Impacts of gas pressure on carbon isotope fractionation during methane degassing—An experimental study on shales from Wufeng and Longmaxi Formations in southeast Sichuan, China

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The physical properties of gas shales, especially the structural features of connected pore-fractures, are key parameters for evaluating shale gas resource potential and effective production. In this study, four major techniques, including mercury intrusion capillary pressure (MICP), low-temperature nitrogen adsorption/desorption (LT-NA/D) tests, scanning electron microscopy (SEM), and fractal theory, were adopted to establish a suitable pore size classification for gas shales from the Wufeng–Longmaxi formations in the southeastern Sichuan Basin. On the basis of the inflection points of the mercury intrusion curves, a quantitative classification for connected pore-fractures of gas shales in the study area was proposed: micropores (<10 nm), ostioles (10–25 nm), mesopores (25–100 nm), macropores (100 nm–5000 nm), and fractures (>5000 nm). This classification method was verified using fractal geometry theory and was reasonable as compared to other pore size classification methods of unconventional reservoir. The controlling factors of pore-fractures systems were also investigated according to shale compositions and SEM images. The results show that gas shales mainly developed organic matter (OM) pores, interparticle (interP) pores, and intraparticle (intraP) pores. Among them, the OM pores are composed mainly of micropores and ostioles, which can effectively increase the gas storage capacity of shale. The increase of pore content with diameter greater than 25 nm may increase the seepage capacity of gas shales. The quality of shale gas reservoirs is usually affected by multiparameter such as microscopic pore-fractures content, pore size distribution, specific surface area, porosity, and shale compositions (including minerals and OM). The gas shales could be classified into three types (i.e., types I, II, and III). Type III shale is a high-quality shale gas reservoir, which is rich in micropores (35.90–87.83 vol %), has a high total organic carbon (TOC) content (2.55–3.39%), has a high porosity (10.96–16.01%), and has good fracturing ability (the average content of quartz is 53.88%). Type I shale is a poor shale gas reservoir, but it can be used as a good gas seepage channel due to the high content of fractures and macropores (mean 39.48 vol % and 18.89 vol %). Type II shale is a transitional shale gas reservoir.

Section: Resultsmentioning

confidence: 99%

Section: Resultsmentioning

confidence: 99%

Classification Evaluation of Gas Shales Based on High-Pressure Mercury Injection: A Case Study on Wufeng and Longmaxi Formations in Southeast Sichuan, China

Wei

et al. 2021

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“…Recent studies have found significant carbon isotope fractionation when monitoring the isotopic composition of released gas during canister degassing − and transport simulation − experiments. Further investigation revealed that the fractionation characteristics (duration and amplitude) during methane transport are correlated with the material composition, , pore structure, ,, GIP content, , and AGR, ,,,,, providing a novel approach to assess the gas-bearing parameters using isotopic fractionation. Li et al proposed a carbon isotope fractionation (CIF) model that can effectively characterize the entire shale gas degassing process based on experimental findings and mechanism analysis.…”

Section: Introductionmentioning

confidence: 99%

Comparison and Verification of Gas-Bearing Parameter Evaluation Methods for Deep Shale Based on the Pressure Coring Technique

Zhao

Wu³

et al. 2023

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Gas-bearing properties, such as gas-in-place (GIP) content and adsorbed gas ratio (AGR), have drawn considerable attention because they are essential for shale gas resource evaluation and sweet spot forecasting. The above-mentioned metrics have been determined using a variety of approaches, but they lack systematic comparison and accuracy verification, particularly for deep shale gas, where conventional methods frequently fall short. A total of 30 shales were taken for the investigation utilizing pressure and conventional coring methods from Wufeng and Longmaxi Formations in the Sichuan Basin, China. For pressure coring samples, we developed the experimental protocols and a GIP content classification scheme that categorizes the GIP content into four categories: lost gas (estimated using the temperature-corrected pressure-holding ratio), extracted gas from depressurization, degassed gas, and residual gas. The four pressure coring samples from well Y206 with measured GIP content range from 2.84 to 5.58 m 3 /tonne, with an average of 4.72 m 3 /tonne. In contrast to the calculated GIP content of the pressure coring samples, the validity of the current GIP content evaluation methodologies has been confirmed. The comparison results demonstrate that the GIP content assessed using the United States Bureau of Mines (USBM) method is frequently underestimated for samples from conventional coring and notably overstated for samples from pressure coring. The polynomial fitting method dramatically overestimated the GIP content. With its accurate time-dependent boundary conditions and strict theoretical foundation, the simplified carbon isotope fractionation (s-CIF) model exhibits the highest level of accuracy in determining GIP content. Additionally, the s-CIF model can find yet another crucial parameter of AGR. Shale samples from well Y206 had an average AGR of 20.4% but a range from 12.2 to 33.2%. The examination of the influencing factors demonstrates that the lost gas ratio, AGR, and diffusion coefficient are responsible for controlling the calculation error of the USBM method. The lost gas ratio prior to core retrieval increases with decreasing AGR (or increasing diffusion coefficient), which increases the computation error of the USBM method.

“…In recent years, studies have found that significant and complex isotope fractionation is prevalent, whether during the laboratory resaturation degassing experiments of small-scale cores, , the canister degassing experiments of full-diameter cores, ,− or the continuous monitoring of production wells at larger scales. ,, Meanwhile, the isotopic fractionation characteristics are closely related to factors such as shale gas content, , adsorbed gas ratio, ,− material composition, pore structure, and degradation behavior, ,,,− which provide a material basis for evaluating the above key parameters by means of isotope methods. Li et al proposed a model that is capable of accurately describing methane migration in tight sedimentary rocks through conducting systematic laboratory simulation experiments and mechanism analysis, named the carbon isotope fractionation (CIF) model .…”

Section: Introductionmentioning

confidence: 99%

Determination of Shale Gas-Bearing Properties Based on Carbon Isotope Fractionation Model: A Case Study from Longmaxi Formation Shales in Jiaoshiba Area, Sichuan Basin, China

Liu³

et al. 2023

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Adsorbed gas ratio and gas-in-place (GIP) content are two critical parameters for determining shale gas resources and devising development plans. Existing traditional methods have their limitations in solving the above issues, while a novel approach for evaluating the aforementioned key parameters was provided by the carbon isotope fractionation (CIF) model. To investigate the stable carbon isotope fractionation and shale gas content characteristics during the degassing process, 10 shale samples from Well JY A in the Jiaoshiba area of the Sichuan Basin were chosen for on-site degassing tests. The on-site degassing patterns were recorded, and the methane, ethane, and carbon dioxide isotope values were measured. The CIF model was used to evaluate the gas degassing patterns and isotope fractionation characteristics of the complete degassing process and accurately assess the in situ gas-bearing parameters of the Well JY A shale. Research has shown that during a 20 h degassing process, the methane fractionation magnitude can reach 10‰, and the ethane fractionation magnitude is about 2‰. There are no significant fractionation characteristics for carbon dioxide. The complete cumulative degassing curve exhibits a "downward convex" shape followed by an "upward convex" shape, while the complete isotope fractionation curve shows a three-stage pattern of "initially stable, then lighter, and finally heavier". Free gas diffuses first, followed by the desorption of adsorbed gas, which lags behind significantly, and the adsorbed gas ratio controls the apparent carbon isotope fractionation. Initially, diffusion fractionation dominates, while later, adsorption−desorption fractionation gradually becomes dominant. Using the CIF model, the GIP content of shale in the Well JY A ranges 2.52−5.11 mL/g, averaging 3.56 mL/g, and the adsorbed gas ratio accounts for 4.39%−30.28%, averaging 14.64%. Using the U.S. Bureau of Mines (USBM) method, the GIP content ranges 1.49−4.14 mL/g, averaging 2.69 mL/g, which is significantly underestimated in this area.