Investigating Influential Factors of the Gas Absorption Capacity in Shale Reservoirs Using Integrated Petrophysical, Mineralogical and Geochemical Experiments: A Case Study

Estimating in situ gas content is very important for the effective exploration of shale gas reservoirs. However, it is difficult to choose the sensitive geological and geophysical parameters during the modeling process, since the controlling factors for the abundance of gas volumes are often unknown and hard to determine. Integrated interdisciplinary experiments (involving petrophysical, mineralogical, geochemical and petrological aspects) were conducted to search for the influential factors of the adsorbed gas volume in marine gas shale reservoirs. The results showed that in shale reservoirs with high maturity and high organic content that the adsorbed gas volume increases, with an increase in the contents of organic matter and quartz, but with a decrease in clay volume. The relationship between the adsorbed gas content and the total porosity is unclear, but a strong relationship between the proportions of different pores is observed. In general, the larger the percentage of micropores, the higher the adsorbed gas content. The result is illuminating, since it may help us to choose suitable parameters for the estimation of shale gas content.

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Effect of reservoir pressure and total organic content on adsorbed gas production in shale reservoirs: a numerical modelling study

Arabian Journal of Geosciences ◽

10.1007/s12517-021-09416-x ◽

2022 ◽

Vol 15 (2) ◽

Author(s):

Moataz Mansi ◽

Mohamed Almobarak ◽

Christopher Lagat ◽

Quan Xie

Keyword(s):

Numerical Modelling ◽

Shale Gas ◽

Organic Content ◽

Gas Production ◽

Reservoir Pressure ◽

Adsorbed Gas ◽

Total Organic Content ◽

Simulation Results ◽

Shale Reservoirs ◽

The Impact

AbstractAdsorbed gas plays a key role in organic-rich shale gas production due to its potential to contribute up to 60% of the total gas production. The amount of gas potentially adsorbed on organic-rich shale is controlled by thermal maturity, total organic content (TOC), and reservoir pressure. Whilst those factors have been extensively studied in literature, the factors governing desorption behaviour have not been elucidated, presenting a substantial impediment in managing and predicting the performance of shale gas reservoirs. Therefore, in this paper, a simulation study was carried out to examine the effect of reservoir depth and TOC on the contribution of adsorbed gas to shale gas production. The multi-porosity and multi-permeability model, hydraulic fractures, and local grid refinements were incorporated in the numerical modelling to simulate gas storage and transient behaviour within matrix and fracture regions. The model was then calibrated using core data analysis from literature for Barnett shales. Sensitivity analysis was performed on a range of reservoir depth and TOC to quantify and investigate the contribution of adsorbed gas to total gas production. The simulation results show the contribution of adsorbed gas to shale gas production decreases with increasing reservoir depth regardless of TOC. In contrast, the contribution increases with increasing TOC. However, the impact of TOC on the contribution of adsorbed gas production becomes minor with increasing reservoir depth (pressure). Moreover, the results suggest that adsorbed gas may contribute up to 26% of the total gas production in shallow (below 4,000 feet) shale plays. These study findings highlight the importance of Langmuir isothermal behaviour in shallow shale plays and enhance understanding of desorption behaviour in shale reservoirs; they offer significant contributions to reaching the target of net-zero CO2 emissions for energy transitions by exhibiting insights in the application of enhanced shale gas recovery and CO2 sequestration — in particular, the simulation results suggest that CO2 injection into shallow shale reservoirs rich in TOC, would give a much better performance to unlock the adsorbed gas and sequestrate CO2 compared to deep shales.

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The Gas Content Characteristics of Nanopores Developed in a Normal Pressure Shale Gas Reservoir in Southeast Chongqing, Sichuan Basin, China

Journal of Nanoscience and Nanotechnology ◽

10.1166/jnn.2021.18453 ◽

2021 ◽

Vol 21 (1) ◽

pp. 698-706

Author(s):

Fangwen Chen ◽

Qiang Zheng ◽

Hongqin Zhao ◽

Xue Ding ◽

Yiwen Ju ◽

...

Keyword(s):

Organic Carbon ◽

Shale Gas ◽

Normal Pressure ◽

Gas Content ◽

Organic Carbon Content ◽

Gas Reservoir ◽

Free Gas ◽

Shale Gas Reservoir ◽

Adsorbed Gas ◽

Longmaxi Shale

To evaluate the gas content characteristics of nanopores developed in a normal pressure shale gas reservoir, the Py1 well in southeast Chongqing was selected as a case study. A series of experiments was performed to analyze the total organic carbon content, porosity and gas content using core material samples of the Longmaxi Shale from the Py1 well. The results show that the adsorbed gas and free gas content in the nanopores developed in the Py1 well in the normal pressure shale gas reservoir range from 0.46–2.24 m3/t and 0.27–0.83 m3/t, with average values of 1.38 m3/t and 0.50 m3/t, respectively. The adsorbed gas is dominant in the shale gas reservoir, accounting for 53.05–88.23% of the total gas with an average value of 71.43%. The Gas Research Institute (GRI) porosity and adsorbed gas content increase with increasing total organic carbon content. The adsorbed gas and free gas contents both increase with increasing porosity value, and the rate of increase in the adsorbed gas content with porosity is larger than that of free gas. Compared with the other five shale reservoirs in America, the Lower Silurian Longmaxi Shale in the Py1 well developed nanopores but without overpressure, which is not favorable for shale gas enrichment.

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

Geophysics ◽

10.1190/geo2016-0462.1 ◽

2017 ◽

Vol 82 (3) ◽

pp. D187-D197 ◽

Cited By ~ 6

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.

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APPLICATION OF FRACTAL GEOMETRY IN EVALUATION OF EFFECTIVE STIMULATED RESERVOIR VOLUME IN SHALE GAS RESERVOIRS

Fractals ◽

10.1142/s0218348x17400072 ◽

2017 ◽

Vol 25 (04) ◽

pp. 1740007 ◽

Cited By ~ 25

Author(s):

GUANGLONG SHENG ◽

YULIANG SU ◽

WENDONG WANG ◽

FARZAM JAVADPOUR ◽

MEIRONG TANG

Keyword(s):

Hydraulic Fracturing ◽

Shale Gas ◽

Fractal Geometry ◽

Fracture Network ◽

Gas Reservoirs ◽

Stimulated Reservoir Volume ◽

Reservoir Volume ◽

Adsorbed Gas ◽

Shale Gas Reservoirs ◽

Shale Reservoirs

According to hydraulic-fracturing practices conducted in shale reservoirs, effective stimulated reservoir volume (ESRV) significantly affects the production of hydraulic fractured well. Therefore, estimating ESRV is an important prerequisite for confirming the success of hydraulic fracturing and predicting the production of hydraulic fracturing wells in shale reservoirs. However, ESRV calculation remains a longstanding challenge in hydraulic-fracturing operation. In considering fractal characteristics of the fracture network in stimulated reservoir volume (SRV), this paper introduces a fractal random-fracture-network algorithm for converting the microseismic data into fractal geometry. Five key parameters, including bifurcation direction, generating length ([Formula: see text]), deviation angle ([Formula: see text]), iteration times ([Formula: see text]) and generating rules, are proposed to quantitatively characterize fracture geometry. Furthermore, we introduce an orthogonal-fractures coupled dual-porosity-media representation elementary volume (REV) flow model to predict the volumetric flux of gas in shale reservoirs. On the basis of the migration of adsorbed gas in porous kerogen of REV with different fracture spaces, an ESRV criterion for shale reservoirs with SRV is proposed. Eventually, combining the ESRV criterion and fractal characteristic of a fracture network, we propose a new approach for evaluating ESRV in shale reservoirs. The approach has been used in the Eagle Ford shale gas reservoir, and results show that the fracture space has a measurable influence on migration of adsorbed gas. The fracture network can contribute to enhancement of the absorbed gas recovery ratio when the fracture space is less than 0.2 m. ESRV is evaluated in this paper, and results indicate that the ESRV accounts for 27.87% of the total SRV in shale gas reservoirs. This work is important and timely for evaluating fracturing effect and predicting production of hydraulic fracturing wells in shale reservoirs.

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Factors Controlling Shale Reservoirs and Development Potential Evaluation: A Case Study

Geofluids ◽

10.1155/2021/6661119 ◽

2021 ◽

Vol 2021 ◽

pp. 1-13

Author(s):

Chao Luo ◽

Hun Lin ◽

Yujiao Peng ◽

Hai Qu ◽

Xiaojie Huang ◽

...

Keyword(s):

Shale Gas ◽

Mineral Content ◽

Gas Content ◽

Longmaxi Formation ◽

Development Potential ◽

Reservoir Characteristics ◽

Lower Silurian ◽

Single Well ◽

Shale Reservoir ◽

Shale Reservoirs

The shale of the Lower Silurian Longmaxi Formation is an important gas-producing layer for shale gas development in southern China. This set of shale reservoir characteristics and shale gas development potential provide an important foundation for shale gas development. This study takes wellblock XN111 in the Sichuan Basin, China, as an example and uses X-ray diffraction (XRD), scanning electron microscopy (SEM), isothermal adsorption, and other techniques to analyze the shale reservoir characteristics of the Lower Silurian Longmaxi Formation. The results show that the Lower Silurian Longmaxi Formation was deposited in a deep-water shelf environment. During this period, carbonaceous shale and siliceous shale characterized by a high brittle mineral content ( quartz > 40 wt . % , carbonate mineral > 10 wt . % ) and a low clay mineral content (<30 wt.%, mainly illite) were widely deposited throughout the region. The total organic carbon (TOC) content reaches up to 6.07 wt.%, with an average of 2.66 wt.%. The vitrinite reflectance is 1.6–2.28%, with an average of 2.05%. The methane adsorption capacity is 0.84–4.69 m3/t, with an average of 2.92 m3/t. Pores and fractures are developed in the shale reservoirs. The main reservoir space is composed of connected mesopores with an average porosity of 4.78%. The characteristics and development potential of the shale reservoirs in the Lower Silurian Longmaxi Formation are controlled by the following factors: (1) the widespread deep-water shelf deposition in wellblock XN111 was a favorable environment for the development of high-quality shale reservoirs with a cumulative thickness of up to 50 m; (2) the high TOC content enabled the shale reservoir to have a high free gas content and a high adsorptive gas storage capacity; and (3) the shale’s high maturity or over maturity is conducive to the development of pores and fractures in the organic matter, which effectively improves the storage capacity of the shale reservoirs. The reservoir characteristic index was constructed using the high-quality shale’s thickness, gas content, TOC, fracture density, and clay content. Using production data from shale gas wells in adjacent blocks, a mathematical relationship was established between the Estimated Ultimate Recovery (EUR) of a single well and the Reservoir Characteristics Index (Rci). The EUR of a single well in wellblock XN111 was estimated.

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Shale Gas Content Calculation of the Triassic Yanchang Formation in the Southeastern Ordos Basin, China

10.20944/preprints201710.0052.v1 ◽

2017 ◽

Author(s):

Jiao Su ◽

Yingchu Shen ◽

Bo Liu ◽

Jin Hao

Keyword(s):

Shale Gas ◽

Calculation Method ◽

Indirect Method ◽

Ordos Basin ◽

Gas Content ◽

Dissolved Gas ◽

Yanchang Formation ◽

Free Gas ◽

Shale Reservoirs ◽

Method Show

Shale gas content is the key parameter for shale gas potential evaluation and favorable area prediction. Therefore, it is very important to determine shale gas content accurately. Generally, we use the USBM method for coal reservoirs to calculate gas content of shale reservoirs. However, shale reservoirs are different from coal reservoirs in depth, pressure, core collection, etc. This method would inevitably cause problems. In order to make the USBM method more suitable for shale reservoir, an improved USBM method is put forward on the basis of systematic analysis of core pressure history and temperature history during shale gas desorption. The improved USBM method modifies the calculation method of the lost time, and determines the temperature balance time of water heating. In addition, we give the calculation method of adsorption gas content and free gas content, especially the new method of calculating the oil dissolved gas content and water dissolved gas content which are easily neglected. We used the direct method (USBM and the improved USBM) and the indirect method (adsorption gas, free gas and dissolved gas) to calculate the shale gas content of 16 shale samples of the Triassic Yanchang Formation in the Southeastern Ordos Basin, China. The results of the improved USBM method show that the total shale gas content is high, with an average of 3.97 m3/t, and the lost shale gas content is the largest proportion with an average of 62%. The total shale gas content calculated by the improved USBM method is greater than that of the USBM method. The results of the indirect method show that the total shale gas content is large, with an average of 4.11 m3/t, and the adsorption shale gas content is the largest proportion with an average of 71%.  The oil dissolved shale gas content which should be taken attention accounts for about 7.8%. The relative error between the improved USBM method and indirect method is much smaller than that between USBM method and indirect method, which verifies the accuracy of the improved USBM method.

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Measurement of shale gas in place based on different approaches and their comparison study

Thermal Science ◽

10.2298/tsci190929467m ◽

2019 ◽

pp. 467-467

Author(s):

Asadullah Memon ◽

Aifen Li ◽

Xiaoxia Ren ◽

Asif Mehmood ◽

Qi Fang ◽

...

Keyword(s):

Experimental Data ◽

Shale Gas ◽

Gas Storage ◽

Langmuir Model ◽

Gas Absorption ◽

Comparison Study ◽

Sorption Mechanism ◽

Gas Reservoirs ◽

Sorption Model ◽

Adsorbed Gas

The understanding of gas sorption mechanism is essential to characterize the original gas-in-place for shale gas reservoirs. In this study, experimental data of five shale samples have been used to estimate the shale gas-in-place with new sights. Langmuir model is commonly used to measure the amount of adsorbed gas but this model does not include the amount of absorbed gas and its behavior. However, such gas usually contributes about 22% in respect to total gas storage even though its input remains undefined. Sorption model used in this study includes adsorbed and absorbed gas. Good results are obtained from sorption model as compared to Langmuir model. Variable range of total gas storage is observed using different approaches in all shale samples. Initially at low pressure, total gas storage is observed to be higher because of gas absorption contribution in new proposed approach when compared to approach-2. When pressure increases, total gas storage is altered in keeping with characteristics of adsorption and absorption of gas. Adsorbed and sorbed porosity is estimated at two different approaches and where total gas storages capacity is affected due to adsorbed or sorbed porosity. Further, the contribution of absorbed gas amount is found at about 19-22% in respect to total gas storage in all shale samples and that is in same range as mentioned in literature. The sorption model and new proposed approach includes adsorption and absorption of gases and provides new insights to understand the gas storage mechanisms and estimation of shale gas-in-place.

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A gas-content calculation model for terrestrial shales in the Kuqa Depression, the Tarim Basin, Western China

Interpretation ◽

10.1190/int-2018-0127.1 ◽

2019 ◽

Vol 7 (2) ◽

pp. T513-T524 ◽

Cited By ~ 1

Author(s):

Yiqian Qu ◽

Wei Sun ◽

Song Guo ◽

Shuai Shao ◽

Xiuxiang Lv

Keyword(s):

Tarim Basin ◽

Shale Gas ◽

Calculation Model ◽

Influential Factors ◽

Gas Content ◽

Western China ◽

Isothermal Adsorption ◽

Kuqa Depression ◽

Target Layer ◽

Gas Potential

Because shale gas content plays a very important role in the evaluation of gas shale potential, its calculation and prediction become obligatory. We used two predictive models, namely, the Langmuir and Ambrose models, to calculate the shale gas content. The parameters involved in these two models are calculated by various experiments and analytic methods, including indirect prediction, the isothermal adsorption test, X-ray diffraction analysis, total organic carbon (TOC) measurement, pyrolysis, and porosity measurement. Then, a new calculation model that is applicable to shales in the Kuqa Depression, Tarim Basin, is established. Further research on influential factors of gas content in well YN2 is implemented. The result indicates that the gas content of terrestrial shales is more influenced by TOC abundance than by the content of clay minerals and quartz. The main parameters in the new calculation model are the TOC, depth, porosity, and gas saturation. The Jurassic shale gas in well YN2 is speculated to be mainly adsorption gas, with a dominant proportion of 75%–90% in the total gas content. As the formation depth increases, the free-gas content rises continuously, whereas the adsorption gas content first increases and then approaches the equilibrium value or even tends to decrease slightly. Based on the foregoing results, the target layer, the Yengisar Formation, is predicted to possess an enormous amount of shale gas potential, with an average total gas content of [Formula: see text].

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Shale Gas-in-Place Calculation from Sichuan Basin, China

Advanced Materials Research ◽

10.4028/www.scientific.net/amr.803.342 ◽

2013 ◽

Vol 803 ◽

pp. 342-346

Author(s):

Hua Qing Xue ◽

Hong Ling Liu ◽

Gang Yan ◽

Wei Guo

Keyword(s):

Shale Gas ◽

Sichuan Basin ◽

Water Saturation ◽

Organic Content ◽

Gas Content ◽

High Porosity ◽

Formation Pressure ◽

Free Gas ◽

Gas Accumulation ◽

Content Measurement

The methods of shale gas content measurement and shale Gas-in-place calculation are introduced in detail. The shale gas content is form 1.05 to 1.84 m3/t. From Gas-in-place calculation the adsorption gas content is a little more than free gas content. The advantage of shale gas accumulation areas are high formation pressure, low water saturation, high porosity and high total organic content. There are some discrepancy between shale gas content testing and gas in place calculation and three reasons may cause this phenomenon.

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Porosity and Water Saturation Estimation for Shale Reservoirs: An Example from Goldwyer Formation Shale, Canning Basin, Western Australia

Energies ◽

10.3390/en13236294 ◽

2020 ◽

Vol 13 (23) ◽

pp. 6294

Author(s):

Muhammad Atif Iqbal ◽

Reza Rezaee

Keyword(s):

Organic Carbon ◽

Total Organic Carbon ◽

Western Australia ◽

Water Saturation ◽

Clay Content ◽

Total Porosity ◽

Gas Content ◽

Accurate Estimation ◽

Canning Basin ◽

Shale Reservoirs

Porosity and water saturation are the most critical and fundamental parameters for accurate estimation of gas content in the shale reservoirs. However, their determination is very challenging due to the direct influence of kerogen and clay content on the logging tools. The porosity and water saturation over or underestimate the reserves if the corrections for kerogen and clay content are not applied. Moreover, it is very difficult to determine the formation water resistivity (Rw) and Archie parameters for shale reservoirs. In this study, the current equations for porosity and water saturation are modified based on kerogen and clay content calibrations. The porosity in shale is composed of kerogen and matrix porosities. The kerogen response for the density porosity log is calibrated based on core-based derived kerogen volume. The kerogen porosity is computed by a mass-balance relation between the original total organic carbon (TOCo) and kerogen maturity derived by the percentage of convertible organic carbon (Cc) and the transformation ratio (TR). Whereas, the water saturation is determined by applying kerogen and shale volume corrections on the Rt. The modified Archie equation is derived to compute the water saturation of the shale reservoir. This equation is independent of Rw and Archie parameters. The introduced porosity and water saturation equations are successfully applied for the Ordovician Goldwyer formation shale from Canning Basin, Western Australia. The results indicate that based on the proposed equations, the total porosity ranges from 5% to 10% and the water saturation ranges from 35% to 80%. Whereas, the porosity and water saturation were overestimated by the conventional equations. The results were well-correlated with the core-based porosity and water saturation. Moreover, it is also revealed that the porosity and water saturation of Goldwyer Formation shale are subjected to the specific rock type with heterogeneity in total organic carbon total clay contents. The introduced porosity and water saturation can be helpful for accurate reserve estimations for shale reservoirs.

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