Coupling accumulation model with gas-bearing features to evaluate low-rank coalbed methane resource potential in the southern Junggar Basin, China

Ou, Chenghua; Li, Chaochun; Zhi, Dongming; Xue, Lie; Yang, Shenglai

doi:10.1306/03231715171

Cited by 18 publications

(8 citation statements)

References 42 publications

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“…The gas reservoir determines the potential resource (generally below 30% of the maximum), and the seal formation limits the real shalegas reserves (generally below 50% of the potential). These static subsystems function through various interactions and couplings exerted by the four dynamic subsystems (Ou Chenghua et al, 2016cd;2018b). The hydrocarbon source rock, gas reservoir, and seal formation are sedimentary sequences controlled by various sedimentation processes in specific palaeo-geographic environments throughout various lithological periods.…”

Section: Configuration Of Shale Gas Enrichmentmentioning

confidence: 99%

Modes of Shale‐Gas Enrichment Controlled by Tectonic Evolution

2018

Acta Geologica Sinica (Eng)

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The typical characteristics of shale gas and the enrichment differences show that some shale gases are insufficiently explained by the existing continuous enrichment mode. These shale gases include the Wufeng–Longmaxi shale gas in the Jiaoshiba and Youyang Blocks, the Lewis shale gas in the San Juan Basin. Further analysis reveals three static subsystems (hydrocarbon source rock, gas reservoirs and seal formations) and four dynamic subsystems (tectonic evolution, sedimentary sequence, diagenetic evolution and hydrocarbon‐generation history) in shale‐ gas enrichment systems. Tectonic evolution drives the dynamic operation of the whole shale‐gas enrichment system. The shale‐gas enrichment modes controlled by tectonic evolution are classifiable into three groups and six subgroups. Group I modes are characterized by tectonically controlled hydrocarbon source rock, and include continuous in‐situ biogenic shale gas (I1) and continuous in‐situ thermogenic shale gas (I2). Group II modes are characterized by tectonically controlled gas reservoirs, and include anticline‐controlled reservoir enrichment (II1) and fracture‐controlled reservoir enrichment (II2). Group III modes possess tectonically controlled seal formations, and include faulted leakage enrichment (III1) and eroded residual enrichment (III2). In terms of quantity and exploitation potential, I1 and I2 are the best shale‐gas enrichment modes, followed by II1 and II2. The least effective modes are III1 and III2. The categorization provides a different perspective for deep shale‐gas exploration.

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Section: Configuration Of Shale Gas Enrichmentmentioning

confidence: 99%

Modes of Shale‐Gas Enrichment Controlled by Tectonic Evolution

2018

Acta Geologica Sinica (Eng)

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“…Recovery of coalbed methane (CBM) from coal seams can not only benefit mining safety, reduce greenhouse gas emissions, and also increase clean energy supply (Karacan et al, 2011;Moore, 2012). In the Junggar Basin, the CBM resources have been estimated at 3.83 trillion cubic meters, which is the third largest CBM basin in China after the Qinshui Basin and Ordos Basin (Fu et al, 2016;Ou et al, 2018;Yu and Wang, 2020). Exploration of CBM in the Junggar Basin has made significant progress in recent years, among which the Fukang area of the southern Junggar Basin is one of the most successful and typical representatives.…”

Section: Introductionmentioning

confidence: 99%

“…Exploration of CBM in the Junggar Basin has made significant progress in recent years, among which the Fukang area of the southern Junggar Basin is one of the most successful and typical representatives. The previous investigation demonstrated that coal seam gas-in-place (GIP) resources in the Fukang area are about 682 × 10 8 m 3 , which account for more than twenty percent of the known CBM resources in the southern Junggar Basin (Yang et al, 2005;Ou et al, 2018). The highest daily gas production of vertical wells in China, 27,896 m 3 , was archived and gas production has reached 100 million cubic meters annually in this area (Cao et al, 2012;Zhang B et al, 2021).…”

Section: Introductionmentioning

confidence: 99%

Coalbed methane accumulation, in-situ stress, and permeability of coal reservoirs in a complex structural region (Fukang area) of the southern Junggar Basin, China

Li²,

Pan³

et al. 2023

Front. Earth Sci.

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The enrichment of coalbed methane (CBM), in-situ stress field, and permeability are three key factors that are decisive to effective CBM exploration. The southern Junggar Basin is the third large CBM basin in China but is also known for the occurrence of complex geological structures. In this study, we take the Fukang area of the southern Junggar Basin as an example, coalbed methane accumulation and permeability, and their geological controls were analyzed based on the determination of geological structures, in-situ stress, gas content, permeability, hydrology and coal properties. The results indicate that gas contents of the Fukang coal reservoirs are controlled by structural framework and burial depth, and high-to-ultra-high thickness of coals has a slightly positive effect on gas contents. Perennial water flow (e.g., the Baiyanghe River) favors gas accumulation by forming a hydraulic stagnant zone in deep reservoirs, but can also draw down gas contents by persistent transportation of dissolved gases to ground surfaces. Widely developed burnt rocks and sufficient groundwater recharge make microbial gases an important gas source in addition to thermogenic gases. The in-situ stress field of the Fukang area (700–1,500 m) is dominated by a normal stress regime, characterized by vertical stress > maximum horizontal stress > minor horizontal stress. Stress ratios, including lateral stress coefficient, natural stress ratios, and horizontal principal stress ratio are all included in the stress envelopes of China. Permeability in the Fukang area is prominently partitioned into two distinct groups, one group of low permeability (0.001–0.350 mD) and the other group of high permeability (0.988–16.640 mD). The low group of permeability is significantly formulated by depth-dependent stress variations, and the high group of permeability is controlled by the relatively high structural curvatures in the core parts of synclines and the distance to the syncline core. Meanwhile, coal deformation and varying dip angles intensify the heterogeneity and anisotropy of permeability in the Fukang area. These findings will promote the CBM recovery process in China and improve our understanding of the interaction between geological conditions and reservoir parameters and in complex structural regions.

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“…Current gas content (CGC) of coal seams is one of the most important parameters for evaluating coalbed methane (CBM) reservoirs. − The CGC is a product of the generation, migration, and preservation of CBM, and it is mainly controlled by various geological processes such as the sedimentary environment, geological structure, and hydrogeological conditions. − In the coalification process, the gas content of coal generated can reach a peak of ∼400 m 3 /t, which is an order of magnitude higher than the average CGC (commonly <30 m 3 /t in most CBM basins). ,− Most CBM can escape during the complex evolution processes of CBM reservoir formation, gas accumulation, and loss before reaching a final equilibrium state.…”

Section: Introductionmentioning

confidence: 99%

Fault Development Characteristics and Their Effects on Current Gas Content and Productivity of No. 3 Coal Seam in the Zhengzhuang Field, Southern Qinshui Basin, North China

Wang

Yao

Huang³

et al. 2021

Energy Fuels

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Faulting is one of the most common geological features that impacts current gas content (CGC) of coal seams, which is an important parameter for coalbed methane (CBM/gas) production. However, the detailed faulting effects on CGC and productivity have not been thoroughly investigated, because of inadequate methods for quantitative evaluation of the effects. In this study, we carry out comprehensive analysis of diverse geological coring data and experimental results and production data of exploration wells as well as the three-dimensional fault interpretation in the Zhengzhuang field. We introduce a parameter fault scale (F) to quantify the scale of faults, which is described by fault length, fault throw, and the investigated area. Then we propose a horizontal grid method to determine the faulting influence on CGC. The relationships between the CGC and the fracture density of coal core, the mechanical properties of the roof and floor of coal seam, the average gas production in a faulting system (including the upthrown side, downthrown side, and fault plain) are analyzed. In the study area, the well-developed normal faults have significant influence on CGC, but the locally developed thrust faults have negligible influence. The square grid with length of 1.5 km is probably the most effective grids for analyzing faulting effected distance on CGC. Thus, the normal faults can be divided into small- (F 1.5 < 0.05), moderate- (0.05 < F 1.5 < 0.15), and large-scale (F 1.5 > 0.15). The evident effect of faulting on CGC can be observed up to ∼1.5 km away from the normal fault. When the coal seam is further away from the normal faults (i.e., >1.5 km), the CGC is higher or closer to 20.7 m3/t. In contrast, when the coal seam is <1.5 km from the normal faults, the CGC decreases with increasing value of F. In general, the CGC is higher on the downthrown side, with better gas preservation conditions than the upthrown side. Relatively high CGC (>20 m3/t) is necessary for good gas production of CBM wells. The CBM wells with low ADGP (<500 m3/d) and low CTGP (<105 m3) are commonly located on the fault plane and upthrown side of normal faults. In general, the places far away (>1.5 km) from the normal faults is the most favorable productivity area, and only the small-scale normal faults developed is the secondary favorable productivity area. These places have the average gas production as high as 1000 m3/d and cumulative total gas production as high as 4 × 105 m3.

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Coupling accumulation model with gas-bearing features to evaluate low-rank coalbed methane resource potential in the southern Junggar Basin, China

Cited by 18 publications

References 42 publications

Modes of Shale‐Gas Enrichment Controlled by Tectonic Evolution

Modes of Shale‐Gas Enrichment Controlled by Tectonic Evolution

Coalbed methane accumulation, in-situ stress, and permeability of coal reservoirs in a complex structural region (Fukang area) of the southern Junggar Basin, China

Fault Development Characteristics and Their Effects on Current Gas Content and Productivity of No. 3 Coal Seam in the Zhengzhuang Field, Southern Qinshui Basin, North China

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