Modeling of Transport Phenomena and Multicomponent Sorption for Shale Gas and Coalbed Methane in an Unstructured Grid Simulator

Leahy-Dios, Alana; Das, Mita; Agarwal, Anshul; Kaminsky, R. D.

doi:10.2118/147352-ms

Cited by 54 publications

(28 citation statements)

References 12 publications

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“…In the Appalachian Basin, the well performance from darker zones within Devonian shale with higher organic content is better than that from organic-poor gray zones (Schmoker 1980). Lu et al (1995) showed that the relationship between gas-adsorption capacity and TOC is approximately linear when the TOC is high, whereas for a very low TOC, illite plays an important role in gas storage in Devonian shales. The adsorption process in shale-gas reservoirs is mainly physical adsorption, which means that the adsorption is fully reversible, allowing gas molecules to completely adsorb and desorb, and the interaction force between the solid surface and the adsorbed gas molecules is controlled by the weak van der Waals force.…”

Section: Introductionmentioning

confidence: 99%

Modeling Gas Adsorption in Marcellus Shale With Langmuir and BET Isotherms

2016

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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 gasdesorption 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.

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Section: Introductionmentioning

confidence: 99%

Modeling Gas Adsorption in Marcellus Shale With Langmuir and BET Isotherms

2016

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“…Second, there are also natural fractures in shale, which can play an important role in formation of hydraulic fracture geometry and depletion of the reservoirs. Third, adsorbed gas contributes a significant fraction of total original gas in place (Leahy-Dios et al 2011), although the impact on EUR and production is not well understood. Fourth, the history of drilling horizontal wells in the Eagle Ford shale is relatively short, with first production from these wells in 2008.…”

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confidence: 99%

Assessment of Eagle Ford Shale Oil and Gas Resources

et al. 2013

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The Eagle Ford play in south Texas is currently one of the hottest plays in the United States. In 2012, the average Eagle Ford rig count (269 rigs) was 15% of the total US rig count. Assessment of Eagle Ford oil and gas resources and their associated uncertainties in the early stages is critical for optimal development. The objective of our research was to assess Eagle Ford shale oil and gas reserves, contingent resources, and prospective resources.Probabilistic decline curves using Markov Chain Monte Carlo (MCMC) were used to forecast reserves and resources. The Eagle Ford play from the Sligo Shelf Margin to the San Marcos Arch was divided into 8 different production regions based on geology, fluid type, and well performance. We used the Duong model switching to the Arps model with b = 0.3 at the minimum decline rate to model the linear flow to boundary-dominated flow behavior often observed in shale plays. Cumulative production after 20 years predicted from Monte Carlo simulation combined with reservoir simulation was used as prior information in the Bayesian decline-curve methodology. Probabilistic type decline curves for oil and gas were then generated for all production regions. Individual-well reserves and resources estimates were aggregated probabilistically within each production region and arithmetically between production regions.The total oil reserves and resources range from a P 90 of 5.3 to P 10 of 28.7 billion barrels of oil (BBO), with a P 50 of 11.7 BBO; the total gas reserves and resources range from a P 90 of 53.4 to P 10 of 313.5 trillion cubic feet (TCF), with a P 50 of 121.7 TCF. These reserves and resources estimates are much higher than the U.S. Energy Information Administration's 2011 recoverable resource estimates of 3.35 BBO and 21 TCF. The results of this study provide a critical update of the reserves and resources estimates and their associated uncertainties for the Eagle Ford shale formation of South Texas.

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“…In shale gas reservoirs, the gas adsorbed on organic material surfaces is considered as the main source in the pores (Leathy-Dios et al, 2011). With the pressure decreasing during the gas production, the gas adsorbed on the matrix will release and contribute to the gas production.…”

Section: Gas Adsorption and Desorptionmentioning

confidence: 99%

Numerical simulation of gas and water flow mechanism in hydraulically fractured shale gas reservoirs

Shen

et al. 2016

Journal of Natural Gas Science and Engineering

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a b s t r a c tThe problem of the fracturing water remaining in hydraulically fractured shale gas reservoirs has become one of the major concerns in terms of gas productivity and operating costs. The fracturing water retention is influenced by reservoir properties and production parameters, such as matrix porosity and permeability, fracture porosity and permeability, Langmuir pressure and volume, diffusion coefficient, shut-in time, drawdowns and injection rate. In this study, a horizontal well with six-stage hydraulicfracturing treatment was constructed to understand the water retention and gas production performance in shale gas reservoirs. Gas diffusion, gas adsorption/desorption and Darcy flow as well as non-Darcy flow were considered in this model. The process of water retention and gas production performance was analyzed, and the effects of reservoir and production properties on this problem were performed. The results show that only 34% of the fracturing water can flow back to the surface, most of which remains in shale formations to interfere with gas production. The increasing of matrix porosity, fracture porosity, Langmuir pressure and drawdowns will reduce water retention while water retention in shale matrix will increase with the increasing of matrix permeability and Langmuir volume, and consequently impact gas production. But the trapped water and gas rate increase with the higher fracture permeability. Furthermore, the diffusion coefficient, shut-in time and injection rate do not have a significant effect on water retention and gas productivity. These results can provide insights into a better understanding of gas and water flow in the shale gas reservoirs and the effects of reservoir and production parameters on water retention and gas production.

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Modeling of Transport Phenomena and Multicomponent Sorption for Shale Gas and Coalbed Methane in an Unstructured Grid Simulator

Cited by 54 publications

References 12 publications

Modeling Gas Adsorption in Marcellus Shale With Langmuir and BET Isotherms

Modeling Gas Adsorption in Marcellus Shale With Langmuir and BET Isotherms

Assessment of Eagle Ford Shale Oil and Gas Resources

Numerical simulation of gas and water flow mechanism in hydraulically fractured shale gas reservoirs

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