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.

Shale gas potential of the major marine shale formations in the Upper Yangtze Platform, South China, Part II: Methane sorption capacity

Fuel ◽  
2014 ◽  
Vol 129 ◽  
pp. 204-218 ◽  
Author(s):  
Jingqiang Tan ◽  
Philipp Weniger ◽  
Bernhard Krooss ◽  
Alexej Merkel ◽  
Brian Horsfield ◽  
...  
Keyword(s):  
Sorption Capacity ◽  
South China ◽  
Shale Gas ◽  
Yangtze Platform ◽  
Shale Formations ◽  
Marine Shale ◽  
Methane Sorption ◽  
Gas Potential

Petroleum generation and expulsion characteristics of Lower and Middle Jurassic source rocks on the southern margin of Junggar Basin, northwest China: implications for unconventional gas potential

2014 ◽  
Vol 51 (6) ◽  
pp. 537-557 ◽  
Author(s):  
Jigang Guo ◽  
Xiongqi Pang ◽  
Fengtao Guo ◽  
Xulong Wang ◽  
Caifu Xiang ◽  
...  
Keyword(s):  
Source Rock ◽  
Shale Gas ◽  
Middle Jurassic ◽  
Junggar Basin ◽  
Northwest China ◽  
Source Rocks ◽  
Coal Bed ◽  
Southern Margin ◽  
Petroleum Generation ◽  
Gas Potential

Jurassic strata along the southern margin of Junggar Basin are important petroleum system elements for exploration in northwest China. The Lower and Middle Jurassic source rock effectiveness has been questioned as exploration progresses deeper into the basin. These source rocks are very thick and are distributed widely. They contain a high total organic carbon composed predominantly of Type III kerogen, with some Type II kerogen. Our evaluation of source rock petroleum generation characteristics and expulsion history, including one-dimensional basin modeling, indicates that Jurassic source rocks are gas prone at deeper depths. They reached peak oil generation during the Early Cretaceous and began to generate gas in the Late Cretaceous. Gas generation peaked in the Paleogene–Neogene. Source rock shales and coals reached petroleum expulsion thresholds at thermal maturities of 0.8% and 0.75% vitrinite reflectance, respectively, when the petroleum expulsion efficiency was ∼40%. The petroleum generated and expelled from these source rocks are 3788.75 × 108 and 1507.55 × 108 t, respectively, with a residual 2281.20 × 108 t retained in the source rocks. In these tight reservoirs, a favorable stratigraphic relationship (where tight sandstone reservoirs directly overlie the source rocks) indicates short vertical and horizontal migration distances. This indicates the potential for a large, continuous, tight-sand gas resource in the Lower and Middle Jurassic strata. The in-place natural gas resources in the Jurassic reservoirs are up to 5.68 × 1012 − 15.14 × 1012 m3. Jurassic Badaowan and Xishanyao coals have geological characteristics that are favorable for coal-bed methane resources, which have an in-place resource potential between 3.60 × 1012 and 11.67 × 1012 m3. These Lower and Middle Jurassic strata have good shale gas potential compared with active US shale gas, and the inferred in-place shale gas resources in Junggar Basin are between 20.73 × 1012 and 113.89 × 1012 m3. This rich inferred conventional and unconventional petroleum resource in tight-sand, coal-bed, and shale gas reservoirs makes the deeper Jurassic strata along the southern margin of Junggar Basin a prospective target for future exploration.

The Influences of the Rank of Coal on Methane Sorption Capacity in Coals/Wpływ Rzędu Węgla Na Pojemność Sorpcyjną Metanu W Węglach

2014 ◽  
Vol 59 (2) ◽  
pp. 509-516
Author(s):  
Andrzej Olajossy
Keyword(s):  
Sorption Capacity ◽  
Coalbed Methane ◽  
Vitrinite Reflectance ◽  
Sorption Isotherms ◽  
Volatile Matter ◽  
Low Rank ◽  
Hard Coal ◽  
Petrographic Composition ◽  
Methane Sorption ◽  
Indian Coals

Abstract Methane sorption capacity is of significance in the issues of coalbed methane (CBM) and depends on various parameters, including mainly, on rank of coal and the maceral content in coals. However, in some of the World coals basins the influences of those parameters on methane sorption capacity is various and sometimes complicated. Usually the rank of coal is expressed by its vitrinite reflectance Ro. Moreover, in coals for which there is a high correlation between vitrinite reflectance and volatile matter Vdaf the rank of coal may also be represented by Vdaf. The influence of the rank of coal on methane sorption capacity for Polish coals is not well understood, hence the examination in the presented paper was undertaken. For the purpose of analysis there were chosen fourteen samples of hard coal originating from the Upper Silesian Basin and Lower Silesian Basin. The scope of the sorption capacity is: 15-42 cm3/g and the scope of vitrinite reflectance: 0,6-2,2%. Majority of those coals were of low rank, high volatile matter (HV), some were of middle rank, middle volatile matter (MV) and among them there was a small number of high rank, low volatile matter (LV) coals. The analysis was conducted on the basis of available from the literature results of research of petrographic composition and methane sorption isotherms. Some of those samples were in the form (shape) of grains and others - as cut out plates of coal. The high pressure isotherms previously obtained in the cited studies were analyzed here for the purpose of establishing their sorption capacity on the basis of Langmuire equation. As a result of this paper, it turned out that for low rank, HV coals the Langmuire volume VL slightly decreases with the increase of rank, reaching its minimum for the middle rank (MV) coal and then increases with the rise of the rank (LV). From the graphic illustrations presented with respect to this relation follows the similarity to the Indian coals and partially to the Australian coals.

Geological controls and methane sorption capacity of marine shales of the Fuling shale gas field in the eastern Sichuan Basin, China

2017 ◽  
Vol 23 (4) ◽  
pp. 466-475 ◽  
Author(s):  
Xiaoming Zhang ◽  
Wanzhong Shi ◽  
Qinhong Hu ◽  
Shiwan Zhang ◽  
Haiyan Hu ◽  
...  
Keyword(s):  
Sorption Capacity ◽  
Shale Gas ◽  
Sichuan Basin ◽  
Gas Field ◽  
Eastern Sichuan Basin ◽  
Methane Sorption ◽  
Eastern Sichuan

Geology, resource potentials, and properties of emerging and potential China shale gas and shale oil plays

2015 ◽  
Vol 3 (2) ◽  
pp. SJ1-SJ13 ◽  
Author(s):  
Shu Jiang ◽  
Jinchuan Zhang ◽  
Zhiqiang Jiang ◽  
Zhengyu Xu ◽  
Dongsheng Cai ◽  
...  
Keyword(s):  
South China ◽  
Shale Gas ◽  
Oil And Gas ◽  
Northwest China ◽  
Shale Oil ◽  
Yangtze Platform ◽  
Lower Paleozoic ◽  
High Maturity ◽  
Shale Reservoirs ◽  
Gas Potential

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.

scholarly journals Methane Sorption Capacity of Organics and Clays in High-Over Matured Shale-Gas Systems

2014 ◽  
Vol 32 (6) ◽  
pp. 927-942 ◽  
Author(s):  
Erping Fan ◽  
Shuheng Tang ◽  
Chenglong Zhang ◽  
Qiulei Guo ◽  
Changhua Sun
Keyword(s):  
Sorption Capacity ◽  
Shale Gas ◽  
Methane Sorption

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 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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