Shale gas potential of the Prince Albert Formation: A preliminary study

2019 ◽  
Vol 122 (4) ◽  
pp. 541-554 ◽  
Author(s):  
H. Mosavel ◽  
D.I. Cole ◽  
A.M. Siad
Keyword(s):  
Shale Gas ◽  
Vitrinite Reflectance ◽  
Marcellus Shale ◽  
Mercury Porosimetry ◽  
The United States ◽  
Karoo Basin ◽  
Type Iv ◽  
Volume Porosity ◽  
Rock Eval ◽  
Gas Potential

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.

scholarly journals Organic geochemistry and mineralogical characterization of the Paleocene Ranikot Formation shales in selected areas of Southern Indus Basin Pakistan.

2021 ◽  
Author(s):  
Hussain Asghar ◽  
◽  
Saeed Abbas ◽  
Muhammad S. Khan ◽  
Samina Jahandad ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Organic Geochemistry ◽  
Vitrinite Reflectance ◽  
Xrd Analysis ◽  
Indus Basin ◽  
Gas Chromatography Mass Spectrometry ◽  
Mineralogical Characterization ◽  
Type Iv ◽  
Rock Eval

Southern Indus Basin is one of the promising regions in Pakistan as a commercially producing oil and gas perspective. The current research presents the geochemical characterization of the Ranikot Formation shales from Southern Indus Basin based on total organic carbon (TOC), Rock-Eval (RE) pyrolysis, organic petrography, gas chromatography-mass spectrometry (GC-MS), and x-ray diffraction (XRD) analyses. The average TOC of Ranikot shale is 4.6 wt. %, indicating very good hydrocarbon potential. Types III/IV kerogens were identified in Ranikot shale. The maceral data also suggest that the Type of kerogen present in Ranikot shale is dominantly Types II-III, with the minor occurrence of Type IV. The vitrinite reflectance, pyrolysis Tmax and methylphenanthrene indices values specify immature levels of the shales. The normal alkane data reflect that marine macrophyte, algae, and land plants were contributed to the organic matter of Ranikot shales. Dibenzothiophene/phenanthrene ratio (0.11), phytane/n-C18 ratio (0.53), pyrite, and glauconite elucidate that the depositional environment of the Ranikot shale is marine. The XRD analysis of the shale from the Ranikot Formation revealed that it is brittle shale and dominated by 39.5 to 50.9 wt. % quartz. The present study, integration with the US EIA report demarcated the Ranikot Formation influential horizon as a shale gas resource.

scholarly journals Emerging unconventional shale plays in Western Australia

2013 ◽  
Vol 53 (1) ◽  
pp. 313 ◽  
Author(s):  
K. Ameed R. Ghori
Keyword(s):  
Shale Gas ◽  
Early Stage ◽  
Marcellus Shale ◽  
Gas Production ◽  
Source Rocks ◽  
Lower Permian ◽  
Upper Ordovician ◽  
Canning Basin ◽  
The Us ◽  
Gas Potential

Production of shale gas in the US has changed its position from a gas importer to a potential gas exporter. This has stimulated exploration for shale-gas resources in WA. The search started with Woodada Deep–1 (2010) and Arrowsmith–2 (2011) in the Perth Basin to evaluate the shale-gas potential of the Permian Carynginia Formation and the Triassic Kockatea Shale, and Nicolay–1 (2011) in the Canning Basin to evaluate the shale-gas potential of the Ordovician Goldwyer Formation. Estimated total shale-gas potential for these formations is about 288 trillion cubic feet (Tcf). Other petroleum source rocks include the Devonian Gogo and Lower Carboniferous Laurel formations of the Canning Basin, the Lower Permian Wooramel and Byro groups of the onshore Carnarvon Basin, and the Neoproterozoic shales of the Officer Basin. The Canning and Perth basins are producing petroleum, whereas the onshore Carnarvon and Officer basins are not producing, but they have indications for petroleum source rocks, generation, and migration from geochemistry data. Exploration is at a very early stage, and more work is needed to estimate the shale-gas potential of all source rocks and to verify estimated resources. Exploration for shale gas in WA will benefit from new drilling and production techniques and technologies developed during the past 15 years in the US, where more than 102,000 successful gas production wells have been drilled. WA shale-gas plays are stratigraphically and geochemically comparable to producing plays in the Upper Ordovician Utica Shale, Middle Devonian Marcellus Shale and Upper Devonian Bakken Formation, Upper Mississippian Barnett Shale, Upper Jurassic Haynesville-Bossier formations, and Upper Cretaceous Eagle Ford Shale of the US. WA is vastly under-explored and emerging self-sourcing shale plays have revived onshore exploration in the Canning, Carnarvon, and Perth basins.

Seismic imaging of dolerite sills and volcanic vents in the Central Karoo, South Africa: implications for shale gas potential

2021 ◽  
Author(s):  
S.E. Scheiber-Enslin ◽  
M. Manzi ◽  
S.J. Webb
Keyword(s):  
South Africa ◽  
Shale Gas ◽  
Global Climate ◽  
Magnetic Data ◽  
Seismic Reflection Profile ◽  
Magnetic Studies ◽  
Seismic Line ◽  
Seismic Section ◽  
Karoo Basin ◽  
Gas Potential

Abstract The Karoo Basin of South Africa covers an area of 700 000 km2 and has been identified as a possible shale gas reserve. Any evaluation of the shale gas potential of the basin must consider the widespread dolerite dykes and sills. These intrusions were emplaced into the Karoo Supergroup and are well dated at around 183 Ma. Their intrusion triggered the explosive releases of gas in the basin, marked on surface by breccia pipes and hydrothermal vents. This outpouring of gas has been proposed as a significant contributor to global climate change. Research into the three-dimensional interconnected structure of these dolerite sills and dykes and their interaction with the hydrocarbon rich layers in the lower part of the Karoo Supergroup has been limited to localized observations of outcrop, magnetic data, legacy seismic data (from the 1970s) and well core. Here we present an interpreted 65 km long higher-resolution 2D seismic reflection profile across the Karoo Basin, approximately 100 km southeast of Trompsburg. These data were collected in the 1990s and at the time deeper structures along the line interpreted. In this study we focus on the top 0.6 to 2 seconds TWT of the data. The seismic line images the interconnected and cross cutting nature of the dolerite dykes and sills along the profile. We also report possible evidence of a gas escape structure (approximately 2.5 km in diameter at surface) emerging near the edge of a dolerite sill in close proximity to the Whitehill Formation, which is the main target for shale gas exploration. This suggests that gas vents in the eastern Karoo Basin close to Lesotho are due to the release of gas from the carbonaceous shales of the Ecca Group. This is similar to breccia pipes mapped on surface in the western part of the Karoo Basin. This seismic section highlights why dolerite sills and dykes must be considered when evaluating the shale gas potential of the Karoo Basin. We propose that better characterization of the Karoo Basin subsurface by seismic and magnetic studies is necessary prior to any efforts to calculate shale gas reserves.

scholarly journals The concept of well integrity in gas production activities

2016 ◽  
Vol 23 (2) ◽  
pp. 205-213 ◽  
Author(s):  
Peter Reichetseder
Keyword(s):  
Drinking Water ◽  
Shale Gas ◽  
Environmental Protection Agency ◽  
Marcellus Shale ◽  
The United States ◽  
Gas Production ◽  
Well Integrity ◽  
Drinking Water Resources ◽  
The Us ◽  
Geological Situation

Abstract Shale gas production in the US, predominantly from the Marcellus shale, has been accused of methane emissions and contaminating drinking water under the suspicion that this is caused by hydraulic fracturing in combination with leaking wells. Misunderstandings of the risks of shale gas production are widespread and are causing communication problems. This paper discusses recent preliminary results from the US Environmental Protection Agency (EPA) draft study, which is revealing fact-based issues: EPA did not find evidence that these mechanisms have led to widespread, systemic impacts on drinking water resources in the United States, which contrasts many broad-brushed statements in media and public. The complex geological situation and extraction history of oil, gas and water in the Marcellus area in Pennsylvania is a good case for learnings and demonstrating the need for proper analysis and taking the right actions to avoid problems. State-of-the-art technology and regulations of proper well integrity are available, and their application will provide a sound basis for shale gas extraction.

scholarly journals Deflating the shale gas potential of South Africa’s Main Karoo basin

2017 ◽  
Vol 113 (9/10) ◽  
Author(s):  
Michiel de Kock ◽  
Nicolas Beukes ◽  
Elijah Adeniyi ◽  
Doug Cole ◽  
Annette Götz ◽  
...  
Keyword(s):  
Organic Carbon ◽  
Total Organic Carbon ◽  
Shale Gas ◽  
Vitrinite Reflectance ◽  
Gas Content ◽  
Carbonaceous Shale ◽  
Organic Carbon Content ◽  
Hydrocarbon Generation ◽  
Developmental Potential ◽  
Karoo Basin

The Main Karoo basin has been identified as a potential source of shale gas (i.e. natural gas that can be extracted via the process of hydraulic stimulation or ‘fracking’). Current resource estimates of 0.4–11x109 m3 (13–390 Tcf) are speculatively based on carbonaceous shale thickness, area, depth, thermal maturity and, most of all, the total organic carbon content of specifically the Ecca Group’s Whitehill Formation with a thickness of more than 30 m. These estimates were made without any measurements on the actual available gas content of the shale. Such measurements were recently conducted on samples from two boreholes and are reported here. These measurements indicate that there is little to no desorbed and residual gas, despite high total organic carbon values. In addition, vitrinite reflectance and illite crystallinity of unweathered shale material reveal the Ecca Group to be metamorphosed and overmature. Organic carbon in the shale is largely unbound to hydrogen, and little hydrocarbon generation potential remains. These findings led to the conclusion that the lowest of the existing resource estimates, namely 0.4x109 m3 (13 Tcf), may be the most realistic. However, such low estimates still represent a large resource with developmental potential for the South African petroleum industry. To be economically viable, the resource would be required to be confined to a small, well-delineated ‘sweet spot’ area in the vast southern area of the basin. It is acknowledged that the drill cores we investigated fall outside of currently identified sweet spots and these areas should be targets for further scientific drilling projects.

Application of integrated formationevaluation and three-dimensional modeling in shale gas prospect identification

2020 ◽  
Vol 1 (3) ◽  
Author(s):  
Jin Gao ◽  
Guangdi Liu ◽  
Zhe Cao ◽  
Lijun Du ◽  
Yuhua Kong
Keyword(s):  
Sorption Capacity ◽  
Shale Gas ◽  
Vitrinite Reflectance ◽  
Three Dimensional ◽  
Junggar Basin ◽  
Northwest China ◽  
Wide Distribution ◽  
Methane Sorption ◽  
Northwestern Margin ◽  
Gas Potential

Identifying the shale gas prospect is crucial for gas extraction from such reservoirs. Junggar Basin (in Northwest China) is widely considered to have high potential as a shale gas resource, and the Jurassic, the most significant gas source strata, is considered as prospective for shale gas exploration and development. This study evaluated the Lower Jurassic Badaowan Formation shale gas potential combined with geochemical, geological, and well logging data, and built a three-dimensional (3D) model to exhibit favorable shale gas prospects. In addition, methane sorption capacity was tested for verifying the prospects. The Badaowan shale had an average total organic carbon (TOC) content of 1.30 wt. % and vitrinite reflectance (Ro) ranging from 0.47% to 0.81% with dominated type III organic matter (OM). X-ray diffraction (XRD) analyses showed that mineral composition of Badaowan shale was fairly homogeneous and dominated by clay and brittle minerals. 67 wells were used to identify prospective shale intervals and to delineate the area of prospects. Consequently, three Badaowan shale gas prospects in Junggar Basin were identified: the northwestern margin prospect, eastern Central Depression prospect and Wulungu Depression prospect. The middle interval of the northwestern margin prospect was considered to be the most favorable exploration target benefitted by wide distribution and high lateral continuity. Generally, methane sorption capacity of the Badaowan shale was comparable to that of the typical gas shales with similar TOC content, showing a feasible gas potential.

scholarly journals Jurassic Terrestrial Shale Gas Potential of the Northern Kashi Sag in the Tarim Basin, Northwestern China

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-16
Author(s):  
Wei Wu ◽  
Zhiwei Liao ◽  
Honghan Chen ◽  
Shaohu Li ◽  
Ao Su ◽  
...  
Keyword(s):  
Organic Matter ◽  
Surface Area ◽  
Tarim Basin ◽  
Shale Gas ◽  
Pore Volume ◽  
Middle Jurassic ◽  
Vitrinite Reflectance ◽  
Mature Stage ◽  
Average Pore ◽  
Gas Potential

Evaluation of terrestrial shale gas resource potential is a hot issue in unconventional oil and gas exploration. Organic-rich shales are widely developed in the Jurassic strata of Tarim Basin, but their shale gas potential has not been described well. In the study, the Lower-Middle Jurassic fine-grained sedimentary rocks (Kangsu and Yangye Formations) in northern Kashi Sag, northwestern Tarim Basin, were taken as the study object. The comprehensive studies include petrology, mineralogy, organic geochemistry, and physical properties, which were used to characterize the organic matter and reservoir characteristics. Results show that the Jurassic terrestrial shale in the northern Kashi Sag was mainly deposited in lakes, rivers, and deltas. The thickness of black lacustrine shale developed in the Early-Middle Jurassic in the study area is generally over 100 m. The total organic carbon (TOC) content is rich, averaging 2.77%. The vitrinite reflectance ( R o ) values indicate that the Lower Jurassic shale organic matter is in the early mature–mature stage, while the Middle Jurassic is in the mature stage. Besides, organic matter is primarily II and III in kerogen types. The whole shale contains a large number of clay minerals, especially illite. The average brittle minerals such as quartz and feldspar are 28.67%, and the average brittleness index is 38.63%. Nanoscale pores containing intergranular pores, dissolution pores, and organic pores, coupled with microcracks, are well developed in Jurassic shale. The sample’s average pore volume is 0.017 cm3/g, and the specific surface area is 9.36 m2/g. Mesoporous contribute the most to pore volume, while the number of microporous is the largest. Both of them provide most of the surface area for the shale. Combined with regional geologic settings, we propose that the Jurassic terrestrial shale has good-excellent shale gas exploration potential and development prospects.

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