scholarly journals Molecular Investigation on the Displacement Characteristics of CH4 by CO2, N2 and Their Mixture in a Composite Shale Model

Energies ◽  
2020 ◽  
Vol 14 (1) ◽  
pp. 2
Author(s):  
Liang Gong ◽  
Yuan Zhang ◽  
Na Li ◽  
Ze-Kai Gu ◽  
Bin Ding ◽  
...  
Keyword(s):  
Energy Consumption ◽  
Shale Gas ◽  
Injection Pressure ◽  
Gas Production ◽  
Formation Temperature ◽  
Displacement Efficiency ◽  
Gas Recovery ◽  
Displacement Capacity ◽  
Molecular Investigation ◽  
Shale Reservoirs

The rapid growth in energy consumption and environmental pollution have greatly stimulated the exploration and utilization of shale gas. The injection of gases such as CO2, N2, and their mixture is currently regarded as one of the most effective ways to enhance gas recovery from shale reservoirs. In this study, molecular simulations were conducted on a kaolinite–kerogen IID composite shale matrix to explore the displacement characteristics of CH4 using different injection gases, including CO2, N2, and their mixture. The results show that when the injection pressure was lower than 10 MPa, increasing the injection pressure improved the displacement capacity of CH4 by CO2. Correspondingly, an increase of formation temperature also increased the displacement efficiency of CH4, but an increase of pore size slightly increased this displacement efficiency. Moreover, it was found that when the proportion of CO2 and N2 was 1:1, the displacement efficiency of CH4 was the highest, which proved that the simultaneous injection of CO2 and N2 had a synergistic effect on shale gas production. The results of this paper will provide guidance and reference for the displacement exploitation of shale gas by injection gases.

scholarly journals Performance Evaluation of CO2 Huff-n-Puff Gas Injection in Shale Gas Condensate Reservoirs

Energies ◽  
2018 ◽  
Vol 12 (1) ◽  
pp. 42 ◽  
Author(s):  
Xingbang Meng ◽  
Zhan Meng ◽  
Jixiang Ma ◽  
Tengfei Wang
Keyword(s):  
Oil Recovery ◽  
Shale Gas ◽  
Injection Pressure ◽  
Gas Condensate ◽  
Dew Point ◽  
Gas Condensate Reservoirs ◽  
Gas Recovery ◽  
Point Pressure ◽  
Shale Reservoirs ◽  
Dew Point Pressure

When the reservoir pressure is decreased lower than the dew point pressure in shale gas condensate reservoirs, condensate would be formed in the formation. Condensate accumulation severely reduces the commercial production of shale gas condensate reservoirs. Seeking ways to mitigate condensate in the formation and enhance both condensate and gas recovery in shale reservoirs has important significance. Very few related studies have been done. In this paper, both experimental and numerical studies were conducted to evaluate the performance of CO2 huff-n-puff to enhance the condensate recovery in shale reservoirs. Experimentally, CO2 huff-n-puff tests on shale core were conducted. A theoretical field scale simulation model was constructed. The effects of injection pressure, injection time, and soaking time on the efficiency of CO2 huff-n-puff were examined. Experimental results indicate that condensate recovery was enhanced to 30.36% after 5 cycles of CO2 huff-n-puff. In addition, simulation results indicate that the injection period and injection pressure should be optimized to ensure that the pressure of the main condensate region remains higher than the dew point pressure. The soaking process should be determined based on the injection pressure. This work may shed light on a better understanding of the CO2 huff-n-puff- enhanced oil recovery (EOR) strategy in shale gas condensate reservoirs.

scholarly journals Numerical Simulation of Gas Production from Gas Shale Reservoirs—Influence of Gas Sorption Hysteresis

Energies ◽  
2019 ◽  
Vol 12 (18) ◽  
pp. 3405 ◽  
Author(s):  
Jamiu M. Ekundayo ◽  
Reza Rezaee
Keyword(s):  
Adsorption Isotherms ◽  
Shale Gas ◽  
Computer Modelling ◽  
Three Dimensional ◽  
Gas Production ◽  
Gas Sorption ◽  
Gas Desorption ◽  
Dual Porosity Model ◽  
Desorption Isotherms ◽  
Shale Reservoirs

The true contribution of gas desorption to shale gas production is often overshadowed by the use of adsorption isotherms for desorbed gas calculations on the assumption that both processes are identical under high pressure, high temperature conditions. In this study, three shale samples were used to study the adsorption and desorption isotherms of methane at a temperature of 80 °C, using volumetric method. The resulting isotherms were modeled using the Langmuir model, following the conversion of measured excess amounts to absolute values. All three samples exhibited significant hysteresis between the sorption processes and the desorption isotherms gave lower Langmuir parameters than the corresponding adsorption isotherms. Langmuir volume showed positive correlation with total organic carbon (TOC) content for both sorption processes. A compositional three-dimensional (3D), dual-porosity model was then developed in GEM® (a product of the Computer Modelling Group (CMG) Ltd., Calgary, AB, Canada) to test the effect of the observed hysteresis on shale gas production. For each sample, a base scenario, corresponding to a “no-sorption” case was compared against two other cases; one with adsorption Langmuir parameters (adsorption case) and the other with desorption Langmuir parameters (desorption case). The simulation results showed that while gas production can be significantly under-predicted if gas sorption is not considered, the use of adsorption isotherms in lieu of desorption can lead to over-prediction of gas production performances.

Molecular Simulation of Methane Sorption onto Kerogen Surface of Shale in Presence of Surfactant

2021 ◽  
Author(s):  
Hesham Abduelah ◽  
Berihun Mamo Negash ◽  
Keong Boon Kim ◽  
Eswaran Padmanabhan ◽  
Muhammad Arif ◽  
...  
Keyword(s):  
Molecular Model ◽  
Pore Space ◽  
Gas Production ◽  
Ammonium Bromide ◽  
Sorption Behavior ◽  
Displacement Efficiency ◽  
Methane Sorption ◽  
Shale Reservoirs ◽  
Hydrocarbon Storage ◽  
Cetyl Trimethyl Ammonium

Abstract Shale reservoirs, despite having abundance in hydrocarbon storage, offer significant challenges in terms of understanding the pore-scale and reservoir-scale phenomenon. Typically, hydraulic fracturing treatment is implemented to improve hydrocarbon productivity through the injection of fracturing fluid to induce the breakdown of the formation to create fractures, hence allowing a flow conduit for hydrocarbon to be produced at a higher flow rate of oil and/or gas. In this work, molecular dynamics (MD) simulation using GROMACS were utilized to create a 3D model comprised of methane (CH4), surfactant and graphite. Surfactant, as represented by the cationic cetyl trimethyl ammonium bromide (CTAB) was added along with water to represent water-based visco-elastic surfactant (VES) as an additive to reduce the surface tension of hydrocarbon to shale (represented by graphene). A realistic molecular model was created to examine the interaction of CTAB towards the adsorption pattern of methane onto graphene, in order to reveal the displacement efficiency of methane after wettability modification due to the effect of surfactant on the graphene on a nanoscale. The findings suggest that addition of CTAB as surfactant may enhance the production of methane though the reduction of IFT and adsorption capability of methane to the wall of shale. The result yielded consistent trends, where methane's tendency to stick to the adsorption site (at approximately 1.5 nm from the center of the system) was reduced and more methane molecules were accumulated at the center of the pore space. This study has uncovered the adsorption process and the effect of CTAB in altering the sorption behavior of methane towards shale. This would contribute to the enhancement of long-term shale gas production by providing more information on salinity and pressure sensitivity, enabling extraction to be done at a lower cost.

Numerical Simulation of Shale Gas Production

2011 ◽  
Vol 402 ◽  
pp. 804-807 ◽  
Author(s):  
Song Ru Mu ◽  
Shi Cheng Zhang
Keyword(s):  
Shale Gas ◽  
Simulation Models ◽  
Fracture Network ◽  
Gas Production ◽  
Wire Mesh ◽  
Well Performance ◽  
Gas Reservoirs ◽  
Shale Gas Reservoirs ◽  
Shale Reservoirs ◽  
Fracture Mapping

Shale gas reservoirs require a large fracture network to maximize well performance. Microseismic fracture mapping has shown that large fracture networks can be generated in many shale reservoirs. The application of microseismic fracture mapping measurements requires estimation of the structure of the complex hydraulic fracture or the volume of the reservoir that has been stimulated by the fracture treatment. There are three primary approaches used to incorporate microseismic measurements into reservoir simulation models: discrete modeling of the complex fracture network, wire-mesh model, and dual porosity model. This paper discuss the different simulation model, the results provided insights into effective stimulation designs and flow mechanism for shale gas reservoirs.

Probabilistic Estimation of Shale Gas Reserves Implementing Fast Marching Method and Monte Carlo Simulation

2016 ◽  
Author(s):  
Jaejun Kim ◽  
Joe M. Kang ◽  
Yongjun Park ◽  
Seojin Lim ◽  
Changhyup Park ◽  
...  
Keyword(s):  
Monte Carlo Simulation ◽  
Monte Carlo ◽  
Shale Gas ◽  
Computing Time ◽  
Gas Production ◽  
Full Scale ◽  
Fast Marching Method ◽  
Fast Marching ◽  
Gas Recovery ◽  
Marching Method

This paper evaluates the estimated ultimate recovery for 10-year operation at a shale gas reservoir, implementing FMM (Fast Marching Method) as a surrogate model of full-scale numerical simulation and Monte Carlo simulation as a tool for accessing the uncertainty of FMM-based proxy parameters. Sensitivity analysis shows the significant properties affecting the gas recovery that are enhanced permeability, matrix permeability, and porosity in sequence. Using the statistical distributions of these parameters, this study determines P10, P50, and P90 of the 10-year cumulative gas production and compares them with the values from full-physics simulations. The computing time based on the proxy model is much smaller than that of the full-scale simulations while the prediction accuracy is acceptable. FMM can forecast the production profiles reliably without time-consuming simulation and the integration of Monte-Carlo simulation is able to evaluate the uncertainty of gas recovery, quantitatively.

Study of Temperature Effects on Economic Performance of CO2 Enhanced Shale Gas Recovery

2019 ◽  
Vol 142 (3) ◽  
Author(s):  
Hao Sui ◽  
Peng Pei ◽  
Qian Su ◽  
Weige Ding ◽  
Ruiyong Mao
Keyword(s):  
Shale Gas ◽  
Economic Performance ◽  
Gas Adsorption ◽  
Injection Pressure ◽  
Cost Component ◽  
Gas Recovery ◽  
Operation Temperature ◽  
Production Ratio ◽  
Potential Market ◽  
Study Results

Abstract CO2 displacement has been proposed to enhance shale gas recovery and unlock a big potential market for CO2 beneficial utilization. Theoretically, gas adsorption is inversely related to the temperature, so gas can be desorbed by elevating the temperature. This paper investigates the economic performance of enhancing shale gas recovery by injecting CO2 at high temperatures through displacement as well as desorption by rising temperatures. Influences of operation temperature and injection pressure were studied for three potential shale plays in China. Study results show that both factors exerted obvious impacts, and CO2 procurement was the largest cost component. It is found that the net revenue was not always proportional to the operation temperature, but more controlled by the injection–production ratio. This is because of the different temperature impacts to the various patterns of adsorbed CH4 and CO2 contents. Consequently, in some cases, more CO2 is needed to displace CH4 when operation temperature is raised, resulting a higher cost. The modeling results demonstrate that based on the adsorption characters of reservoirs, the productivity and profitability of CO2 enhanced gas recovery can be further improved by choosing appropriate operation temperatures.

scholarly journals Regeneration of unconventional natural gas by methanogens co-existing with sulfate-reducing prokaryotes in deep shale wells in China

2020 ◽  
Vol 10 (1) ◽  
Author(s):  
Yimeng Zhang ◽  
Zhisheng Yu ◽  
Yiming Zhang ◽  
Hongxun Zhang
Keyword(s):  
Natural Gas ◽  
Produced Water ◽  
Gas Production ◽  
Biogenic Methane ◽  
Sulfate Reducing ◽  
Gas Recovery ◽  
Stable Isotopic ◽  
Unconventional Natural Gas ◽  
Acetoclastic Methanogenesis ◽  
Shale Reservoirs

Abstract Biogenic methane in shallow shale reservoirs has been proven to contribute to economic recovery of unconventional natural gas. However, whether the microbes inhabiting the deeper shale reservoirs at an average depth of 4.1 km and even co-occurring with sulfate-reducing prokaryote (SRP) have the potential to produce biomethane is still unclear. Stable isotopic technique with culture-dependent and independent approaches were employed to investigate the microbial and functional diversity related to methanogenic pathways and explore the relationship between SRP and methanogens in the shales in the Sichuan Basin, China. Although stable isotopic ratios of the gas implied a thermogenic origin for methane, the decreased trend of stable carbon and hydrogen isotope value provided clues for increasing microbial activities along with sustained gas production in these wells. These deep shale-gas wells harbored high abundance of methanogens (17.2%) with ability of utilizing various substrates for methanogenesis, which co-existed with SRP (6.7%). All genes required for performing methylotrophic, hydrogenotrophic and acetoclastic methanogenesis were present. Methane production experiments of produced water, with and without additional available substrates for methanogens, further confirmed biomethane production via all three methanogenic pathways. Statistical analysis and incubation tests revealed the partnership between SRP and methanogens under in situ sulfate concentration (~ 9 mg/L). These results suggest that biomethane could be produced with more flexible stimulation strategies for unconventional natural gas recovery even at the higher depths and at the presence of SRP.

scholarly journals Study on Competitive Adsorption and Displacing Properties of CO2 Enhanced Shale Gas Recovery: Advances and Challenges

Geofluids ◽  
2020 ◽  
Vol 2020 ◽  
pp. 1-15
Author(s):  
Shuyang Liu ◽  
Baojiang Sun ◽  
Jianchun Xu ◽  
Hangyu Li ◽  
Xiaopu Wang
Keyword(s):  
Shale Gas ◽  
Adsorption Mechanism ◽  
Competitive Adsorption ◽  
Gas Adsorption ◽  
Organic Matter Content ◽  
Gas Production ◽  
Gas Recovery ◽  
Model Studies ◽  
Displacement Experiments ◽  
Adsorption Of Co2

CO2 enhanced shale gas recovery (CO2-ESGR) draws worldwide attentions in recent years with having significant environmental benefit of CO2 geological storage and economic benefit of shale gas production. This paper is aimed at reviewing the state of experiment and model studies on gas adsorption, competitive adsorption of CO2/CH4, and displacement of CO2-CH4 in shale in the process of CO2-ESGR and pointing out the related challenges and opportunities. Gas adsorption mechanism in shale, influencing factors (organic matter content, kerogen type, thermal maturity, inorganic compositions, moisture, and micro/nano-scale pore), and adsorption models are described in this work. The competitive adsorption mechanisms are qualitatively ascertained by analysis of unique molecular and supercritical properties of CO2 and the interaction of CO2 with shale matrix. Shale matrix shows a stronger affinity with CO2, and thus, adsorption capacity of CO2 is larger than that of CH4 even with the coexistence of CO2-CH4 mixture. Displacement experiments of CO2-CH4 in shale proved that shale gas recovery is enhanced by the competitive adsorption of CO2 to CH4. Although the competitive adsorption mechanism is preliminary revealed, some challenges still exist. Competitive adsorption behavior is not fully understood in the coexistence of CO2 and CH4 components, and more experiment and model studies on adsorption of CO2-CH4 mixtures need to be conducted under field conditions. Coupling of competitive adsorption with displacing flow is key factor for CO2-ESGR but not comprehensively studied. More displacement experiments of CO2-CH4 in shale are required for revealing the mechanism of flow and transport of gas in CO2-ESGR.

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