Search

Adsorbed gas is a significant component of shale gas due to the abundant nanopores of organic matter in shales. Methane adsorption behavior on shale matrix is complex considering the geochemical properties, lithology, pore structure and pressure-temperature conditions. In this work, methane adsorption experiments were conducted through a gravimetric method for shale samples at reservoir pressure and temperature conditions. Meanwhile, total organic carbon (TOC), mineral contents and pore structure parameters of samples were measured, respectively. Experimental results show that (1) an excess adsorption phenomenon is obvious at high-pressure and high-temperature conditions; (2)methane adsorption capacity of shale tends to increase with an increase of TOC; (3) lithology and pore structure also affect the methane adsorption capacity of shales, inducing the different adsorption results of two samples with similar TOC; (4) a shale with a large TOC, a low illite content, a large specific area, a large pore volume and a small average diameter would have a strong methane adsorption capacity, nevertheless the effect of TOC is generally dominant. In order to further investigate the methane adsorption behavior on shales, a simplified local density adsorption model considering the cylindrical pore geometry is established, and is regressed and verified by the experimental data. The modeling results indicate that a sample with a large TOC would have a strong fluid-solid interaction energy and a large surface area of methane adsorption. At last, the mechanism of methane adsorption on shales at in-situ conditions is summarized. This work is beneficial for an accurate shale gas reservoir modeling.

Gas slippage phenomenon in single phase gas flow conditions has been extensively investigated. However, only a few researchers have focused on gas slippage in gas/water two-phase flow conditions. Unfortunately, initial water saturation always exists in tight gas reservoirs, and its impact on gas slippage and flow capacity should not be neglected. In this work, gas slippage for single phase and two-phase flows in tight rocks were experimentally investigated, and our results directly demonstrated that gas slip factors increase with an increase in water saturation. But interestingly, the measured values were significantly higher than those predicted by the Klinkenberg idealized model. This finding indicated that the heterogeneous pore-network structure could largely affect the gas/water distribution characteristics, e.g., leading to ‘water blocking’ or ‘gas trapping’ inside actual samples, which further influenced the two-phase gas slippage behaviors. Thus, a heterogeneity coefficient χ was proposed to correct the deviation between actual cases and the Klinkenberg’s ideal model (χ = 0.5 is for the ideal case, and χ ranges from 0.5 to 2.0 for actual tight sandstones), and thus the two-phase gas slippage for actual tight rocks could be well characterized. Besides, the impact of two-phase gas slippage on the relative gas permeability also needs to be paid more attention. Without a correction of gas slippage, the relative permeability for gas flow in a high-pressure reservoir condition would be overestimated, and this error could be up to 20% for our studied samples. Our present work illustrates a better understanding on how water saturation affects gas slippage in a two-phase flow condition, and paves a path for a more accurate evaluation of the gas flow capacity in actual reservoir systems.

The addition of hydrocarbon solvents to the steam injection, known as Solvent-Assisted Thermal Gravity Drainage (SA-SAGD), has recently been proven to be a more energy saving and environmentally friendly method for heavy oil recovery. Nevertheless, the relationship between injection parameters and heavy oil production in conventional SAGD were always introduced to analysis the performance of SA-SAGD, which makes many confusing in the interpretation. In this paper, the heat lost to the cap rock of the reservoir is determined by taking into account not only the chamber-edge velocity, but also the temperature and mass distributions inside the chamber. Besides, by implicitly characterizing the chamber-edge shape and considering heat and solvent diffusion beyond the chamber edge, the oil rate is calculated. Then, the model couples heat and mass balance equations in the whole oil sand dynamically by considering the effect of liquid pool. This comprehensive method enables us to clearly examine the relationship between the Production-Injection Ratio (PIR) and the height of liquid pool. Lastly, the new model is verified by comparing predicted results with that of numerical simulation. The results show that, the oil rate of SA-SAGD is improved by both of the diluting effect of solvent on bitumen viscosity and a more reasonable chamber shape formed by co-injection solvent with steam. In addition, although heat-loss rate of SA-SAGD is generally smaller than that of conventional SAGD, the Steam-Oil Ratio (SOR) of SA-SAGD may even higher than that of SAGD in the late period of the process if the liquid level is extremely high. Moreover, the liquid-pool height for SA-SAGD is more sensitive to the PIR than for SAGD. Accordingly, when the effect of liquid pool on the production is considered, the PIR of SA-SAGD must be selected carefully.

Although many breakthrough efforts have been made in recent years, it is still challenging to gain a clear knowledge of the variation regularities of effective gas/water phase permeability with the pressure depletion. The reasons behind this phenomenon can be attributed to the coexistence of multiple effects and the transition of the flow behavior at different production stages. To date, the fully-coupled model for effective gas/water phase permeability in coal-bed methane (CBM) reservoirs is still lacking and is significantly necessary to be developed. Firstly, the Palmer-Mansoori (PM) model is employed to represent the variation relationship between absolute permeability and pressure. Secondly, after rigorous derivation of the gas–water two phase partial differential equations in coal seams, the relationship between pressure and saturation in infinitesimal coal is obtained, which can be solved through an iterative algorithm. Subsequently, combined with the Corey relative permeability model, the relative gas/water phase permeability can be described as a function of pressure. Finally, coupling the absolute permeability model and relative permeability model, the effective gas/water phase permeability can also be quantified as a function of pressure or saturation. And the reliability and the accuracy of the proposed model is successfully verified through comparisons with experimental data and previous model collected from published literature. Furthermore, on the basis of the proposed semi-analytical model, the effects of critical desorption pressure, gas desorption capacity, stress dependence, and matrix shrinkage on effective permeability are identified. And many implications and direct insights are achieved through the sensitive analysis process. The semi-analytical model, for the first time, incorporates nearly all known mechanisms and can achieve more accurate characterization of effective permeability during the production process. Moreover, due to the concise form and precise feature, the proposed model will serve as a simple, practical and robust tool for the development of CBM reservoirs.

A real gas transport model in shale matrix with fractal structures is established to bridge a pore size distribution and multiple transport mechanisms. This model is well validated with experiments. Results indicate that different pore size distributions lead to various transport efficiencies of shale matrix. A larger fractal dimension of the pore size and a smaller minimum pore size yield higher frequency of occurrence of small pores and a lower free gas transport ratio, which further results in lower transport efficiency. Gas transport efficiency due to pore size distribution parameters (a fractal dimension and a minimum pore size) varies with different porosities and pressures. Increasing fractal dimension and decreasing minimum pore size result in a higher contribution of Knudsen diffusion to the total gas transport. Decreased pressure and increased porosity enhance the sensitivity of gas transport efficiency to a pore size distribution. The relationship between apparent permeability and porosity based on different pore size distributions is also established for industrial application.

Understanding and controlling the gas flow at the nanoscale has tremendous implications in the fields of separation science, catalytic reactions, and energy storage, conversion and extraction. However, the gas flow behavior at the nanoscale is significantly different from that occurring at larger scales. In this work, we focus on a real gas effect, stemming from a strong gas intermolecular interaction force at high pressure and an un-negligible gas molecule volume at the nanoscale, on gas flow through nanoporous shale. An analytical and unified model is developed and validated with the published results of the Lattice-Boltzmann equation and experiments. This unified model covers all gas flow mechanisms, including viscous flow, slip flow and transition flow, and captures the real gas effect, which enhances flow capacity through nanoporous shale. This unified model is a ready-to-use tool for fast and accurately modeling gas flow through nanopores, and provides a basic foundation for numerical simulation and production prediction in shale gas reservoirs.

The thin water film stabilized by disjoining pressure is non-negligible in tight formations which results in significant difference in multiphase flow behavior compared with that in conventional formations. In this work, a pore network model is proposed to simulate two phase flow in tight formations to highlight the contribution of thin water film on multiphase flow. The newly developed pore network model includes the influence of thin water film on fluid configuration, capillary entry pressure, fluid conductance and connectivity during multiphase flow in pore space. Our approach is first validated with the existing pore network model and then the influence of thin water film on two-phase flow is investigated extensively. The results show that the connate water saturation increases and its associated oil relative permeability decreases as the average pore radius decreases. It also suggests that in water-wet systems, the influence of thin water film on both oil and water phases becomes significant when the average pore radius is smaller than 100 nm. Existence of thin water film will increase the proportion of film water and corner water, resulting in an increasement in oil phase relative permeability and a slight decline of water phase relative permeability in tight porous media dominated by angular pores and throats; while in porous media dominated by circular shaped pores and throats, oil and water phase relative permeability are both enhanced due to better connectivity caused by thin water film; at the same time swelling of water film results in lower residue oil saturation and higher end point of water relative permeability. We also found higher water relative permeability when porous media has more irregular pores.

Nanoconfinement effects lead to the anomalous phase behavior of hydrocarbons in nanopores. Besides the capillary pressure, the critical properties’ shift and curvature-dependent effect are found to be wettability-dependent parameters. In this work, we propose novel methods to correlate the macroscopic contact angle to the critical properties’ shift and curvature-dependent effect with an in-depth analysis of the microscopic interactions, including molecule-wall interactions and intermolecular interactions at the liquid-vapor interface. Then, we extend the Peng-Robinson equation of state model to investigate the effects of wettability on the phase behavior and interfacial tension (IFT) of nanoconfined hydrocarbons. Our results show that the nanoconfinement effects are not only dependent on the pore size but also on the wettability of the pore wall. In nonhydrocarbon-wet nanopores, the nanoconfinement effects are limited, and the bubble point pressure (Pb) and IFT are close to the bulk values. In hydrocarbon-wet nanopores, with the pore radius smaller than 50 nm, the nanoconfinement effects become visible and they are further strengthened as the contact angle decreases. The calculated results suggest that under reservoir temperature for Eagle Ford reservoir with the pore size of 10 nm, the suppression of Pb and IFT with completely oil-wet cases are nearly six-fold and ten-fold higher than that of intermediate-wet cases.

The rock wettabilities and water contact angles describing interactions between CO2, CH4, brine and shale formations are of great significance to CO2 sequestration and enhanced gas recovery processes. However, water contact angles on the surfaces of shale organic matter in the atmospheres of CO2 and CH4 under reservoir conditions are not well-understood. In this study, we present an investigation of water/brine contact angles as functions of temperature, pressure, salinity, ion types, and gas contents by molecular dynamics simulations, and compare results with data from literature. It is found that temperature has profound effects on water contact angles below the critical temperature at an intermediate pressure. Meanwhile, water contact angles increase with pressure before reaching 180° at high pressure and the CO2-water-shale organic matter system turns from a neutrally-wet state to a CO2-wet state at the critical pressure of CO2. We also demonstrate that salinity and ion types have minor impacts on the brine contact angles in the CO2-brine-shale system. Only a slight increase in water contact angles is observed with increasing salinity, and an increase in brine contact angles caused by the divalent cations Mg2+ and Ca2+ is larger than that by the monovalent cations Na+ at the same salinity. Additionally, an increase in the CO2 fraction of gas mixtures can increase water contact angles at the same pressure and temperature. The surfaces of shale organic matter have a stronger affinity for CO2 than CH4, which contributes to a higher CO2 adsorption capacity and improves the displacement efficiency of CH4.

A boom in the production of shale gas has recently impacted the world’s energy supply. The hydraulic fracturing technology has been widely used in the development of shale gas reservoirs. Models for accurate reservoir simulation are essential for their economic production. In this paper, a model for shale gas reservoir production is proposed to account for slip flow, Knudsen diffusion, surface diffusion, gas adsorption/desorption, stress dependence of a pore structure, a non-ideal gas effect, and a flow mechanism difference between organic and inorganic content in the shale matrix. This model is implemented in our in-house simulator with a coupled MINC-EDFM approach to study and predict shale gas production behavior. Comprehensive sensitivity studies are performed to analyze the importance of different parameters in shale gas production. These parameters are divided into two categories. The first category includes reservoir data, such as shale matrix porosity, a nanopore radius, an organic/inorganic volume ratio, hydraulic fracture half-length, and fracture spacing. The second category includes parameters relevant to flow mechanisms, such as a non-ideal gas effect, stress dependence, presence of an adsorbed layer as well as a selection of a flow mechanism model. It is found that parameters related to hydraulic fractures impact calculated gas production more than reservoir matrix data. Among the fracturing parameters, hydraulic fracture half-length has a stronger effect than fracture spacing, and among matrix properties, porosity has a larger impact than a nanopore radius or the assumed organic/inorganic content ratio. These results help to optimize a shale gas reservoir production design. In addition, in a synthetic case assuming a 1 nm pore radius, the presence of an adsorbed gas layer has a more tremendous effect compared to the non-ideal gas and stress dependence phenomena. Moreover, the developed simulator with the multiple transport mechanisms can be used to accurately predict shale gas reservoir production. The findings of this study help a better understanding of shale gas flow and can be used to enhance the production of shale gas reservoirs.

A void volume, which is measured by helium expansion tests and used in the calculation of methane adsorption amounts, is always overestimated due to helium adsorption. In this study, by comparing void volumes of carbon nanopores determined under different temperatures and pressures using GCMC (Grand Canonical Monte Carlo) simulation, suitable experimental conditions for helium expansion tests are obtained. Five volumes, including one apparent volume Vapp, three referred volumes Vref and one physical volume Vphy, are recognized. The apparent volume Vapp corresponds to the volume directly determined under traditional experimental conditions, while three referred volumes are determined at 500 K with different pressure ranges (low, moderate, high). The physical volume is calculated by multiplying a pore width and a surface area. Besides, a volume determined by using a helium probe is named an accessible volume Vacc and used as a criterion for a determined volume through mass balance. It is found that use of a void volume determined under traditional experimental conditions or a physical volume leads to negative adsorption amounts at high pressures. Considering an economic effect and measurement accuracy, determining a void volume by helium expansion tests within a moderate pressure range at 500 K is suggested. Excess isotherms of methane calculated by the suggested volume are more appropriate and of great physical meanings for further investigation of adsorption mechanisms.

Unlike conventional gas reservoirs, gas flow in shale reservoirs is a complex and multiscale flow process which has special flow mechanisms. Shale gas reservoirs contain a large fraction of nano pores, which leads to an apparent permeability that is dependent on pore pressure, fluid type, and pore structure. Study of gas flow in nano pores is essential for accurate numerical simulation of shale gas reservoirs. However, no comprehensive study has been conducted pertaining to the gas flow in nano pores. In this paper, experiments for nitrogen flow through nano membranes (with pore throat size: 20 nm, 55 nm, and 100 nm) have been done and analyzed. Obvious discrepancy between apparent permeability and intrinsic permeability has been observed; and the relationship between this discrepancy and pore throat diameter (PTD) has been analyzed. Then, based on the advection-diffusion model, a new mathematical model has been constructed to characterize gas flow in nano pores. A new apparent permeability expression has been derived based on advection and Knudsen diffusion. A comprehensive coefficient for characterizing the flow process was proposed. Simulation results were verified against the experimental data for gas flow through nano membranes and published data. By changing the comprehensive coefficient, we found the best candidate for the case of argon with a membrane PTD of 235 nm. We verified the model using experimental data with different gases (oxygen, argon) and different PTDs (235 nm, 220 nm). The comparison shows that the new model matches the experimental data very closely. Additionally, we compared our results with experimental data, the Knudsen/Hagen–Poiseuille analytical solution, and existing models available in the literature. Results show that the model proposed in this study yielded a more reliable solution. Shale gas simulations, in which gas flowing in nano pores plays a critical role, can be made more accurate and reliable based on the results of this work.