Review of gas adsorption in shales for enhanced methane recovery and CO2 storage

Rani, Sneha; Padmanabhan, Eswaran; Prusty, Basanta K.

doi:10.1016/j.petrol.2018.12.081

Cited by 209 publications

(102 citation statements)

References 83 publications

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“…When quartz in shales is biogenic, the TOC content and quartz content tend to be positively correlated, while other shales have an opposite correlation. As for the shales with type III kerogen, many studies have shown that the quartz of them is mainly formed by plants, and there is almost no biological quartz [46,62]. In addition, from Figure 9b it is clear that clay minerals have a positive correlation with the TOC content, and the shale samples with relatively high TOC contents (T-11 and T-12) have relatively large clay contents, which are larger than 70%.…”

Section: Composition Of the Shale Samples With Type III Kerogen Formementioning

confidence: 90%

Nanostructure Effect on Methane Adsorption Capacity of Shale with Type III Kerogen

et al. 2020

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This study focuses on the nanostructure of shale samples with type III kerogen and its effect on methane adsorption capacity. The composition, pore size distribution, and methane adsorption capacities of 12 shale samples were analyzed by using the high-pressure mercury injection experiment, low-temperature N2/CO2 adsorption experiments, and the isothermal methane adsorption experiment. The results show that the total organic carbon (TOC) content of the 12 shale samples ranges from 0.70% to ~35.84%. In shales with type III kerogen, clay minerals and organic matter tend to be deposited simultaneously. When the TOC content is higher than 10%, the clay minerals in these shale samples contribute more than 70% of the total inorganic matter. The CO2 adsorption experimental results show that micropores in shales with type III kerogen are mainly formed in organic matter. However, mesopores and macropores are significantly affected by the contents of clay minerals and quartz. The methane isothermal capacity experimental results show that the Langmuir volume, indicating the maximum methane adsorption capacity, of all the shale samples is between 0.78 cm3/g and 9.26 cm3/g. Moreover, methane is mainly adsorbed in micropores and developed in organic matter, whereas the influence of mesopores and macropores on the methane adsorption capacity of shale with type III kerogen is small. At different stages, the influencing factors of methane adsorption capacity are different. When the TOC content is <1.4% or >4.5%, the methane adsorption capacity is positively correlated with the TOC content. When the TOC content is in the range of 1.4–4.5%, clay minerals have obviously positive effects on the methane adsorption capacity.

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Section: Composition Of the Shale Samples With Type III Kerogen Formementioning

confidence: 90%

Nanostructure Effect on Methane Adsorption Capacity of Shale with Type III Kerogen

et al. 2020

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“…[4] Both of these cases are far removed from the wide pore size distributions, complex wettabilities, unpredictable pore geometries, and complex fluid compositions in shale. Even so, the ease with which longstanding, simplistic adsorption theories, such as Langmuir and BET, can be fit to shale adsorption isotherms has led to their widespread incorporation into shale characterization [9], [3], [10], [11] and reservoir modeling. [12]- [14] However, we prove here that despite the fact that the shapes of shale isotherms are often similar to IUPAC isotherms, the underlying physics are generally not the same.…”

Section: Introductionmentioning

confidence: 99%

Using Capillary Condensation and Evaporation Isotherms to Investigate Confined Fluid Phase Behavior in Shales

et al. 2020

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The abundance of nanopores (pores with diameters between 2 and 100 nm) in shale and ultra-tight reservoirs precludes the use of common pressure-volume-temperature (PVT) analyses on reservoir fluids. The small sizes of the pores cause capillary condensation, which is a nanoconfinement-induced gas-to-liquid phase change, that can occur at pressures more than 50% below the corresponding bulk phase change of the fluid due to strong fluid-pore wall interactions. We quantify this phenomenon by measuring propane isotherms both in a synthetic nanoporous medium and a core from a shale gas reservoir. Comparison of our results in the two porous media indicates the occurrence of capillary condensation in shale rock. At the same time, we observe capillary condensation hysteresis for shale, in which the density of the fluid is significantly lighter during desorption than adsorption. This indicates structural changes to the rock matrix caused by the phase behavior of the confined fluid. We use scanning electron microscopy to corroborate our findings. These results have significant implications for determining the PVT properties, porosity, and permeability of shale and ultra-tight formations for use in reservoir modeling and production estimations.

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“…It is because that the surface free energy of coal decreases when the temperature increases, as a result more CH 4 is released from the micro-pore. A Langmuir equation is often used to describe the methane adsorption content under constant temperature [38][39][40] as:…”

Section: Effects Of Temperature On Methane Adsorption Contentmentioning

confidence: 99%

Mathematical Modeling and Simulation on the Stimulation Interactions in Coalbed Methane Thermal Recovery

Teng

Wang

et al. 2019

Processes

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Heat stimulation of coalbed methane (CBM) reservoirs has remarkable promotion to gas desorption that enhances gas recovery. However, coalbed deformation, methane delivery and heat transport interplay each other during the stimulation process. This paper experimentally validated the evolutions of gas sorption and coal permeability under variable temperature. Then, a completely coupled heat-gas-coal model was theoretically developed and applied to a computational simulation of CBM thermal recovery based on a finite element approach of COMSOL with MATLAB. Modeling and simulation results show that: Although different heat-gas-coal interactions have different effects on CBM recovery, thermal stimulation of coalbed can promote methane production effectively. However, CBM thermal recovery needs a forerunner heating time before the apparent enhancement of production. The modeling and simulation results may improve the current cognitions of CBM thermal recovery.Processes 2019, 7, 526 2 of 16 that the reservoir temperature increases 30 • C in twelve years to finally expand the methane production by 58% compared to the conventional method of direct recovery. Li et al.[12] established a mathematical model before demonstrating the complicated couplings among coalbed, methane and temperature. The model was then applied to a CBM thermal recovery of microwave heating. Research results show that thermal stimulation with microwave expands methane recovery more than 40% due to the deformation induced by gas sorption. Khoshnevis et al. [13] investigated the synergy type of gas production by injecting geothermal water. They established a three-dimension model to discuss the production potential of gas field and the influences of injection rate, reservoir permeability, saturation condition on the ultimate methane production. Lu [14] proposed a numerical simulation of heat injection into a three-dimensional temperature field by ANSYS to evidence the increasing production of CBM with temperature due to the easier desorption with higher temperature. Shahtalebi et al. [15] point out that the costs in coalbed methane thermal production limit the economic effectiveness. Only when the price of natural gas is comparatively higher and the demand for clean energy is stronger, the method of thermal production can become an economically attractive option.CBM thermal recovery benefits a lot from the enhanced gas adsorption behavior [16][17][18]. Sakurovs et al. [19] presented three sets of experimental sorption evolutions at variable temperature. The results show that the methane adsorption capacity has great dependency with coal temperature. The sorption of coal to methane at different temperature ranges may indicate different behaviors, and a traditional Langmuir equation cannot describe the different trends. For example, Guan et al. [20,21] estimated the adsorption isotherms at temperatures from 283 K to 343 K. They find that the adsorption capacity of CBM decreases linearly with increasing temperature at the range of 283 K to 323 K, and keeps...

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Review of gas adsorption in shales for enhanced methane recovery and CO2 storage

Cited by 209 publications

References 83 publications

Nanostructure Effect on Methane Adsorption Capacity of Shale with Type III Kerogen

Nanostructure Effect on Methane Adsorption Capacity of Shale with Type III Kerogen

Using Capillary Condensation and Evaporation Isotherms to Investigate Confined Fluid Phase Behavior in Shales

Mathematical Modeling and Simulation on the Stimulation Interactions in Coalbed Methane Thermal Recovery

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