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Geochemical and Preliminary Reservoir Characteristics of the Carboniferous–Permian Coal-Bearing Strata in the Junger Area, Northeastern Ordos Basin, China: Source Implications for Unconventional Gas Hao Xu, Daiyong Cao, Yong Li, Jincheng Liu, Xinlei Niu, Yan Zhang, and Guohong Qin Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.6b00996 • Publication Date (Web): 09 Aug 2016 Downloaded from http://pubs.acs.org on August 10, 2016

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Geochemical and Preliminary Reservoir Characteristics of the Carboniferous–Permian Coal-Bearing Strata in the Junger Area, Northeastern Ordos Basin, China: Source Implications for Unconventional Gas Hao Xu1, 2, Daiyong Cao1, 2, Yong Li1, 2*, JinCheng Liu1, 2, Xinlei Niu1, 2, Yan Zhang1, 2, Guohong Qin1, 2 (1. State Key Laboratory of Coal Resources and Safe Mining, China University of Mining and Technology, Beijing 100083, China; 2. College of Geosciences and Surveying Engineering, China University of Mining and Technology, Beijing 100083, China)

Abstract: Unconventional natural gas development, including coalbed methane, shale gas and tight sand gas, has received extensive attention recently in coal-bearing basins. This study provides a case study of the hydrocarbon generation potential (coal and shale) and reservoir characterization (coal, shale and sandstone) of samples from Carboniferous–Permian coal-bearing strata in the Junger area, northeastern Ordos Basin, China. Results show that the coal is dominated by vitrinite (9.3–84.1%) and inertinite (14.0–82.5%) with an average total vitrinite and inertinite content higher than 90%, and maximum vitrinite reflectance (Ro,max) values from 0.44% to 0.81%. The shales contain mainly type II kerogen with high total organic carbon content (0.36–31.58%) and relatively low Ro,max (0.45–0.72%). The hydrocarbon generation potential of all the shale samples ranges from 3.25 to 82.82 mg/g rock, and the hydrogen index values range from 100.31 to 768.06 mg HC/g. Three types of fluid inclusions were detected in the microfractures in/through quartz grains, particle pores, dissolution holes of calcite cement, and microfractures in calcite veins, including liquid, gas–liquid and gas hydrocarbon inclusions, with yellow-green and blue fluorescence. The homogenization temperatures range from 60°C to 140°C and combined with the geothermal evolution of the research area and the salinity of the fluid inclusions, the continuous charging history of unconventional gas can be divided into three stages, two hydrocarbon charging stages (80–110°C, corresponding to Late Triassic–Middle Jurassic and 110–140°C, corresponding to Middle Jurassic–Middle Cretaceous) and one

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adjustment stage (60–80°C, Late Cretaceous). The coal samples show the highest porosity (10.4–18.0%, avg. 14.3%) and permeability (2.17–2.93 mD, avg. 2.6 mD), followed by sandstones with porosities ranging from 10.1–13.0% (avg. 11.6%) and permeability varying between 0.51 and 1.16 mD (avg. 0.84 mD). Shale samples have the lowest porosity (1.1–4.7%, avg. 2.48%) and permeability values (0.003–0.37 mD, avg. 0.1 mD). The extensively developed and thickly deposited source rocks, and multiple lithological cycles of coal-bearing strata set a good foundation for the development of unconventional gases, and the western Junger area should be newly considered as a target area for its appropriate burial depth, great hydrocarbon potential and favorable preservation conditions. Keywords:

unconventional

natural

gas;

coalbed

methane;

hydrocarbon

generation;

reservoir

characterization; fluid inclusions; Junger area

1 Introduction Coalbed methane (CBM), shale gas and tight sand gas are important unconventional natural gas resources, which are all present in coal-bearing strata. Innovators worldwide have demonstrated that the amount of natural gas that can be recovered is vastly larger than previously reported1. Workflows for optimization of unconventional gas development have been proposed based on newly emerging evaluation methods, such as complex systems and numerical modeling techniques2-3. Basin-centered gas systems, indicating coal and carbonaceous shale as the main source rocks and sandstones, siltstones, and carbonates with low permeability as the common reservoirs, have been proposed4. Many scholars have discussed the geological factors controlling CBM, shale gas and tight sand gas from different aspects5-10, and have also indicated the coexistence of unconventional gases in the same basins11. A few large unconventional gas fields have been developed in the coal-bearing strata in the northeast


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of the Ordos Basin, China, including CBM in the Baode area and tight sand gas in the Linxing and Shenfu areas12-14. The Junger area is famous for its thick and widely distributed low rank Carboniferous–Permian coal seams and abundant elements in coal, especially the no. 6 coal seam15. In recent years, CBM and shale gas development have also been attempted with several wells being drilled. However, no systematic analyses have been conducted on unconventional gas production potentials in this area16. The folds and faults are seldom developed and the strata is gentle in the Junger area. In addition, the coal-bearing strata are widely developed with multilayer and thickness source rocks (coal and shale). Therefore, the geological background and developmental characteristics of the coal-bearing strata in the Junger are similar to those of the Powder River Basin in the USA17-19, which is the most productive coalbed methane reserve in the world19,20. The Niobrara shale and the shallower tight sand formation (Parkman formation) assets are one of CNOOC’s (China National Offshore Oil Corporation) unconventional resources in USA21. This indicates that evaluation of source rock potential and discussion of the preliminary characterization of coal, shale and sandstones is important for the Junger area. In this paper, we report laboratory-tested data for coal, shale and sandstones from newly drilled well cores and coal mines in the Junger area, with an emphasis on the discussion of geochemical characteristics and hydrocarbon generation potential of the coal-bearing strata. The results will be beneficial for the exploration of CBM, shale gas and tight sand gas in the study area and other basins with coal-bearing strata.

2 Geological Setting The Junger area is situated in the northeast of Ordos Basin, with its tectonic unit belonging to the North China platform. The strata occur in a monocline striking S–N and inclined to the west at less than


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10°. The structures are seldom developed with few folds and faults occurring to the east, which were formed during the uplift and subsidence of crustal movement15 (Fig. 1). The strata are characterized by thick and widely distributed coal seams within the Taiyuan and Shanxi formations (Fig. 2). The underlying strata are composed of Cambrian and Ordovician formations and the Carboniferous Pennsylvanian Benxi formation. The overlying strata are non-coal-bearing and include the Pennsylvanian Xiashihezi, Shangshihezi and Shiqianfeng Formations, Triassic and Cretaceous Formations and Neogene deposits16.

3 Samples and Methods 3.1 Samples A total of 54 fresh samples (19 coal samples, 29 shales, and 6 sandstones) from Taiyuan and Shanxi formations were collected from six coalfields and two drilling wells for analysis, which were all carefully packed and directly delivered to the laboratories for the experiments. All coal samples were selected from the No. 6 coal seam, which occurs in the Taiyuan formations, and is the main target for coal mining and CBM development. The shale and sandstone samples from the Taiyuan and Shanxi formations were collected from the well cores in the drilling field.

3.2 Experimental approach All of the experiments described below were conducted according to standard procedures to ensure their analytical accuracy. coal samples (16) were tested for maceral analysis and maximum vitrinite reflectance (Ro,max) measurements were taken for the evaluation of gas generation potential. The shale samples (28) were tested for total organic carbon (TOC) content, with a subset (16 of the 28) being tested with Rock-Eval Pyrolysis to ascertain their hydrogen generation potential. One shale which calcite veins


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are developed and four of the six sampled sandstones were tested for fluid inclusions (FIs) to gain insight into their fluid activity. Furthermore, to aid discussion of the structural characteristics of the reservoir pores, three coals, two sandstones and four shales were tested with a mercury capillary injection and four sandstone samples and one shale with calcite veins were selected to analyze the geochemistry of FIs. Maceral analysis and Ro,max measurements were performed on the same polished surfaces of samples using a DM4500P polarizing microscope, according to Standards SY/T 5124-2012 and SY/T 5125-1996. The TOC content was measured using a CS230 device, following the Chinese National Standard GB/T 19145-2003. Rock-Eval Pyrolysis was measured following the Chinese National Standard GB/T 18602-2012, using an OGE-VI Rock-Eval apparatus to characterize Tmax (the temperature at which the maximum number of hydrocarbons are generated) and bulk thermal parameters. Microscopic observation of FIs was carried out using a Zeiss Imager.M2m microscope with 5×, 10× and 20× objective lenses. Measurement for the homogenization temperature and salinity of FIs was conducted using a LINKAM THMS600 at a 20°C temperature and 40% relative humidity. In order to analyze the porosity of potential reservoir (coal, shale and sandstones), three coal samples, four shale samples and two sandstone samples were selected for pressured-mercury testing using an Autopore IV 9510 series porosimeter. The test followed the conventional method according to Standard SY/T 5346-2005 at 8°C temperature, 40% humidity and 103.5 kPa.

4 Results and Discussion 4.1 Geochemical characterization of source rocks Coals in the Junger area are generally subbituminous–high vol. bituminous with Ro,max of between 0.44%


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and 0.81% (avg. 0.56%), indicating that the coal is in the low mature to mature stage15. The coals have not yet entered the best gas generation stage, since it has been reported that the optimum coal rank for CBM generation is 1.2% to 2.5% Ro22-24. When Ro,max< 0.6%, the coal is in the biogas generation stage, and then it enters into the thermogenic gas generation stage as Ro,max increases25. Thus, the gases in the study area may include biogenic and thermogenic gases. The maceral composition of coal is mainly vitrinite (9.3–84.1%, avg. 41.4%) and inertinite (14–82.5%, avg. 48.7%), with limited exinite and few minerals. The TOC content is a key parameter in determining source rock quality and petroleum potential. Hydrocarbon generation also depends upon the level of thermomaturation and the kerogen type of the source rocks. The maturity and kerogen type of shales can be identified by the results of Ro,max and Rock-Eval, respectively26-31. The TOC content of the shale samples varies from 0.36% to 31.58% (avg. 5.46%). We found 57% of the samples have TOC contents higher than 2%, with a few samples even higher than 10% (Table 2). The TOC content displays a positive correlation with pyrolysis hydrocarbon (S2), which ranges from 3.07 to 79.12 mg/g (avg. 22.82 mg/g) (Fig. 3-a). The hydrocarbon generative potential (G.P. = S1 + S2) of all the samples ranges from 3.25 to 82.82 mg/g rock, and the hydrogen index (HI) values range from 100.31 to 768.06 mg HC/g. These results are indicative of a good source rock with moderate hydrogen generation potential32,33. The Rock-Eval Tmax of the studied samples ranges from 408°C to 453°C, averaging 432°C (Table 3). The relationship between Tmax versus HI, reveals that the kerogen types of shales in the Junger area are predominantly type II kerogen. Most rock samples are predominantly in the oil to wet gas maturity range, which is consistent with the Ro,max values (0.45–0.72%, avg. 0.58%) (Fig. 3-b).


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4.2 The hydrocarbon generation of source rocks 4.2.1 Petrography of FIs The FIs, which help record the diagenesis and mineralization history of a formation, are usually captured in quartz grains, quartz secondary overgrowth, calcite cement or microfractures during the oil and gas charging process. As such, the thermodynamic characteristics of FIs are direct and effective parameters for analyzing the charging history of gas accumulation34-37. Liquid hydrocarbon inclusions, gas-liquid hydrocarbon inclusions and gas hydrocarbon inclusions have been found in the microfractures in quartz grains, microfractures through quartz grains, sandstone particle porosity, dissolution holes of calcite cement, and microfractures in calcite veins. The hydrogen inclusions are shown with yellow-green fluorescence or blue fluorescence (Fig. 4). 4.2.2 Thermodynamic characteristics of FIs In order to avoid the effect of deformation of FIs from later tectonic evolution, the FIs selected for homogenization temperature measurements were small (ranging from 1 × 1 µm to 39 × 6 µm) and low in gas to liquid ratio (≤5%) (Table 4). As shown in Fig. 5 and Table 4, the homogenization temperatures of aqueous inclusions of research area ranged from 60–140°C, which can generally be divided into three intervals (60–80°C, 80–110°C and 110–140°C) and are mainly distributed between 110 and 140°C. Based on the relationship between homogenization temperature and salinity, FIs can be divided into two different inclusion styles: low-temperature and low-salinity fluid style and high-temperature and composite-salinity fluid style (Fig. 6), which form over three stages during the charging history of unconventional gas. 4.2.3 The charging history of unconventional gas

The geothermal evolution history of coal-bearing strata in the Junger area was simulated based


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on the analysis of the burial and erosion history using BasinMod Geology Software (Fig. 7, based on the data presented in Table 5). Combining petrographic analysis, thermodynamic characteristics of FIs, the charging history of the unconventional gas can be divided into three stages. These include two primary hydrocarbon charging stages and one later adjustment stage. At the first stage of hydrocarbon charging, FIs are mainly composed of liquid hydrocarbon inclusions with light yellow color and yellow-green fluorescence. They are located along microfractures in quartz grains, corresponding to a temperature peak at 80–110°C, and we speculate that the timing is from 220–160 Ma, corresponding to the Late Triassic–Middle Jurassic with a relatively small amount of hydrocarbon generation (Figs. 4, 5

and 7). During the second stage, which was the main period of hydrocarbon generation, FIs occur mainly as gas-liquid hydrocarbon inclusions with grey black color and blue fluorescence, banded along microfractures through quartz grains and clustered in sandstone particle porosity. The stage corresponds to a temperature peak at 110–150°C, and we speculate that the timing is from 160–105 Ma, corresponding to the Middle Jurassic–Late Cretaceous (Figs. 4, 5 and 7). High-temperature and low-salinity fluid inclusions occurred during this gas charging stage, and may have been affected by coal dewatering, which occurs at the Ro from 0.5% to 0.7%. The last stage is inferred to have occurred during basin adjustment. The FIs are mainly composed of gas hydrocarbon inclusions with grey black color and no fluorescence. They occur in bands along microfractures through quartz grains, microfractures in calcite veins and clustered in dissolution holes of calcite cement. This stage occurred at a temperature peak of 60–80°C, and formed by the rapid uplift and intense transformation of the basin after the Late Cretaceous (Figs. 4, 5 and 7). The


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low-temperature and low-salinity fluid captured during the adjustment charge may have been affected 38

by low-salinity groundwater . A dilute oil pitch contaminated calcite cement in sandstone particle

porosity with brown color was observed, which represents the degradation and transformation of the reservoir (Fig. 8)39-41. The source rocks were mainly buried before the Late Cretaceous, and the charging history of unconventional gas was a continuous process from the Middle Jurassic to Late Cretaceous in the Junger area. 4.3 Porosity and pore structures The pressured-mercury testing data of the coal, shale and sandstones are presented in Table 6. Different rocks show different porosities and pore structures. The coal samples show the highest porosity (10.4–18%, avg.14.3%) and permeability (2.17–2.93 mD, avg. 2.6 mD), followed by sandstones with porosity ranging from 10.1% to 13.0% (avg. 11.55%) and permeability varying between 0.51 and 1.16 mD (avg. 0.84 mD). The shale samples have the lowest porosity (1.1–4.7%, avg. 2.48%) and permeability (0.003–0.37 mD, avg. 0.1 mD); the highest value within the shale samples occurred in a carbonaceous shale, which may be caused by the higher carbonaceous material content that is easily moved during mercury intrusion. As shown in Fig. 9, the capillary pressure curves of samples are mostly located at the upper right of the mercury saturation (SHg)–capillary pressure (Pc) semi-logarithmic Cartesian coordinate system. There is no obvious mercury curve platform in the coal and shale samples. In contrast, the mercury curve platform is well developed in sandstone samples, indicating that the pore throats are small and poorly-sorted in coal and shales, while coarse and better-sorted pore throats are developed in sandstone45. The Pore diameter (Dp), displacement pressure (Pd) and pore structure coefficient (φ) were adopted to discuss the pore structure and


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connectivity. The Pd is defined as the pressure necessary to form a continuous hydrocarbon filament in the pore space of the seal and is commonly inferred from the injection pressure at 10% saturation. The φ refers to the degree of pore roundness; the higher the value, the more complicated the pore structure. This can be expressed by the following equation: ଶ

R ݉൘ , ߮= 8݇ where φ is the connectivity and curvature degree of pore throat; m is the porosity, %;

R is the weighted

average of the pore throat radius, µm; and k is the permeability, mD. In coal samples, the Dp ranges from 0.11 to 0.34 µm (avg. 0.16 µm); the Pd from 1.17 to 10.59 MPa (avg. 4.93 MPa) and the φ from 0.01 to 0.24 (avg. 0.09). In shale samples, the Dp ranges from 0.04 to 0.09 µm (avg. 0.06 µm); the Pd from 11.06 to 15.62 MPa (avg. 14.32 MPa) and the φ from 0.01 to 0.47 (avg. 0.18). In sandstone samples, the Dp ranges from 0.6 µm to 0.95 µm (avg. 0.8µm); the Pd from 0.45 to 0.48 MPa (avg. 0.47 MPa), and the φ from 2.65 to 3.15 (avg. 2.9). Collectively, the data indicate that sandstones have the Dp, but with lower porosity and permeability than those of coal samples. The types of pore in sandstone are mainly primary pores and inter-particle pores, while organic pores are well developed in coal samples. Generally, primary pores and inter-particle pores have larger pore throat than organic pores. However, microcracks developed in the coal samples and represent the major causes of the higher porosity and higher permeability in the coal samples than the other samples. The shales have the lowest porosity, permeability and pore diameter, which may be the result of the higher clay content and smaller pores (such as organic pores).

4.4 Unconventional natural gas target area Stratal cycles are an important feature of the coal-bearing interval, which is reflected in the fact that


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the lithology and strata repeat regularly with symbiotic relationships. This can be seen from the well histogram of the OM well in the study area (Fig. 2). The lithological cycles can form several sets of conventional “source rock–reservoir-cap” combinations, which are favorable for the preservation and enrichment of hydrocarbon gases. There are no unified rules with which to predict reservoir quality of coal, shale and sandstone in space and time. Coal-bearing strata are widely developed in the study area, with an average thickness of 150 m, of which 11 coal seams occur with an average total thickness of 30.5 m, and the coal reservoir has the highest porosity and permeability. The average thickness of the shales is 67.5 m and a single shale unit can be up to 15 m thick at the lowest porosity and permeability. The extensive development and relatively thick source rocks (coal and shale) and the lithological cycles represent a good foundation for development and enrichment of unconventional gases. The sandstone is interlayered with coal beds and shales; this feature meets the commonly seen accumulation model of tight sand gas development, referred to as the “Short-distance transport, nearest-reservoir enrichment” model. Units of coal, shale and sandstones occur in each part of the coal-bearing strata, at many spatial scales (Fig. 10). The geochemical characterization of the source rocks indicates that the coal and shales are all at relatively low maturity; the coal are dominated with vitrinite and inertinite and the shale is type II kerogen with high TOC and hydrocarbon generative potential, indicating that the source rocks have all entered into the wet gas generation stage. Combined with the charging history of unconventional gas and the thicknesses and areas of reservoir, the study area could be favorable for gas generation. However, burial depth restricts the economic accumulation of natural gas. According to the burial depth of the No. 6 coal seam (Fig. 11), the coal depth ranges from essentially zero to over 1200 m from east to west. Although the No. 6 coal seam gas content is relatively low (around 2 m3/t)16, it still has vast unconventional natural gas


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resources potential due to its large thickness, multiple sets and large areal extent of source rocks within the Junger area. Thus, the presence of simple structures and the small dip of the coal-bearing strata would be favorable for unconventional natural gas preservation, with the more deeply-buried western areas having the best potential for unconventional gas enrichment (Fig. 11).

5 Conclusions Coal and shales in the Taiyuan and Shanxi Formations in the Junger area have good potential for hydrocarbon accumulation. Coal-bearing strata are widely developed with an average thickness of 150 m. The extensive and thick source rocks and lithological cycles of coal-bearing strata set a good foundation for the development of unconventional gases. (1) The coal rank is of low mature-mature stage (Ro,max = 0.44–0.81%), with vitrinite and inertinite comprising more than 90% of the total maceral compositions. The shale is type II organic matter kerogen characterized by high TOC content

(0.36–31.58%) and high hydrocarbon generative potential (3.25–82.82 mg/g rock), and is predominantly in the oil to wet gas maturity range, which is consistent with the Ro,max values (0.45–0.72%, avg. 0.58%). (2)

Three types of FIs were observed: liquid hydrocarbon, gas–liquid hydrocarbon and gas hydrocarbon inclusions. Combined with the fluorescence of FIs and the homogenization temperatures, the charging history of unconventional gas can be divided into three stages, including two primary hydrocarbon charging from the Middle Jurassic to Late Cretaceous and one later adjustment stage since the Late Cretaceous. (3) The porosity of the coal samples varies from 10.4% to 18.0%, and the pore diameter ranges between 0.11 and 0.34 µm. The shales are of porosity between 1.1% and 4.7%, with much lower pore diameter of 0.04–0.09 µm. The sandstones have an average porosity of 11.55% and pore diameter 0.80 µm. The coal samples have higher porosity and higher permeability than sandstones; however, they have a


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lower pore diameter for the development of microcracks. (4) Combined with the geochemical characterization, hydrocarbon generation of the source rocks and the development characteristics of the reservoir, the presence of simple structures and small dip of the coal-bearing strata would be favorable

for unconventional natural gas preservation, with the more deeply-buried western areas having the best potential for unconventional gas enrichment Acknowledgements This research was financially supported by National Mineral Resources Technical Standard System Project (Grant No. CB2015-6-2), National Natural Science Foundation of China (41572141) and the Geological Survey Project of China geological survey (12120114012201). We wish to thank Prof. Wei Yingchun and Doc. Guo Aijun for their constructive comments and suggestions on the manuscript. References (1)

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(14) Dai J. X.; Li J.; Deng W. W.; Hu G. Y.; Luo X.; Tao S. Z.; Zhang W. Z.; Zhu G. Y.; Mi J. K. Petroleum Exploration and Development. 2015, 32:16-22. (15) Dai S. F.; Ren D. Y.; Chou C. L.; Li S. S.; Jiang Y. F. International Journal of Coal Geology. 2006, 66:253-270. (16) Qiu Y. K.; Liu D. M, Elsworth D.; Yao Y. B.; Cai Y. D.; Li J. Q. International Journal of Oil, Gas and Coal Technology. 2014, 8: 449-467. (17) Pratt T.J.; Mavor M.J.; Debruyn R.P. International Coalbed Methane Symposium. 1999:23-24. (18) Crowley S.S.; Ruppert L.F.; Belkin H.E.; Stanton R.W.; Moore T.A. Organic Geochemistry. 1993, 20:843-853. (19) Michael F.; Anna M.; Steven P. International Journal of Coal Geology. 2008, 76:86-97. (20) Walter B.; Ayers J. AAPG, 86:1855-1890. (21) Yue J.H.; Xiao Q.G. China Offshore Oil and Gas. 2016,28:99-102. (22) Flores R.M. International Journal of Coal Geology. 1998, 35:3-26. (23) Creedy D.P. International Journal of Coal Geology. 1988, 10:1–31. (24) Yao, Y. B.; Liu, D. M.; Tang, D. Z.; Tang, S. H.; Che Y.; Huang W. H. International Journal of Coal Geology. 2009, 78, 1-15. (25) Clayton J L. International Journal of Coal Geology.1998, 35:159-173. (26) Jarvie, D. M.; Hill, R. J.; Pollastro, R. M. Unconventional Energy Resources in the Southern Mid-continent Symposium, March 9-10, 2005, Oklahoma City, Oklahoma, pp. 37-50. (27) Curtis J. B. AAPG Bulletin. 2002, 86:1921-1938. (28) Jarvie D. M.; Hill R. J.; Ruble T. E.; Pollastro R. M. AAPG Bull. 2007, 91, 475-499. (29) Bowker K A. AAPU Bulletin. 2007, 91:523-533. (30) Rowe H. D.; Loucks R. G,; Ruppel S. C.; Rimmer S. M. Chemical Geology. 2008, 257:16-25. (31) Quigley T. M.; Mackenzie A. S. Nature. 1988, 333:549-552 (32) Peters K. E.; Cassa M. R. AAPG Memoir. 60, Tulsa, OK, 1994, pp. 93-117. (33) Tissot B. P.; Welte D. H. Berlin, Springer Verlag. 1984, 699. (34) Middleton D.; Parnell J.; Carey P.; Xu G. Journal of Geochemical Exploration. 2000, 69-70:673-677. (35) Kelly J, Parnell J, Chen H H. Journal of Geochemical Exploration. 2000,69:705-709. (36) Murray R C. AAPG Bulletin. 1957,41:950-952. (37) Tilley B. J.; Nesbitt B. E.;Longstaffe F. J. AAPG Bulletin. 1989,73:1206-1222.


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(38) Li Y.; Tang D. Z.; Xu H.; Elsworth D.; Meng Y. J. AAPG Bulletin. 2015,99:207-229. (39) Zheng M. L.; Jin Z. J.; Wang Y.; Liu C. Y,; Xu G. Z. Journal of Earth Sciences and Environment. 2006, 28: 31-36(in Chinese with English abstract). (40) Chen G.; Ding C.; Xu L. M.; Zhang H. R.; Li N.; Li Y.; Hu Y. X.; Huang D. S. Acta Petrolei Sinica. 2012, 33: 1003-1011(in Chinese with English abstract). (41) Hu G. Y.; Li J.; Shan X. Q.; Han Z. X. International Journal of Coal Geology. 2010, 381-391. (42) Ding C. Xi An: Northwest University, 2013(in Chinese with English abstract). (43) Chen R.Y.; Luo X. R.; Chen Z.K.; Wang Z. M.; Zhou B. Acta Geologica Sinica. 2006, 80: 685-693(in Chinese with English abstract). (44) Ren Z. L. Acta Petrolei Sinica. 1996, 17: 17-24(in Chinese with English abstract). (45) Zeng W. T.; Zhang J. C.; Ding W. L.; Wang X. Z.; Jiu K.; Fu J. L.; Journal of China Coal Society. 2014, 39:1118-1126(in Chinese with English abstract).


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1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Figure captions

Figure 1. The location and geologic structures in the Junger area, northeast Ordos Basin, China

Figure 2. Lithological combinations and depositional cycles of OM well in the Junger area

Figure 3. The relationship of Rock-Eval data (a, TOC (%) versus S2. b, Tmax versus HI diagram)

Figure 4. Typical fluid inclusions and its occurrence in the microfractures in/through quartz grains (a, b, c, d, g), sandstone particle pores (e), dissolution holes of calcite cement (f), and microfractures in calcite veins (h), including liquid, gas–liquid and gas hydrocarbon inclusions, with yellow-green and blue fluorescence

Figure 5. Histogram of homogenization temperatures of the tested fluid inclusions in the Junger area

Figure 6. Classification of fluid inclusions by homogenization temperature and salinity

Figure 7. Hydrocarbon-generation and thermal history of source rocks in coal-bearing strata in OM well wells in the Junger area (The burial evolution and ancient geothermal gradient data are taken from Refs. 42–44)

Figure 8. Dilute oil pitch contaminated calcite cement in sandstone particle porosity, brown, optical microscopy

Figure 9. The mercury intrusion results of coal, shale and sandstones in the Junger area

Figure10. The loggings correlation through the research area from west to east showing the coal-bearing strata are stably distributed and the burial depth is shallow from west to east

Figure11. Map of Junger area showing No. 6 coal burial depth, gas content and unconventional gas target area (the No. 6 burial depth and coal content data were extracted from Ref. 13)


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1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

Tables Table 1. Coal maceral composition and maximum vitrinite reflectance in the No.6 coal seam in the Junger area Samples

V (%)

I (%)

E (%)

MM (%)

Ro,max (%)

(V/I)

DFP-1

12.1

70.3

17.2

0.4

0.6

0.17

DFP-2

61.5

32.3

5.6

0.6

0.57

1.90

DFP-3

9.3

82.5

8.1

0.1

0.81

0.11

HDG-1

41.9

53.9

3.2

1.0

0.56

0.78

HDG-2

15.6

72

12

0.4

0.58

0.22

HDG-3

37.3

53.2

8.8

0.7

0.44

0.70

HDG-4

35.3

54.9

9.3

0.5

0.52

0.64

HEWS-1

14.2

65.6

19.8

0.4

0.73

0.22

HEWS-2

46.4

45.3

8.2

0.1

0.51

1.02

HEWS-3

30.1

59.9

9.6

0.4

0.55

0.5

HEWS-4

26.6

56.9

16.3

0.2

0.57

0.47

CEGZ6

84.1

14

1.7

0.2

0.41

6.01

JZT6

78.0

18.5

3.5

0

0.42

4.22

HYC-1

59.5

30.1

10.2

0.2

0.56

1.98

HYC-2

61.2

32.1

6.7

0

0.58

1.91

HYC-3

49.2

38.4

12.4

0

0.55

1.28

Abbreviations: V = vitrinite content; I = inertinite content; E = liptinite content; MM = mineral matter content; Ro,max = maximum vitrinite reflectance.


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Table 2. TOC content and Ro,max of shale in the Junger area Samples

Depth (m)

TOC (%)

M1

196.13

0.4

M5

209.22

0.39

M6

210.72

1.64

M9

223.57

1.75

M10

226.04

0.46

M11

227.84

3.48

M12

233.73

7.27

M13

236.13

1.56

M16

240.37

2.82

M17

241.67

0.82

M22

262.36

18.62

M23

273.7

3.36

M24

278.54

31.58

M25

287.14

1.06

M29

302.01

6.11

M30

306.12

3.96

M31

316.26

14.91

M35

325.66

21.37

M37

331.24

9.61

M39

334.88

3.66

M40

336.09

4.04

M41

337

3.23

M42

340.33

2.97

M44

342.33

1.44

M45

348.63

3.05

M46

350.43

1.75

M47

351.43

1.28

M49

355

0.36

Ro,max (%)

0.45

0.68

0.54

0.47

0.56

0.72

0.61


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Energy & Fuels

Table 3. Rock-Eval data for shale in the Junger area Samples

Lithology

TOC (%)

S1

S2

S3

S4

S1 + S2

HI

OI

HCI

(mg/g)

(mg/g)

(mg/g)

(mg/g)

(mg/g)

(mg HC/g TOC)

(mg CO2/g TOC)

(mg HC/g TOC)

Tmax (°C)

M11

shale

3.48

432

0.26

9.29

0.90

55.52

9.55

266.95

25.86

7.47

M12

shale

7.27

432

0.43

21.63

0.84

141.45

22.06

297.52

11.55

5.91

M16

shale

2.82

453

0.09

3.16

0.47

50.17

3.25

112.06

16.67

3.19

M22

carbonaceous shale

18.62

423

2.52

68.45

1.59

242.01

70.97

367.62

8.54

13.53

M23

shale

3.36

432

0.82

5.32

1.22

63.04

6.14

158.33

36.31

24.40

M24

carbonaceous shale

31.58

408

3.70

79.12

1.79

307.35

82.82

250.54

5.67

11.72

M29

carbonaceous shale

6.11

436

1.60

24.88

0.80

93.12

26.48

407.20

13.09

26.19

M30

carbonaceous shale

3.96

446

0.63

9.47

0.82

67.45

10.10

239.14

20.71

15.91

M31

carbonaceous shale

14.91

435

0.77

39.18

0.96

235.61

39.95

262.78

6.44

5.16

M35

carbonaceous shale

21.37

421

1.05

54.06

1.35

131.85

55.11

252.97

6.32

4.91

M37

carbonaceous shale

9.61

424

1.13

25.95

1.27

172.00

27.08

270.03

13.22

11.76

M39

shale

3.66

434

0.45

6.76

0.84

67.29

7.21

184.70

22.95

12.30

M40

shale

4.04

437

0.20

5.53

0.88

71.90

5.73

768.06

122.22

27.78

M41

shale

3.23

435

0.11

3.24

0.86

56.19

3.35

100.31

26.63

3.41

M42

shale

2.97

443

0.15

5.93

0.81

51.76

6.08

199.66

27.27

5.05

M45

shale

3.05

423

0.26

3.07

0.85

51.87

3.33

100.66

27.87

8.52

Abbreviations: S1 = soluble hydrocarbon; S2 = pyrolysis hydrocarbon; S3 = organic carbon dioxide; S4 = residual organic carbon.


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Page 20 of 34

Table 4. Fluid inclusion test data of sandstones and shale with calcite veins in coal-bearing strata in the Junger area Samples M3

M19

M27

M34

Lithology Sandstone

Sandstone

Sandstone

Sandstone

Numbers 6

6

6

7

Host mineral occurrences

Distribution type

Size (µm)

Homogenization

Salinity

temperature (°C)

(wt% NaCl)

Vapor liquid ratio (%)

Microfractures through quartz grains

Ribbon

7×3

≤5

124

2.74


Ribbon

6×2

≤5

119

2.90


Ribbon

2×3

≤5

126

1.74


Ribbon

3×3

≤5

128

1.91


Ribbon

3×2

≤5

135

1.74


Ribbon

5×5

≤5

134

3.06

Microfractures in quartz grains

Ribbon

7×3

≤5

100

22.38


Ribbon

6 × 13

≤5

73

6.16


Ribbon

16 × 14

≤5

75

6.01


Ribbon

3×7

≤5

79

6.01


Ribbon

1×4

≤5

113

0.88


Ribbon

1×3

≤5

80

0.71


Ribbon

2×3

≤5

132

10.36


Ribbon

2×1

≤5

98

10.24


Ribbon

1×1

≤5

95

10.36


Ribbon

2×2

≤5

115

13.01


Ribbon

1×1

≤5

99

12.96


Ribbon

2×3

≤5

108

2.07


Ribbon

5×1

≤5

75

2.24


Ribbon

12 × 3

≤5

98

6.01


Ribbon

6×3

≤5

89

3.39


Ribbon

6×3

≤5

94

3.23

microfractures in calcite veins

Ribbon

10 × 8

≤5

86


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Energy & Fuels

M48

Calcite vein

9


Ribbon

25 × 5

≤5

69

1.57


Ribbon

39 × 6

≤5

65

1.57


Ribbon

6×3

≤5

124

3.23


Ribbon

6×5

≤5

120

3.23


Ribbon

5×3

≤5

119

3.06


Ribbon

17 × 10

≤5

111

15.2


Ribbon

17 × 10

≤5

119

14.53


Ribbon

12 × 17

≤5

121

14.98


Ribbon

18 × 9

≤5

125

15.09


Ribbon

4×2

≤5

132

15.09


Ribbon

6×3

≤5

123

14.98


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Table 5. Stratigraphic information for simulation of geothermal evolution history (Refs. 42–44) Present Formation

Type

Age (my)

Well top (m)

Missing thick (m) thickness (m)

Q+N

F

1.8

0

17.71

E_E2+3

E

65.5

−448

E_K2-E1

E

85

−1100

E_K1+2

E

130

−1800

D_K1

D

145.5

800

E_J2+3

E

150

−200

D_J2

D

160

450

E_J1+2

E

170

−120

D_J1+2

D

189.6

298

E_T3-J2

E

200

−200

D_T2+3

D

240

820

D_T1

D

251

700

D_P2-3

D

272

800

P2

F

284.4

17.71

203.94

P1s

F

299

221.65

77.85

C 2t

F

306.5

299.50

78.58

Abbreviations: F=Normal formation; D=Deposit; E= Erosion.


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Energy & Fuels

Table 6. Physical property parameters of coal, shale, sandstone in the Junger area Porosity Samples

Permeability

Pore diameter

Lithology

Displacement pressure

Mercury withdrawal

Pore structure

(Mpa)

efficiency (%)

coefficient

Sorting coefficient (%)

(mD)

(µm)

M10

coal

18

2.7

0.34

0.79

1.17

32.29

0.24

M21

sandstone

13

1.16

0.95

2.7

0.45

51.08

3.15

M30

carbonaceous shale

1.1

0.006

0.04

0.12

11.06

35.12

0.1

M28

sandstone

10.1

0.51

0.65

2.02

0.48

44.65

2.65

M31

carbonaceous shale

4.7

0.37

0.09

0.21

15.62

53.87

0.01

M32

coal

10.4

2.17

0.14

0.13

10.59

53.8

0.01

M39

shale

1.1

0.003

0.06

0.18

14.96

34.22

0.14

M42

shale

3

0.003

0.04

0.23

15.62

76.83

0.47

M43

coal

14.4

2.93

0.11

0.12

3.03

52.77

0.02


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Figures

Fig.1


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Fig.2


Energy & Fuels

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a

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b

Fig.3


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Fig.4


Energy & Fuels

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Fig.5


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Fig.6


Energy & Fuels

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Fig.7


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Fig.8


Energy & Fuels

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Fig.9


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Fig.10


Energy & Fuels

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Fig.11


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Geochemical and Preliminary Reservoir Characteristics of the

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