dimension has a positive correlation with organic matter abundance, TOC, clay mineral content, and pyrite content and a negative correlation with quartz content. Since the organic matter contained in the shales of the Longmaxi Formation in the study area is in the overmature stage, the adsorption capacity of the shales is reduced, and the controlling effect of organic matter abundance on the same is not apparent.
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Gao, Ping, Xianming Xiao, Dongfeng Hu, Ruobing Liu, Yidong Cai, Tao Yuan, and Guangming Meng. "Water Distribution in the Ultra-Deep Shale of the Wufeng–Longmaxi Formations from the Sichuan Basin." Energies 15, no. 6 (March 17, 2022): 2215. http://dx.doi.org/10.3390/en15062215.

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Recently, deep and ultra-deep shales (depth >3500 m) of the Lower Paleozoic Wufeng–Longmaxi formations (WF–LMX) have become attractive targets for shale gas exploration and development in China, and their gas contents may be influenced by the occurrence of water to some extent. However, the water content and its distribution in the different nanopores of the deep and ultra-deep shales have rarely been reported. In this study, a suite of the WF–LMX ultra-deep shale samples (5910–5965 m depth) from the Well PS1 was collected for water content measurements, and low-pressure CO2 and N2 adsorption experiments of both as-received and experimentally dried shale samples were carried out to investigate the distribution of water in the different nanopores. Since the studied ultra-deep shales are characterized by higher thermal maturity (equivalent vitrinite reflectance (EqVRo) > 2.5 %) and ultra-low water saturation, the pore water is generally dominated by irreducible water. The content of irreducible water of the studied shales varies from 1.57 to 13.66 mg/g, averaging 6.74 mg/g. Irreducible water may mainly occur in the clay-hosted pores, while it could also be hosted in parts of organic pores of organic-rich shales. Irreducible water is primarily distributed in non-micropores rather than in micropores of the studied shales, which mainly occurs in micopores with a diameter of 0.4–0.6 nm and mesopores with a diameter of 2–10 nm. Very low contents of irreducible water could reduce the specific surface area and volume of non-micropores of the shales to some extent, but the effect of irreducible water on the specific surface area of non-micropores was more significant than the volume of non-micropores, especially for organic-rich shale samples. The ultra-deep shale gas may be predominately composed of free gas, so low contents of irreducible water may play a limited role in its total gas contents. Overall, our findings can be helpful for a better understanding of water distribution in the highly-matured shales, and provide a scientific basis for ultra-deep shale gas exploration.
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Dissertations / Theses on the topic "Gas shales"

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Rexer, Thomas. "Nanopore characterisation and gas sorption potential of European gas shales." Thesis, University of Newcastle upon Tyne, 2014. http://hdl.handle.net/10443/2597.

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An inter-laboratory study of high-pressure gas sorption measurements on two carbonaceous shales has been conducted to assess the reproducibility of sorption isotherms on shale and identify possible sources of error. The measurements were carried out by 7 different international research laboratories on either in-house or commercial sorption equipment using manometric as well as gravimetric methods. Excess sorption isotherms for methane, carbon dioxide and ethane were measured at 65°C and at pressures up to 25 MPa on two organic-rich shales at dry conditions. The inter-laboratory reproducibility of the methane excess sorption isotherms was better for the high-maturity shale (within 0.02 – 0.03 mmol g-1) than for the low-maturity sample (up to 0.1 mmol g-1), which is in agreement with results of earlier studies on coals. The procedures for sample conditioning prior to the measurement, the measurement procedures and the data reduction approach must be optimized to achieve higher accuracy. Unknown systematic errors in the measured quantities must be minimized first by applying standard calibration methods. Furthermore, the adsorption of methane on a dry, organic-rich, high-maturity Alum shale sample was studied at a wide temperature range (300 – 473 K) and pressures up to 14 MPa. These conditions are relevant to gas storage under geological conditions. Maximum methane excess uptake is 0.176 – 0.042 mmol g-1 (125 - 30 scf t-1) at 300 - 473 K. Supercritical adsorption was parameterized using the modified Dubinin-Radushkevich and the Langmuir equations. Gas in shales is stored in three different states: adsorbed, compressed (free) and dissolved; quantifying each underpins calculations of gas storage capacity and also the mechanisms by which gas must be transported from pore (surfaces), to fracture, to the well. While compressed gas dominates in meso- and macropores, it is often assumed that (a) sorbed gas occurs mainly in micropores (< 2nm) and (b) micropores are mainly associated with organic matter. In the third part of this thesis, those ideas are tested by characterising the porous structure of six shales and isolated kerogens from the Posidonia Formation in combination with high pressure methane sorption isotherms at 45, 65 and 85°C. Together, these data help us to understand the extent to which (a) small pores control CH4 sorption and (b) whether “sorption” pores are associated with the organic and inorganic phases within shales. Samples were selected with vitrinite reflectance of 0.6, 0.9 and 1.45%. Pore volumes – named sorption pore volumes here - were determined on dry shales and isolated kerogens by CO2 isotherms measured at -78°C and up to 0.1 MPa. These volumes include micropores (pore II width < 2nm) and narrow mesopores; according to the Gurvitch Rule this is the volume available for sorption of most gases. Sorption pore volumes of Posidoniashales range from 0.008 to 0.016 cm3 g-1, accounting for 21 - 66% of total porosity. Whilst sorption pore volumes of isolated kerogen are much higher, between 0.095 – 0.147 cm3 g-1, normalization by TOC shows that only half the sorption pore volume of the shales is located within the kerogen. Excess uptakes on dry Posidonia shales at 65°C and 11.5MPa range from 0.056−0.110 mmol g-1 (40−78 scf t-1) on dry shale, and from 0.36−0.70 mmol g-1 (253−499 scf t-1) on dry kerogen. Enthalpies of adsorption show no variation with TOC and maturity, respectively. The correlation between maximum CH4 sorption and CO2 sorption pore volume at 195 K is very strong and goes through the origin, suggesting that the vast majority of sorbed CH4 occurs in pores smaller than 6 nm. Approximately half the sorption pore volume and thus CH4 sorption potential of these dry shales is in organic matter, with the rest likely to be associated with clay minerals. Sorption mass balances using isotherms for kerogen and clay minerals do not always account for the total measured sorbed CH4 on dry shales, suggesting that some sorption may occur at interfaces between minerals and organic matter.
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Pathi, Venkat Suryanarayana Murthy. "Factors affecting the permeability of gas shales." Thesis, University of British Columbia, 2008. http://hdl.handle.net/2429/5302.

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The mechanical properties and matrix permeability of gas shales are the most important properties in determining their production capacity. In this research, I have investigated the matrix permeability and rock mechanical properties of Western Canadian and Woodford shales. The matrix permeability was measured using pulse decay experiment. The pulse decay experiment was employed with triaxial experiments combined with mercury porosimetry, helium pydnometry, Rock-Eval pyrolysis, SEM and X-ray diffraction analysis to measure rock strength, pore size, porosity, total organic content, fabric and composition of samples. The permeability results were correlated with effective stress, anisotropy, fabric, rock strength, porosity, pore size and total organic content. Mineralogy plays an important role in determining the permeability of Canadian and Woodford shales. Higher permeability was observed in samples with high clay content, and low permeability was observed in samples with high quartz and carbonate content. Among the clay-, silica-, and calcite-rich Canadian shales, the calcite-rich shales had a very low permeability (1O⁻⁷ md) compared to other shales. The permeability of all shales decline exponentially with increasing effective stress. Samples that were tested parallel to bedding had higher permeabilities than samples were tested normal to bedding. Among shales, the quartz-rich shales showed differences of three to four orders of magnitude for the samples tested parallel to bedding, compared to those tested normal to the bedding. The largest anisotropy was found in the clay-rich samples. Clay-rich shales also have a well developed fabric with a strongly preferred orientation, while the quartz-rich shales had random orientation of the fabric. The porosimetry results suggest that fluid flow is mostly in the meso (2-50 nm) and macro pores (>50 nm) of the Woodford shales. Samples with higher clay content (>30%) showed a higher intrusion volume in macro pores, while samples with higher quartz content showed intrusion volume in micro pores. Porosity is correlated to permeability in the Western Canadian shales and showed a linear correlation within the Woodford shales. Even though calcite-rich Canadian shales and quartz-rich Woodford shales have high TOC content, TOC was not seen to effect permeability. Triaxial compression rock testing was conducted on the Woodford shales to measure the elastic properties and strength behaviour of shale. Lithologic composition plays an important role in the strength and pore compressibility of shale. Quartz-rich or carbonate rich shales have a brittle behaviour and clay-rich shales have a ductile behaviour. Pore compressibility is greater in the clay-rich shales, and less in the quartz-rich shales.
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Roychaudhuri, Basabdatta. "Spontaneous Countercurrent and Forced Imbibition in Gas Shales." Thesis, University of Southern California, 2018. http://pqdtopen.proquest.com/#viewpdf?dispub=10635652.

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In this study, imbibition experiments are used to explain the significant fluid loss, often more than 70%, of injected water during well stimulation and flowback in the context of natural gas production from shale formations. Samples from a 180 ft. long section of a vertical well were studied via spontaneous and forced imbibition experiments, at lab-scale, on small samples with characteristic dimensions of a few cm; in order to quantify the water imbibed by the complex multi-porosity shale system. The imbibition process is, typically, characterized by a distinct transition from an initial linear rate (vs. square root of time) to a much slower imbibition rate at later times. These observations along with contact angle measurements provide an insight into the wettability characteristics of the shale surface. Using these observations, together with an assumed geometry of the fracture system, has made it possible to estimate the distance travelled by the injected water into the formation at field scale.

Shale characterization experiments including permeability measurements, total organic carbon (TOC) analysis, pore size distribution (PSD) and contact angle measurements were also performed and were combined with XRD measurements in order to better understand the mass transfer properties of shale. The experimental permeabilities measured in the direction along the bedding plane (10 –1–10–2 mD) and in the vertical direction (~10–4 mD) are orders of magnitude higher than the matrix permeabilities of these shale sample (10–5 to 10 –8 mD). This implies that the fastest flow in a formation is likely to occur in the horizontal direction, and indicates that the flow of fluids through the formation occurs predominantly through the fracture and micro-fracture network, and hence that these are the main conduits for gas recovery. The permeability differences among samples from various depths can be attributed to different organic matter content and mineralogical characteristics, likely attributed to varying depositional environments. The study of these properties can help ascertain the ideal depth for well placement and perforation.

Forced imbibition experiments have been carried out to better understand the phenomena that take place during well stimulation under realistic reservoir conditions. Imbibition experiments have been performed with real and simulated frac fluids, including deionized (DI) water, to establish a baseline, in order to study the impact on imbibition rates resulting from the presence of ions/additives in the imbibing fluid. Ion interactions with shales are studied using ion chromatography (IC) to ascertain their effect on imbibition induced porosity and permeability change of the samples. It has been found that divalent cations such as calcium and anions such as sulfates (for concentrations in excess of 600 ppm) can significantly reduce the permeability of the samples. It is concluded, therefore, that their presence in stimulating fluids can affect the capillarity and fluid flow after stimulation. We have also studied the impact of using fluoro-surfactant additives during spontaneous and forced imbibition experiments. A number of these additives have been shown to increase the measured contact angles of the shale samples and the fluid recovery from them, thus making them an ideal candidate for additives to use. Their interactions with the shale are further characterized using the Dynamic Light Scattering (DLS) technique in order to measure their hydrodynamic radius to compare it with the pore size of the shale sample.

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Hine, Lucy Ann. "Onshore oil and gas in Britain : planning problems and policies." Thesis, University of Aberdeen, 1985. http://digitool.abdn.ac.uk/R?func=search-advanced-go&find_code1=WSN&request1=AAIU361902.

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The search for onshore oil and gas in Britain has had an erratic pattern of historical development but since the discovery of the Wytch Farm field in Dorset, during 1973, the industry has undergone a marked revival. Over the past ten years one of the highest levels of exploration ever experienced has been achieved and this has raised a number of interesting new questions in relation to planning for these developments. One of the main problems is that although the drilling of an exploratory borehole requires planning permission the work itself is only a temporary operation and on the basis of this argument permission has been sought to drill wells on land of high amenity or ecological value. However, a successful exploratory borehole can lead to a planning application for the installation of more permanent production facilities and this can lead to something of a dilemma for planners as to where exploratory drilling should be permitted. This research aimed to investigate the onshore hydrocarbons industry and determine what were the impacts of and the issues raised by this new phase of activity. The work was given an exciting new dimension when a public inquiry was called to investigate Shell UK's planning application to sink an exploratory borehole in the New Forest. The proceedings of the Inquiry were followed and the evidence presented was used to help determine the important issues. A series of detailed interviews were then undertaken to illuminate the problems from the viewpoint of both the industry and the planners. Mineral Planning Officers and Oil Company Officials answered similar questions and related these to their own individual experiences of onshore hydrocarbons operations. The research concluded that although the industry raised a number of problems the use of effective planning control at both central and local levels could overcome most of these. A series of recommendations were made.
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Wilson, Timothy George Edmund. "Financial aspects of the oil and gas exploration and production industry." Thesis, University of Exeter, 1986. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.302980.

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Rybalcenko, Konstantin. "Gas flow measurements in shales : laboratory, field and numerical investigations." Thesis, University of Leeds, 2017. http://etheses.whiterose.ac.uk/16966/.

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A multi-disciplinary research project including experimental and modelling studies was carried out on shale samples to characterise their porosity and permeability. Pressure expansion techniques were used, including current industry-standard methods as well as new methods developed and modified throughout this research. The derived porosity and permeability values were cross-checked with the results from commercial laboratories. Finally, the results obtained were applied to a shale resource play currently being appraised to understand its commercial viability. Precise grain density results were achieved using the crushed shale method as helium is able to rapidly intrude small sample pores and is not significantly adsorbed onto the constituents of the shale. Precise bulk volume measurements were obtained using mercury immersion but these are ambient stress measurements and need correcting for in-situ conditions. Mercury probably does not enter the pore-space of shale at low pressures during MICP tests and instead closes artificial microfractures. So the results may provide a method to estimate bulk density at the reservoir stresses. The porosity measured using the crushed shale method is more accurate compared to core plug methods. It is important to dry crushed samples to standardise porosity measurements. Other laboratories produced comparable results except for one laboratory which most likely did not conduct sample cleaning procedures properly. Permeability values obtained using the crushed shale method were orders of magnitudes different between the measurements conducted during this study and commercial laboratories. Overall, this test appears to provide no useful information regarding the flow properties of shales. Measurements made on core plugs are often dominated by the presence of microfractures but it is possible to obtain reasonably reliable permeability estimates by inverting the experimental data using a dual porosity-permeability model. To assess the applicability of porosity and permeability methods on commercial shale play, a significant amount of in-situ field data (i.e. well tests, core data etc.) were gathered and tested during the collaborative project in Europe with a local gas exploration company. Gas-In-Place (GIP) and Estimated Ultimate Recovery (EUR) values were produced and based on these the project was approved by the company for the next stage of development. However the model constructed lacked the ability to reproduce the well flow production rates.
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Bou, Hamdan Kamel F. "Investigating the role of proppants in hydraulic fracturing of gas shales." Thesis, University of Aberdeen, 2019. http://digitool.abdn.ac.uk:80/webclient/DeliveryManager?pid=.

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Gasparik, Matus [Verfasser]. "Experimental investigation of gas storage properties of black shales / Matus Gasparik." Aachen : Hochschulbibliothek der Rheinisch-Westfälischen Technischen Hochschule Aachen, 2014. http://d-nb.info/1051427770/34.

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Fink, Reinhard Verfasser], Ralf [Akademischer Betreuer] [Littke, and Andreas [Akademischer Betreuer] Busch. "Experimental investigation of gas transport and storage processes in the matrix of gas shales / Reinhard Fink ; Ralf Littke, Andreas Busch." Aachen : Universitätsbibliothek der RWTH Aachen, 2017. http://d-nb.info/1162499249/34.

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Fink, Reinhard [Verfasser], Ralf [Akademischer Betreuer] Littke, and Andreas [Akademischer Betreuer] Busch. "Experimental investigation of gas transport and storage processes in the matrix of gas shales / Reinhard Fink ; Ralf Littke, Andreas Busch." Aachen : Universitätsbibliothek der RWTH Aachen, 2017. http://d-nb.info/1162499249/34.

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Books on the topic "Gas shales"

1

Abbasi, Arshad H. Shale oil and gas: Lifeline for Pakistan. Edited by Mehmood Fareeha author, Kamal Maha author, Naqvi Swaleha editor, and Sustainable Development Policy Institute. Islamabad: Sustainable Development Policy Institute, 2014.

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Ikushima, Kenji. Shēru gasu oiru no kagayakeru mirai. Tōkyō-to Chiyoda-ku: Shīemushī Shuppan, 2013.

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Schamel, Steven. Shale gas resources of Utah: Assessment of previously undeveloped gas discoveries. Salt Lake City, Utah: Utah Geological Survey, 2006.

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Nash, Katelyn M. Shale gas development. New York: Nova Science Publishers, 2010.

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Hamilton-Smith, Terence. Gas exploration in the Devonian shales of Kentucky. Lexington: Kentucky Geological Survey, University of Kentucky, 1993.

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Project, White River Shale. White River Shale Project, Federal prototype oil shale tracts Ua and Ub: Progress report, environmental programs. Salt Lake City, Utah: White River Shale Oil Corporation, 1985.

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Corporation, White River Shale. White River Shale Project, Federal prototype oil shale leases Ua and Ub: Progress report, environmental programs. Salt Lake City, Utah: White River Shale Project, 1985.

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Ulishney, Aaron J. Oil and gas potential of the Icebox Formation (Ordovician). Grand Forks, ND: North Dakota Geological Survey, 2005.

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United States. Bureau of Land Management. White River Resource Area. Final environmental impact statement, Federal Prototype Oil Shale Tract C-a offtract lease. Lakewood, Colo: U.S. Dept. of the Interior, Bureau of Land Management, White River Resource Area, Craig District, 1986.

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New York (State). Legislature. Assembly. Committee on Environmental Conservation. Public hearing, draft supplemental generic environmental impact statement governing natural gas drilling. New York: Associated Reporters Int'l., Inc., 2009.

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Book chapters on the topic "Gas shales"

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Rasouli, Vamegh. "Geomechanics of Gas Shales." In Fundamentals of Gas Shale Reservoirs, 169–90. Hoboken, NJ: John Wiley & Sons, Inc, 2015. http://dx.doi.org/10.1002/9781119039228.ch8.

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Horsfield, Brian, Hans-Martin Schulz, Sylvain Bernard, Nicolaj Mahlstedt, Yuanjia Han, and Sascha Kuske. "Oil and Gas Shales." In Hydrocarbons, Oils and Lipids: Diversity, Origin, Chemistry and Fate, 1–34. Cham: Springer International Publishing, 2018. http://dx.doi.org/10.1007/978-3-319-54529-5_18-1.

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Horsfield, Brian, Hans-Martin Schulz, Sylvain Bernard, Nicolaj Mahlstedt, Yuanjia Han, and Sascha Kuske. "Oil and Gas Shales." In Hydrocarbons, Oils and Lipids: Diversity, Origin, Chemistry and Fate, 523–56. Cham: Springer International Publishing, 2020. http://dx.doi.org/10.1007/978-3-319-90569-3_18.

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Slatt, Roger M. "Sequence Stratigraphy of Unconventional Resource Shales." In Fundamentals of Gas Shale Reservoirs, 71–88. Hoboken, NJ: John Wiley & Sons, Inc, 2015. http://dx.doi.org/10.1002/9781119039228.ch4.

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Bjørlykke, Knut. "Unconventional Hydrocarbons: Oil Shales, Heavy Oil, Tar Sands, Shale Oil, Shale Gas and Gas Hydrates." In Petroleum Geoscience, 581–90. Berlin, Heidelberg: Springer Berlin Heidelberg, 2015. http://dx.doi.org/10.1007/978-3-642-34132-8_23.

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Bjørlykke, Knut. "Unconventional Hydrocarbons: Oil Shales, Heavy Oil, Tar Sands, Shale Gas and Gas Hydrates." In Petroleum Geoscience, 459–65. Berlin, Heidelberg: Springer Berlin Heidelberg, 2010. http://dx.doi.org/10.1007/978-3-642-02332-3_21.

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Pathak, Manas. "Storage Mechanisms of Oil and Gas in Shales." In Selective Neck Dissection for Oral Cancer, 1–6. Cham: Springer International Publishing, 2018. http://dx.doi.org/10.1007/978-3-319-02330-4_298-1.

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White, C. M. "An Introduction to Open-Tubular Gas Chromatography--Analysis of Fossil and Synthetic Fuels." In Composition, Geochemistry and Conversion of Oil Shales, 107–23. Dordrecht: Springer Netherlands, 1995. http://dx.doi.org/10.1007/978-94-011-0317-6_7.

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Balulla, Shama Mohammed, and E. Padmanabhan. "Variation in Surface Characteristics of Some Gas Shales from Marcellus Shale Formation in the USA." In ICIPEG 2014, 283–90. Singapore: Springer Singapore, 2015. http://dx.doi.org/10.1007/978-981-287-368-2_27.

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Gonzalez-Blanco, Laura, Enrique Romero, Cristina Jommi, Xavier Sillen, and Xiangling Li. "Exploring Fissure Opening and Their Connectivity in a Cenozoic Clay During Gas Injection." In Advances in Laboratory Testing and Modelling of Soils and Shales (ATMSS), 288–95. Cham: Springer International Publishing, 2017. http://dx.doi.org/10.1007/978-3-319-52773-4_33.

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Conference papers on the topic "Gas shales"

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Kale, Sagar, Chandra Rai, and Carl Sondergeld. "Rock Typing in Gas Shales." In SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers, 2010. http://dx.doi.org/10.2118/134539-ms.

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Sondergeld, Carl H., Raymond Joseph Ambrose, Chandra Shekhar Rai, and Jason Moncrieff. "Micro-Structural Studies of Gas Shales." In SPE Unconventional Gas Conference. Society of Petroleum Engineers, 2010. http://dx.doi.org/10.2118/131771-ms.

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Santra, Ashok, Hasmukh Patel, Arthur Hale, Nicolas Osorio, Arfaj Mohammad, Ramaswamy Jothibasu, and Elahbrouk Ehab. "Field Deployment of Nanomaterial Based Shale Inhibitors." In Middle East Oil, Gas and Geosciences Show. SPE, 2023. http://dx.doi.org/10.2118/213743-ms.

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Abstract Shale inhibition solutions that are commonly used in water-based fluids employ chemical systems that are not universally applicable. For example, kaolinite rich shales, can lose strength when exposed to KCl through cation exchange with potassium. In the United States, government regulations prohibit the disposal of greater than 3,000 ppm chloride on lease or 1,000 ppm chloride off lease. The hazardous nature of choline chloride restricts its use as shale inhibitor for water-based fluids. Nanosilica Based Shale Inhibitor (NSBSI) has been developed to mitigate the difficulties in clay stabilization in particularly challenging formations. NSBSI is used when drilling with low solids, non-dispersed muds, such as polymer and PAC muds. It can be used as an alternative to polyamine-based shale inhibitors and silicate-based shale inhibitors. Field trials were conducted in three wells. Commonly used shale inhibitor (polyamine based) were replaced by NSBSI in mud formulations in order to complete the field trials. Trouble-free drilling through problematic shale sections with no changes in mud properties, and no indications of lack of inhibition were experienced. Further addressing field requirements for shale inhibition in water-based muds, we have also developed a second shale-inhibiting product which is functionalized nanoplatelets composed of amine functionalities anchored on the nanometer-thick magnesium silicates (LMS-NH2). A facile synthetic approach was employed to synthesize lab-scale quantity of LMS-NH2 through combination of sol-gel and precipitation techniques. The structural characterization was conducted using powder X-ray diffraction (XRD), Fourier transformed infrared spectroscopy (FTIR), and thermogravimetric analysis (TGA) to evaluate generation of anticipated LMS-NH2. Shale stabilization characteristics of LMS-NH2 were tested and compared with other commercial shale inhibitors. Clay swelling and clay dispersion tests were performed to demonstrate the effectiveness of the impermeable coating of nano-platelets on to the clay-rich shales. The LMS-NH2 have demonstrated 87% recovery of swellable shales after dispersion tests. The microscopic study conducted on the treated shales reveals the formation of inorganic film on the shales, which provide impervious coating to protect the water susceptible clays. The linear swelling measurements were also performed to understand the effectiveness of LMS-NH2 over 72 hours demonstrating minimized the hydration and subsequent swelling of clay-rich shales. The newly developed inhibitor in the current study has outperformed conventional shale inhibitors wherein the presence of inorganic constituents aids stronger film formation compared to solely organic inhibitors. Comparative studies have been carried out against commercially used shale inhibitors using linear swell meter, dispersion test and pore pressure penetration test and the results will be presented.
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Slatt, Roger Malcolm, Prerna Singh, R. P. Philp, Kurt J. Marfurt, Younane N. Abousleiman, and N. R. O'Brien. "Workflow for Stratigraphic Characterization of Unconventional Gas Shales." In SPE Shale Gas Production Conference. Society of Petroleum Engineers, 2008. http://dx.doi.org/10.2118/119891-ms.

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Ewy, R. T. "Mechanical Anisotropy of Gas Shales and Claystones." In Fourth EAGE Shale Workshop. Netherlands: EAGE Publications BV, 2014. http://dx.doi.org/10.3997/2214-4609.20140037.

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Sander, Regina, Zhejun Pan, Luke D. Connell, Michael Camilleri, and Mihaela Grigore. "Controls on CH4 Adsorption on Shales: Characterisation of Beetaloo Sub-Basin Gas Shales and Comparison to Global Shales." In SPE Asia Pacific Oil and Gas Conference and Exhibition. Society of Petroleum Engineers, 2018. http://dx.doi.org/10.2118/191896-ms.

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McLellan, P. J., and K. Cormier. "Borehole Instability in Fissile, Dipping Shales, Northeastern British Columbia." In SPE Gas Technology Symposium. Society of Petroleum Engineers, 1996. http://dx.doi.org/10.2118/35634-ms.

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Jiang, M., and K. Spikes. "Seismic Reservoir Characterization of Unconventional Gas Shales." In 76th EAGE Conference and Exhibition 2014. Netherlands: EAGE Publications BV, 2014. http://dx.doi.org/10.3997/2214-4609.20141209.

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Luffel, D. L., C. W. Hopkins, and P. D. Schettler. "Matrix Permeability Measurement of Gas Productive Shales." In SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers, 1993. http://dx.doi.org/10.2118/26633-ms.

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Aljamaan, Hamza, Cynthia M. Ross, and Anthony R. Kovscek. "Multiscale Imaging of Gas Adsorption in Shales." In SPE Unconventional Resources Conference. Society of Petroleum Engineers, 2017. http://dx.doi.org/10.2118/185054-ms.

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Reports on the topic "Gas shales"

1

Coyner, K., T. J. Katsube, M. E. Best, and M. Williamson. Gas and water permeability of tight shales from the Venture gas field, offshore Nova Scotia. Natural Resources Canada/ESS/Scientific and Technical Publishing Services, 1993. http://dx.doi.org/10.4095/134279.

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Katsube, T. J., N. Scromeda, and M. Williamson. Effective porosity of tight shales from the Venture gas field, offshore Nova Scotia. Natural Resources Canada/ESS/Scientific and Technical Publishing Services, 1992. http://dx.doi.org/10.4095/132887.

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Godec, Michael. Assessment of Factors Influencing Effective CO2 Storage Capacity and Injectivity in Eastern Gas Shales. Office of Scientific and Technical Information (OSTI), June 2013. http://dx.doi.org/10.2172/1123817.

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Brandon C. Nuttall, Cortland F. Eble, James A. Drahovzal, and R. Marc Bustin. Analysis of Devonian Black Shales in Kentucky for Potential Carbon Dioxide Sequestration and Enhanced Natural Gas Production. Office of Scientific and Technical Information (OSTI), September 2005. http://dx.doi.org/10.2172/920185.

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Brandon C. Nuttall. ANALYSIS OF DEVONIAN BLACK SHALES IN KENTUCKY FOR POTENTIAL CARBON DIOXIDE SEQUESTRATION AND ENHANCED NATURAL GAS PRODUCTION. Office of Scientific and Technical Information (OSTI), January 2005. http://dx.doi.org/10.2172/836635.

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Brandon C. Nuttall. ANALYSIS OF DEVONIAN BLACK SHALES IN KENTUCKY FOR POTENTIAL CARBON DIOXIDE SEQUESTRATION AND ENHANCED NATURAL GAS PRODUCTION. Office of Scientific and Technical Information (OSTI), January 2005. http://dx.doi.org/10.2172/837011.

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Brandon C. Nuttall. ANALYSIS OF DEVONIAN BLACK SHALES IN KENTUCKY FOR POTENTIAL CARBON DIOXIDE SEQUESTRATION AND ENHANCED NATURAL GAS PRODUCTION. Office of Scientific and Technical Information (OSTI), April 2005. http://dx.doi.org/10.2172/839558.

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Brandon C. Nuttall. ANALYSIS OF DEVONIAN BLACK SHALES IN KENTUCKY FOR POTENTIAL CARBON DIOXIDE SEQUESTRATION AND ENHANCED NATURAL GAS PRODUCTION. Office of Scientific and Technical Information (OSTI), January 2004. http://dx.doi.org/10.2172/822700.

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Brandon C. Nuttall. ANALYSIS OF DEVONIAN BLACK SHALES IN KENTUCKY FOR POTENTIAL CARBON DIOXIDE SEQUESTRATION AND ENHANCED NATURAL GAS PRODUCTION. Office of Scientific and Technical Information (OSTI), April 2004. http://dx.doi.org/10.2172/824015.

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Brandon C. Nuttall. ANALYSIS OF DEVONIAN BLACK SHALES IN KENTUCKY FOR POTENTIAL CARBON DIOXIDE SEQUESTRATION AND ENHANCED NATURAL GAS PRODUCTION. Office of Scientific and Technical Information (OSTI), August 2004. http://dx.doi.org/10.2172/831083.

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