Formation and development of pore structure in marine-continental transitional shale from northern China across a maturation gradient: insights from gas adsorption and mercury intrusion

Xi, Zhaodong; Tang, Shuheng; Wang, Jing; Yang, Guoqiao; Li, Lei

doi:10.1016/j.coal.2018.10.005

Cited by 64 publications

(37 citation statements)

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“…Previous authors have shown that pore development and porosity of shale gas reservoirs are controlled by the TOC content [9,50]. In the present study, the TOC content reveals a weak positive correlation with the pore structure parameters (specific surface areas and pore volumes) in the rock samples with TOC < 10% ( Fig.…”

Section: Constraint Of Tocsupporting

confidence: 44%

“…The understanding of the petrophysical properties such as the porosity, permeability, mineralogy, specific surface area and pore volume of shales, especially the nanopore arrangement is significant in characterising the shale pore structure [1][2][3][4][5] and in providing a practical implication when evaluating the adsorption, desorption, diffusion and gas flow in shales [1,6]. Shales are complex in nature with heterogeneous porous media [2]; thus, the complex pore network of shale is constrained by several geologic features such as the sedimentary processes, tectonic [7,8], mineralogy, total organic carbon (TOC) content, thermal maturity [9] and organic matter type [3,10].…”

Section: Introductionmentioning

confidence: 99%

“…While taking into account of the different pore types, 3 divisions have been made, namely interparticle (interP) pores, intraparticle (intraP) pores and organic matter pores [4]. Shale gas could be derived from biogenic and/or thermogenic process [13,14] and in situ accumulated as adsorbed dry gas in the fine micropores and mesopores of the organic matter and clays and also as free gas in the crevices and macropores [9,13,14].…”

Section: Introductionmentioning

confidence: 99%

See 2 more Smart Citations

Mineralogical and pore structure of organic-rich deltaic shales and sub-bituminous coals from early Maastrichtian Mamu Formation, Anambra Basin, Nigeria

Faboya

Sonibare

et al. 2020

SN Appl. Sci.

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The Mamu Formation source rocks in the Anambra Basin are targets for shale gas reservoir. However, fundamental data on the critical pore structures for assessing the shale reservoir capabilities are lacking. In this study, the source rocks were investigated for their mineralogical compositions and pore structure characteristics by X-ray diffraction, accelerated surface area and porosimetry and field emission scanning electron microscopy (FE-SEM). The bulk mineralogy of the samples is dominated by kaolinite and quartz with average percentage composition of 52.0 and 41.5, respectively, suggesting that the rocks are potential candidates for fracking. The total average pore volume and specific surface area in the samples are 0.0421 cm 3 /g and 22.43 m 2 /g, respectively. The shale samples show higher amounts of total pore volumes relative to the sub-bituminous coals. No obvious organic pore is observed in the shale samples, but some inherited primary organic matter pores of plant origin exist in the sub-bituminous coals. Therefore, inorganic minerals pores are the major contributors to the pore development in the immature shales. The FE-SEM results reveal that the pore network in the shales is dominated by intraparticle pores and fractures. The observed well-developed fractures within the Mamu shales that may have resulted from tectonic events are capable of positively influencing the petrophysical properties of shales in the basin and by extension assist in shale gas exploration and development in the entire Lower Benue Trough.

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Section: Constraint Of Tocsupporting

confidence: 44%

Section: Introductionmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

See 1 more Smart Citation

Mineralogical and pore structure of organic-rich deltaic shales and sub-bituminous coals from early Maastrichtian Mamu Formation, Anambra Basin, Nigeria

Faboya

Sonibare

et al. 2020

SN Appl. Sci.

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“…The pore size distributions of six coal samples derived from N 2 adsorption branch via the Barrett-Joyner-Halenda (BJH) model are presented in Figure 3. The specific surface area is obtained using the Brunauer-Emmett-Teller (BET) model [36,37]. Pores can be classified into micropore (<10 nm), mesopore (10-100 nm), and macropore (>100 nm).…”

Section: Results and Discussmentioning

confidence: 99%

Evaluation of Coal Pore Connectivity Using N2 Sorption Isotherm and Spontaneous Imbibition Tests

Xia

Fan

et al. 2021

Geofluids

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Pore structure and connectivity of coal are critical factors in coal gas migration and production, which can be characterized by studying the kinetics of capillary imbibition behaviour within the pore spaces. In order to investigate them, six typical coal samples from different collieries in China (Yangcun, Changcun, Gengcun, Yanbei, Dongxia, and Yuwu coal) are selected to carry out N2 sorption isotherm and spontaneous imbibition tests. Results from N2 sorption isotherm tests show that there is a great difference between the total specific surface area and total pore volume among the six coal samples. Their total specific surface area varies from 0.302 to 3.275 m2/g, and the total pore volume varies from 1.782 to 10.94 mm3/g. The pore volume relationship of coal sample among them is in order from the large to small: Dongxia>Yangcun>Gengcun>Yuwu>Changcun>Yanbei coal, and the specific surface area is in order from the large to small: Yangcun>Dongxia>Changcun>Yuwu>Gengcun>Yanbei coal. The imbibition characters of six coal samples were matched using explicit the short-time limit t ⟶ 0 and long-time limit t ⟶ ∞ models by Zhmud et al., respectively. The results show that the long-time limit t ⟶ ∞ model is better. Combined with pore structure analysis, it can be qualitatively analyzed that the imbibition capacity of six coal samples is positively correlated with the connectivity of coal pores, which is ranked as Changcun>Yanbei>Gengcun>Yangcun>Dongxia>Yuwu coal. This work will help understand the mechanism controlling fluid loss and ultimate gas/oil recovery in unconventional hydrocarbon exploration.

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“…Marine shale gas in China, represented by Longmaxi formation shale in the Sichuan Basin, has achieved considerable production, showing great shale gas potential [3]. In contrast, most of the continental shale gas in China is still in the resource evaluation stage due to its low maturity and lower gas show in exploration wells [3][4][5]. Accurate acquisition of shale gas content is of great significance for analyzing gas accumulation and assessing gas resources [6][7][8][9][10][11].…”

Section: Introductionmentioning

confidence: 99%

Influencing Factors and Mathematical Prediction of Shale Adsorbed Gas Content in the Upper Triassic Yanchang Formation in the Ordos Basin, China

et al. 2019

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Evaluating absorbed gas content (AGC) in shales is crucial for accurately characterizing shale gas reservoirs and calculating resource potential. To investigate geological factors influencing AGC, 15 shale samples collected from the Yanchang Formation underwent related experiments. Then geochemistry features, mineral compositions, pore structure parameters and external factors were analyzed. The actual AGC was calculated using the Langmuir equation. Single geological factors acting on the AGC were discussed by the single-factor correlation analysis. Finally, four main influence factors (total organic carbon, S1, quartz content and formation temperature) were selected out from the 12 influence factors to establish the mathematical prediction model through the multi-factor regression statistical analysis method using SPSS software. The model was verified as being reliable with R2 as high as 0.8046 and relative error less than ±20%. Comparisons show that both the CH4 isothermal adsorption experimental method and the multi-factor regression analysis method have their own applicability and disadvantages, and they can complement each other in evaluating AGC in shales. Synthetic evaluation of AGC indicates that the Yanchang shale has an overall moderate AGC occupying about 58% of the total, which is helpful to extend shale gas production time of the Yanchang reservoir. Though under the present conditions, economic benefits of the continental shale gas are not obvious, the shale resource potential of Yanchang formation can’t be ignored.

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Formation and development of pore structure in marine-continental transitional shale from northern China across a maturation gradient: insights from gas adsorption and mercury intrusion

Cited by 64 publications

References 65 publications

Mineralogical and pore structure of organic-rich deltaic shales and sub-bituminous coals from early Maastrichtian Mamu Formation, Anambra Basin, Nigeria

Mineralogical and pore structure of organic-rich deltaic shales and sub-bituminous coals from early Maastrichtian Mamu Formation, Anambra Basin, Nigeria

Evaluation of Coal Pore Connectivity Using N2 Sorption Isotherm and Spontaneous Imbibition Tests

Influencing Factors and Mathematical Prediction of Shale Adsorbed Gas Content in the Upper Triassic Yanchang Formation in the Ordos Basin, China

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