scholarly journals Effect of Pre-Adsorbed Water on Methane Adsorption Capacity in Shale-Gas Systems

2021 ◽  
Vol 9 ◽  
Author(s):  
Lei Chen ◽  
Zhenxue Jiang ◽  
Shu Jiang ◽  
Song Guo ◽  
Jingqiang Tan
Keyword(s):  
Relative Humidity ◽  
Adsorption Capacity ◽  
Shale Gas ◽  
Evaluation Method ◽  
Gas Adsorption ◽  
Water Saturation ◽  
Adsorbed Water ◽  
Lower Jurassic ◽  
Methane Adsorption ◽  
Gas Content

The presence and content of water will certainly affect the gas adsorption capacity of shale and the evaluation of shale gas content. In order to reasonably evaluate the gas adsorption capacity of shale under actual reservoir conditions, the effect of water on methane adsorption capacity needs to be investigated. Taking the Da’anzhai Member of the Lower Jurassic Ziliujing Formation in the northeastern Sichuan Basin, China as an example, this study attempts to reveal the effect of pre-adsorbed water on methane adsorption capacity in shale-gas systems by conducting methane adsorption experiments in two sequences, firstly at different temperatures under dry condition and secondly at different relative humidity levels under the same temperature. The results show that temperature and relative humidity (i.e., water saturation) are the main factors affecting the methane adsorption capacity of shale for a single sample. The key findings of this study include: 1) Methane adsorption capacity of shale first increases then decreases with depth, reaching a peak at about 1,600–2,400 m. 2) Lower relative humidity correlates to greater maximum methane adsorption capacity and greater depth to reach the maximum methane adsorption capacity. 3) 20% increase of relative humidity results in roughly 10% reduction of maximum methane adsorption capacity. As a conclusion, methane adsorption capacity of shale is predominately affected by water saturation, pore type and pore size of shale. This study could provide a theoretical basis for the establishment of a reasonable evaluation method for shale adsorbed gas content.

scholarly journals Reservoir Characteristics of the Lower Jurassic Lacustrine Shale in the Eastern Sichuan Basin and Its Effect on Gas Properties: An Integrated Approach

Energies ◽  
2020 ◽  
Vol 13 (17) ◽  
pp. 4495
Author(s):  
Jianhua He ◽  
Hucheng Deng ◽  
Ruolong Ma ◽  
Ruyue Wang ◽  
Yuanyuan Wang ◽  
...  
Keyword(s):  
Adsorption Capacity ◽  
Shale Gas ◽  
Lower Jurassic ◽  
Gas Content ◽  
Carbonate Content ◽  
Great Success ◽  
High Porosity ◽  
Reservoir Characteristics ◽  
Laminated Structures ◽  
Gas Properties

The exploration of shale gas in Fuling area achieved great success, but the reservoir characteristics and gas content of the lower Jurassic lacustrine in the northern Fuling areas remain unknown. We conducted organic geochemical analyses, Field Emission Scanning Electron Microscope (FE-SEM), X-ray diffraction (XRD) analysis, high-pressure mercury intrusion (MIP) and CH4adsorption experimental methods, as well as NMR logging, to study mineral composition, geochemical, pore structure characteristics of organic-rich shales and their effects on the methane adsorption capacity. The Da’anzhai shale member is generally a set of relatively thick (avg. 75 m) and high carbonate-content (avg. 56.89%) lacustrine sediments with moderate total organic carbon (TOC) (avg. 1.12%) and thermal maturation (Vitrinite reflectance (VR): avg. 1.19%). Five types of lithofacies can be classified: marl (ML), calcareous shale (CS), argillaceous shale (AS), muddy siltstone (MS), and silty shale (SS). CS has good reservoir quality with a high porosity (avg. 4.72%). The small pores with the transverse relaxation time of 0.6–1 ms and 1–3 ms comprised the major part of the porosity in the most lithofacies from Nuclear magnetic resonance (NMR) data, while the large pore (>300 ms) accounts for a small porosity proportion in the CS. The pores mainly constitute of mesopores (avg. 23.2 nm). The clay minerals with a large number of interparticle pores in the SEM contributes most to surface area in the shale lithofacies with a moderate TOC. The adsorption potential of shale samples is huge with an average adsorption capacity of 4.38 mL/g and also has high gas content (avg. 1.04 m3/t). The adsorption capacity of shale samples increases when TOC increases and temperature decreases. Considered reservoir properties and gas properties, CS with the laminated structures in the medium-upper section of the Da’anzhai member is the most advantage lithofacies for shale gas exploitation.

scholarly journals Changes in Pore Structure of Coal Caused by CS2 Treatment and Its Methane Adsorption Response

Geofluids ◽  
2018 ◽  
Vol 2018 ◽  
pp. 1-11 ◽  
Author(s):  
Run Chen ◽  
Yong Qin ◽  
Pengfei Zhang ◽  
Youyang Wang
Keyword(s):  
Pore Structure ◽  
Adsorption Capacity ◽  
Gas Adsorption ◽  
Recovery Process ◽  
Micropore Volume ◽  
Methane Adsorption ◽  
Coal Bed ◽  
Methane Recovery ◽  
Before And After ◽  
Key Issues

The pore structure and gas adsorption are two key issues that affect the coal bed methane recovery process significantly. To change pore structure and gas adsorption, 5 coals with different ranks were treated by CS2 for 3 h using a Soxhlet extractor under ultrasonic oscillation conditions; the evolutions of pore structure and methane adsorption were examined using a high-pressure mercury intrusion porosimeter (MIP) with an AutoPore IV 9310 series mercury instrument. The results show that the cumulative pore volume and specific surface area (SSA) were increased after CS2 treatment, and the incremental micropore volume and SSA were increased and decreased before and after Ro,max=1.3%, respectively; the incremental big pore (greater than 10 nm in diameter) volumes were increased and SSA was decreased for all coals, and pore connectivity was improved. Methane adsorption capacity on coal before and after Ro,max=1.3% also was increased and decreased, respectively. There is a positive correlation between the changes in the micropore SSA and the Langmuir volume. It confirms that the changes in pore structure and methane adsorption capacity due to CS2 treatment are controlled by the rank, and the change in methane adsorption is impacted by the change of micropore SSA and suggests that the changes in pore structure are better for gas migration; the alteration in methane adsorption capacity is worse and better for methane recovery before and after Ro,max=1.3%. A conceptual mechanism of pore structure is proposed to explain methane adsorption capacity on CS2 treated coal around the Ro,max=1.3%.

scholarly journals Effect of Kerogen Thermal Maturity on Methane Adsorption Capacity: A Molecular Modeling Approach

Molecules ◽  
2020 ◽  
Vol 25 (16) ◽  
pp. 3764 ◽  
Author(s):  
Saad Alafnan ◽  
Theis Solling ◽  
Mohamed Mahmoud
Keyword(s):  
Molecular Modeling ◽  
Adsorption Capacity ◽  
Gas Adsorption ◽  
Material Balance ◽  
Methane Adsorption ◽  
Source Rocks ◽  
Thermal Maturity ◽  
Reserve Estimation ◽  
Adsorbed Gas ◽  
Key Factor

The presence of kerogen in source rocks gives rise to a plethora of potential gas storage mechanisms. Proper estimation of the gas reserve requires knowledge of the quantities of free and adsorbed gas in rock pores and kerogen. Traditional methods of reserve estimation such as the volumetric and material balance approaches are insufficient because they do not consider both the free and adsorbed gas compartments present in kerogens. Modified versions of these equations are based on adding terms to account for hydrocarbons stored in kerogen. None of the existing models considered the effect of kerogen maturing on methane gas adsorption. In this work, a molecular modeling was employed to explore how thermal maturity impacts gas adsorption in kerogen. Four different macromolecules of kerogen were included to mimic kerogens of different maturity levels; these were folded to more closely resemble the nanoporous kerogen structures of source rocks. These structures form the basis of the modeling necessary to assess the adsorption capacity as a function of the structure. The number of double bonds plus the number and type of heteroatoms (O, S, and N) were found to influence the final configuration of the kerogen structures, and hence their capacity to host methane molecules. The degree of aromaticity increased with the maturity level within the same kerogen type. The fraction of aromaticity gives rise to the polarity. We present an empirical mathematical relationship that makes possible the estimation of the adsorption capacity of kerogen based on the degree of polarity. Variations in kerogen adsorption capacity have significant implications on the reservoir scale. The general trend obtained from the molecular modeling was found to be consistent with experimental measurements done on actual kerogen samples. Shale samples with different kerogen content and with different maturity showed that shales with immature kerogen have small methane adsorption capacity compared to shales with mature kerogen. In this study, it is shown for the first time that the key factor to control natural gas adsorption is the kerogen maturity not the kerogen content.

Factors affecting the nanopore structure and methane adsorption capacity of organic-rich marine shales in Zhaotong area, Southern Sichuan Basin

2020 ◽  
Vol 8 (2) ◽  
pp. T403-T419
Author(s):  
Panke Sun ◽  
Hanqing Zhu ◽  
Huaimin Xu ◽  
Xiaoni Hu ◽  
Linfeng Tian
Keyword(s):  
Adsorption Capacity ◽  
Sichuan Basin ◽  
Clay Content ◽  
Mineralogical Composition ◽  
Methane Adsorption ◽  
Gas Content ◽  
Quartz Content ◽  
Structure Characteristics ◽  
Longmaxi Shale ◽  
Nanopore Structure

As a national shale-gas demonstration zone in China, the Zhaotong area has great gas resource potential. However, the nanopore structure characteristics, methane adsorption capacity, and their affecting factors of the Lower Silurian Longmaxi Shale in this area remain unclear. To address these puzzles, we conducted a series of experiments, such as X-ray diffraction, field emission scanning electron microscopy, low-pressure [Formula: see text] adsorption, and high-pressure methane adsorption, and we calculated the relevant characteristic parameters, such as pore volume (PV), specific surface area (SSA), fractal dimension, and Langmuir parameters by using the nonlocal density functional theory method, Frenkel-Halsey-Hill theory, and Langmuir model, respectively. The results indicate that the nanopores of the Lower Longmaxi Shale in the Zhaotong area are composed of micropores and mesopores, which mainly exist as organic matter (OM) pores. The pore surface exhibits a high degree of heterogeneity as indicated by the fractal dimensions ranging from 2.845 to 2.866. The nanopore structure characteristics (i.e., SSA and PV) and methane adsorption capacity are mainly controlled by the total organic carbon (TOC) content. In addition, the mineralogical composition (i.e., the quartz and clay content) also contributes significantly to the micropore PV and gas content. The external provenance has a significant effect on the mineralogical composition, TOC content, and methane adsorption capacity. With the increasing influence of the external provenance, the biogenic quartz content decreases and the relationship between the quartz content and TOC content becomes more discrete, which indicates the change of depositional environment, and the clay content increases, which can dilute the OM concentration during the deposition and enhance the compaction potential, and it can eventually result in less gas content. The results of this study reveal the nanopore system characteristics of the Longmaxi Shale in the Zhaotong area and provide further insight into the influence of external provenance on reservoir characteristics and gas content variability of the Lower Longmaxi Shale in the southern Sichuan Basin.

Two effective methods for calculating water saturations in shale-gas reservoirs

Geophysics ◽  
2017 ◽  
Vol 82 (3) ◽  
pp. D187-D197 ◽  
Author(s):  
Jingling Xu ◽  
Lei Xu ◽  
Yuxing Qin
Keyword(s):  
Shale Gas ◽  
Water Saturation ◽  
Critical Issue ◽  
Petroleum Exploration ◽  
Gas Content ◽  
Gas Reservoirs ◽  
Gas Saturation ◽  
Shale Gas Reservoirs ◽  
Shale Reservoirs ◽  
Southeastern Sichuan Basin

Water saturation is one of the most important parameters in petroleum exploration and development. However, its calculation has been limited by the insufficient logging data required by a new technique that further influences the calculation of the free gas content. The accuracy of water saturation estimates is also a critical issue because it controls whether or not we can obtain an accurate gas saturation estimate. Organic matter plays an important role in shale-gas reservoirs, and the total organic carbon (TOC) indirectly controls the gas content and gas saturation. Hence, water saturation is influenced by inorganic and organic components. After analyzing the relationship among TOC, core water saturation, and conventional gas saturation, considering the influence of TOC on gas saturation in organic-rich shale reservoirs, we developed two new methods to improve the accuracy of water saturation estimates: the revised water saturation-TOC method and the water saturation separation method, in which Archie water saturation, modified total shale water saturation, and TOC are integrated. According to case studies of Longmaxi-Wufeng shale, southeastern Sichuan Basin, China, the water saturation results from these two methods in shale reservoirs with different lithologies are consistent with those from core analysis. We concluded that these two methods can be evaluated quickly and they effectively evaluate the water saturation of shale reservoirs.

Modeling Gas Adsorption in Marcellus Shale With Langmuir and BET Isotherms

SPE Journal ◽  
2016 ◽  
Vol 21 (02) ◽  
pp. 589-600 ◽  
Author(s):  
Wei Yu ◽  
Kamy Sepehrnoori ◽  
Tadeusz W. Patzek
Keyword(s):  
Shale Gas ◽  
Langmuir Isotherm ◽  
History Matching ◽  
Gas Adsorption ◽  
Marcellus Shale ◽  
Methane Adsorption ◽  
Gas Reservoirs ◽  
Gas Desorption ◽  
Shale Gas Reservoirs ◽  
Bet Isotherm

Summary Production from shale-gas reservoirs plays an important role in natural-gas supply in the United States. Horizontal drilling and multistage hydraulic fracturing are the two key enabling technologies for the economic development of these shale-gas reservoirs. It is believed that gas in shale reservoirs is mainly composed of free gas within fractures and pores and adsorbed gas in organic matter (kerogen). It is generally assumed in the literature that the monolayer Langmuir isotherm describes gas-adsorption behavior in shale-gas reservoirs. However, in this work, we analyzed four experimental measurements of methane adsorption from the Marcellus Shale core samples that deviate from the Langmuir isotherm, but obey the Brunauer-Emmett-Teller (BET) isotherm. To the best of our knowledge, it is the first time to find that methane adsorption in a shale-gas reservoir behaves similar to multilayer adsorption. Consequently, investigation of this specific gas-desorption effect is important for accurate evaluation of well performance and completion effectiveness in shale-gas reservoirs on the basis of the BET isotherm. The difference in calculating original gas in place (OGIP) on the basis of both isotherms is discussed. We also performed history matching with one production well from the Marcellus Shale and evaluated the contribution of gas desorption to the well's performance. History matching shows that gas adsorption obeying the BET isotherm contributes more to overall gas recovery than gas adsorption obeying the Langmuir isotherm, especially at early time in production. This work provides better understanding of gas desorption in shale-gas reservoirs and updates our current analytical and numerical models for simulation of shale-gas production.

scholarly journals Characteristics and Origin of Methane Adsorption Capacity of Marine, Transitional, and Lacustrine Shales in Sichuan Basin, China

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-12
Author(s):  
Xianglu Tang ◽  
Wei Wu ◽  
Guanghai Zhong ◽  
Zhenxue Jiang ◽  
Shijie He ◽  
...  
Keyword(s):  
Organic Matter ◽  
Water Content ◽  
Adsorption Capacity ◽  
Clay Minerals ◽  
Shale Gas ◽  
Sichuan Basin ◽  
Thermal Evolution ◽  
Methane Adsorption ◽  
Isothermal Adsorption ◽  
Xujiahe Formation

Adsorbed gas is an important component of shale gas. The methane adsorption capacity of shale determines the composition of shale gas. In this study, the methane adsorption capacity of marine, transitional, and lacustrine shales in the Sichuan Basin was analyzed through its isothermal adsorption, mineral composition, water content, etc. The results show that the methane adsorption capacity of marine (Qiongzhusi Formation and Longmaxi Formation), transitional (Longtan Formation), and lacustrine (Xujiahe Formation and Ziliujing Formation) shales is significantly different. The Longtan Formation has the strongest methane adsorption capacity. This is primarily related to its high organic matter and organic matter type III content. The methane adsorption capacity of the lacustrine shale was the weakest. This is primarily related to the low thermal evolution degree and the high content of water-bearing clay minerals. Smectite has the highest methane adsorption capacity of the clay minerals, due to its crystal structure. The water content has a significant effect on methane adsorption largely because water molecules occupy the adsorption site. Additionally, the temperature and pressure in a specific range significantly affect methane adsorption capacity.

scholarly journals Application of a Modified Low-Field NMR Method on Methane Adsorption of Medium-Rank Coals

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-16
Author(s):  
Xiaozhen Chen ◽  
Taotao Yan ◽  
Fangui Zeng ◽  
Yanjun Meng ◽  
Jinhua Liu
Keyword(s):  
Adsorption Capacity ◽  
Coalbed Methane ◽  
Gas Adsorption ◽  
Vitrinite Reflectance ◽  
Methane Adsorption ◽  
Coal Rank ◽  
Nmr Method ◽  
Low Field ◽  
Low Field Nmr ◽  
The Absolute

Methane adsorption capacity is an important parameter for coalbed methane (CBM) exploitation and development. Traditional examination methods are mostly time-consuming and could not detect the dynamic processes of adsorption. In this study, a modified low-field nuclear magnetic resonance (NMR) method that compensates for these shortcomings was used to quantitatively examine the methane adsorption capacity of seven medium-rank coals. Based on the typical T 2 amplitudes obtained from low-field NMR measurement, the volume of adsorbed methane was calculated. The results indicate that the Langmuir volume of seven samples is in a range of 18.9–31.85 m3/t which increases as the coal rank increases. The pore size in range 1-10 nm is the main contributor for gas adsorption in these medium-rank coal samples. Comparing the adsorption isotherms of these coal samples from the modified low-field NMR method and volumetric method, the absolute deviations between these two methods are less than 1.03 m3/t while the relative deviations fall within 4.76%. The absolute deviations and relative deviations decrease as vitrinite reflectance ( R o ) increases from 1.08% to 1.80%. These results show that the modified low-field NMR method is credible to measure the methane adsorption capacity and the precision of this method may be influenced by coal rank.

Inversion-based method for estimating total organic carbon and porosity and for diagnosing mineral constituents from multiple well logs in shale-gas formations

2013 ◽  
Vol 1 (1) ◽  
pp. T113-T123 ◽  
Author(s):  
Zoya Heidari ◽  
Carlos Torres-Verdín
Keyword(s):  
Shale Gas ◽  
Evaluation Method ◽  
Water Saturation ◽  
Total Porosity ◽  
Well Logs ◽  
Well Log ◽  
X Ray Diffraction ◽  
X Ray ◽  
Compositional Properties ◽  
Organic Shale

Reliable estimates of petrophysical and compositional properties of organic shale are critical for detecting perforation zones or candidates for hydro-fracturing jobs. Current methods for in situ formation evaluation of organic shale largely rely on qualitative responses and empirical formulas. Even core measurements can be inconsistent and inaccurate when evaluating clay minerals and other grain constituents. We implement a recently introduced inversion-based method for organic-shale evaluation from conventional well logs. The objective is to estimate total porosity, total organic carbon (TOC), and volumetric/weight concentrations of mineral/fluid constituents. After detecting bed boundaries, the first step of the method is to perform separate inversion of individual well logs to estimate bed physical properties such as density, neutron migration length, electrical conductivity, photoelectric factor (PEF), and thorium, uranium , and potassium volumetric/weight concentrations. Next, a multilayer petrophysical model specific to organic shale is constructed with an initial guess obtained from conventional well-log interpretation or X-ray diffraction data; bed physical properties are calculated with the initial layer-by-layer values. Final estimates of organic shale petrophysical and compositional properties are obtained by progressively minimizing the difference between calculated and measured bed properties. A unique advantage of this method is the correction of shoulder-bed effects on well logs, which are prevalent in shale-gas plays. Another advantage is the explicit calculation of accurate well-log responses for specific petrophysical, mineral, fluid, and kerogen properties based on chemical formulas and volumetric concentrations of minerals/kerogen and fluid constituents. Examples are described of the successful application of the new organic-shale evaluation method in the Haynesville shale-gas formation. This formation includes complex solid compositions and thin beds where rapid depth variations of mineral/fluid constituents are commonplace. Comparison of estimates for total porosity, total water saturation, and TOC obtained with (a) commercial software for multimineral analysis, (b) our organic-shale evaluation method, and (c) core/X-ray diffraction measurements indicates a significant improvement in estimates of total porosity and water saturation yielded by our interpretation method. The estimated TOC is also in agreement with core laboratory measurements.

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