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Collaborating Authors
Results
Effect of Surface Force on Nanoconfined Shale-Gas Flow in Slit Channels
Gao, Yanling (China University of Petroleum) | Wu, Keliu (China University of Petroleum) | Chen, Zhangxin (University of Calgary and China University of Petroleum) | Li, Jing (University of Calgary and China University of Petroleum) | Li, Qian (PetroChina Southwest Oil & Gasfield Company) | Dong, Xiaohu (China University of Petroleum) | Tian, Weibing (China University of Petroleum) | Liu, Yishan (China University of Petroleum) | Zhu, Qingyuan (China University of Petroleum) | Bi, Jianfei (China University of Petroleum)
Summary A model for gas transport in nanoscale channels in shale-gas reservoirs (SGRs) is proposed using a new effective mean free path (MFP) model, which considers the effects of surface/gas interaction and the geometrical termination of a nanochannel boundary. In addition, the influences of the nanochannel dimension, formation-burial depth, surface type, and gas type on nanoconfined gas flow in slit channels are addressed. The nanoconfined gas-flow behavior is investigated for a wide range of temperature and pressure in this work because of the large prospects of shale gas in deep and ultradeep formations with pressure up to 100โMPa and temperature up to 480โK. The newly developed effective MFP model and the gas-flow-rate model are successfully validated with data from molecular dynamics (MD) simulations and experiments. Results show that the effect of surface force reduces the MFP and gas-flow capacity, which increases with a decreasing pressure, a decreasing channel size, and an increasing temperature; that the nanoconfinement effect has weaker influence on gas-transport capacity as the formation-burial depth increases and greater influence as formation pressure decreases during hydrocarbon production from SGRs; that a surface type affects the gas transport, and the gas-flow capacity in carbon (C) channels (organic channels) is stronger than that in silicon (Si) channels (inorganic channels) with the same size; and that the differences among the transport capacities of nitrogen (N2), argon (Ar), and methane (CH4) are not obvious, while the transport capacities of helium (He) are greatly lower compared with CH4 at both the SGR temperature and the laboratory temperature.
- North America > United States (0.46)
- Asia > China (0.28)
- North America > Canada (0.28)
Upscaled Gas and Water Relative Permeability from Pore and Core Scale Experimental Data Over Hydraulic Fracturing, Flowback and Online Production
Wang, Dongying (China University of Petroleum, East China) | Yao, Jun (University of Calgary) | Chen, Zhangxin (China University of Petroleum, East China) | Song, Wenhui (University of Calgary) | Sun, Hai (China University of Petroleum, East China) | Cai, Mingyu (China University of Petroleum, East China) | Yuan, Bin (China University of Petroleum, East China)
Multiphase fluid flow in shale is known to be affected by micro-scale pore structure, wettability and complex fluid transport mechanisms. Investigation on the gas-water two-phase transport property during hydraulic fracturing, flowback and online production has practical implications in estimating hydraulic fracturing effect and development of shale gas. In this study, an upscaling method is proposed to derive core-scale gas-water two-phase relative permeability from the perspective of multiphase pore-scale simulation results and experimental data. First, inorganic matter (IOM)/organic matter (OM) pore netwok models are established in use of SEM images from Sichuan Basin, China. Gas/water absolute permeability on IOM/OM pore network model is calculated and gas-water two-phase imbibition (hydraulic fracturing) and drainage process (flowback-to-production) in IOM pore network model is simulated through invasion percolation theory. The comprehensive pore-scale gas-water relative permeability is modeled integrating, 1) real gas effect, critical property change, bulk gas flow demarcated by Knudsen number (Kn) in both IOM and OM, gas adsorption and surface diffusion in OM for gas phase; 2) boundary slip length and spatially varying viscosity for water phase; 3) a piston-like displacement during hydraulic fracturing, and a non-piston displacement during flowback-to-production in IOM incorporating corner flow for water and gas flow in the pore center. A core-scale model is generated by stochastically distributing IOM/OM patches and is proved by using our pressure pulse decay experiment data. A novel upscaling method is then proposed to calculate core-scale gas-water relative permeability by assembling pore-scale simulated permeabilities/relative permeability of IOM/OM patches over the 2D core-scale model during hydraulic fracturing and flowback-to-produciton. Next, the upscaling results are compared with analytical model, which exhibits a consistant pattern. Furthermore, the critical value of TOC content and intrinsic permeability ratio of OM to IOM on the variation of upscaled relative permeability is determined during different flow processes.
- Asia > China (0.69)
- North America > United States > Texas (0.68)
- Information Technology > Communications > Networks (0.57)
- Information Technology > Modeling & Simulation (0.35)
An Integrated Numerical Simulation Scheme to Predict Shale Gas Production of a Multi-Fractured Horizontal Well
Zhan, Jie (University of Calgary) | Lu, Jing (The Petroleum Institute) | Fogwill, Allan (Canadian Energy Research Institute) | Ulovich, Ivan (University of Calgary) | Cao, Jili Paul (University of Calgary) | He, Ruijian (University of Calgary) | Chen, Zhangxin (University of Calgary)
Abstract The application of horizontal well drilling coupled with the multistage fracturing technology enables commercial development of shale gas formations. To optimize the shale gas development, the transient gas flow in a shale formation is of great research interest. Due to anano-scale pore radius, the gas flow in shale matrix may fall in flow regimes which include viscous flow, slip flow and Knudsen diffusion. On top of that, gas adsorption/desorption and stress-sensitivity are some other important phenomena in shales. In this paper, we introduce a novel numerical simulation scheme to depict the above phenomena and predict the gas production from a multi-stage fractured horizontal well, which is crucial for the shale gas development. Instead of Darcy's equation, we implement the apparent permeability in the continuity equation to depict the gas flow (viscous flow, slip flow and Knudsen diffusion) in shale matrix. An adsorption/desorption term is included in the continuity equation as an accumulation term. A sink which is based on Peaceman's well model is placed at the center of the fracture cell. Uniform fluid flow from matrix to fractures is assumed. Only viscous flow is considered in the fractures and the permeability of the fractures doesnot change with pressure. The model is validated via comparing with an infinity-conductivity fracture model. Moreover, the lab data of Eagle Ford shale which provides the relationship between matrix permeability and the effective stress is integrated into the two-way coupling geomechanical process to simulate a stress-sensitive shale formation. Furthermore, the Langmuir and BET models will be compared to investigate the detailed adsorption/desorption process. This methodology examines the influence of each mechanism for the transient shale gas flow. Instead of conventional pressure-independent Darcy permeability, the apparent permeability increases with the development of a shale gas reservoir, which leads to higher productivity. With the gas adsorption/desorption, the reservoir pressure is maintained via the supply of released gas from nano-scale pore wall surfaces, which also leads to higher gas production. In addition, it yields a 5% difference for the cumulative production for one yearbetween the Langmuir and BET models. With the consideration of geomechanics, the apparent permeability is decreased due to the compaction of nano-scale pores, which leads to a decrease in productivity. Due to the difference of compaction magnitude for each grid block, geomechanics creates additional heterogeneity for anano-pore network in a shale formation, which we should pay more attention to. A novel methodology is introduced to examine the crucial phenomena in a shale formation, which simultaneously takes into account the influence of flow regimes, gas adsorption/desorption and stresssensitivity. On top of that, the productivity of a multi-stage fractured horizontal well is quantified. We provide an effective way to quantify the above effects for the transient gas flow in shale formations.
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (10 more...)
- Well Completion > Hydraulic Fracturing > Multistage fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
A Novel Integrated Numerical Simulation Scheme for Transient Gas Flow in Shale Matrix
Zhan, Jie (University of Calgary) | Han, Yifu (University of Oklahoma) | Fogwill, Allan (Canadian Energy Research Institute) | Wang, Kongjie (China University of Geosciences) | Hejazi, Hossein (University of Calgary) | He, Ruijian (University of Calgary) | Chen, Zhangxin (University of Calgary)
Abstract The gas flow in shale matrix is of great research interest for optimizing shale gas reservoir development. Due to a nano-scale pore radius, the gas flow in the shale matrix may fall in flow regimes which include viscous flow, slip flow and Knudsen diffusion. On top of that, the adsorbed and free gas is stored in nano-scale organic pores. The gas molecules are attached as a monolayer to pore walls to form a film of gas which is the thickness of the adsorbed layer. When a reservoir is depleted, the attached gas molecules will be released so that the radius of organic pores in which the free gas flows is changeable. Thus a sorption-dependent radius will be introduced to the apparent permeability which represents the flow regimes. Stress sensitivity will also be investigated via a two-way coupling geomechanics process. In this paper, we introduce a novel integrated numerical simulation scheme to quantify the above phenomena which is crucial for the shale gas reservoir development. Instead of Darcy's equation, we implement the sorption-dependent apparent permeability in the continuity equation to depict the gas flow (viscous flow, slip flow and Knudsen diffusion) in shale matrix. The methodology which was developed by Vasina et al. and validated through comparing with molecular simulation will be implemented to determine the thickness of an adsorbed layer at each time step. The Langmuir adsorption/desorption term is included in the continuity equation as an accumulation term. In addition, lab data for a Bakken reservoir which provides a relationship between a matrix pore radius reduction and the effective stress is integrated into the two-way coupling geomechanical process to simulate a stress-sensitive shale formation. This methodology examines the influence of each mechanism for the shale gas flow in the matrix. Overall, the sorption-dependent apparent permeability is smaller than the sorption-independent apparent permeability, which leads to the pressure maintenance for the sorption-dependent apparent permeability case. The sorption-dependent apparent permeability will lead to additional heterogeneity. The apparent permeability near a wellbore is bigger than the one far away from the wellbore, which causes the pressure transmit more easily around the production side. With the consideration of geomechanics, the apparent permeability is decreased due to the compaction of a nano-scale pore radius, which leads to the maintenance of reservoir pressure. Due to the difference of compaction magnitude for each grid block, geomechanics also creates additional heterogeneity for a nano-pore network in shale matrix, which we should pay more attention to. The sorption-dependent radius is incorporated into the apparent permeability model to depict the sorption-dependent apparent permeability of shale matrix. We provide a novel integrated methodology to quantify the crucial transient phenomena in the shale matrix, which includes flow regimes, gas adsorption/desorption and stress sensitivity.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- North America > United States > Texas > Haynesville Shale Formation (0.99)
- North America > United States > Louisiana > Haynesville Shale Formation (0.99)
- North America > United States > Arkansas > Haynesville Shale Formation (0.99)
- (3 more...)
A Model for Real Gas Transfer in Nanopores of Shale Gas Reservoirs
Wu, Keliu (University of Calgary) | Chen, Zhangxin (University of Calgary) | Wang, Heng (University of Wyoming) | Yang, Sheng (University of Calgary) | Li, Xiangfang (China University of Petroleum, Beijing) | Shi, Juntai (China University of Petroleum, Beijing)
Abstract The gas transport in nanopores of shale gas reservoirs is significantly different from that in conventional gas reservoirs. A model for ideal gas in nanopores is derived based on a weighted summation of slip flow and Knudsen diffusion, where ratios of intermolecular collisions and molecular and nanopores wall collisions to total collisions are the weighted factors of slip flow and Knudsen diffusion, respectively. This model is extended to the application of real gas transport in nanopores by taking into account the effects of intermolecular force and gas molecule volume on mass transport under the condition of high pressure. The model is validated by published molecular simulation data. The results show that the model is more reasonable to describe all of the gas transport mechanisms known, including continuous flow, slip flow and transition flow; the degree of real gas effects on gas transport is up to 23%, which is controlled by pressure, temperature, nanopores radius and gas type; and methane transport capacity is underestimated by 65.09% with helium and overestimated by 106.27% with nitrogen in simulation of methane transport in shale nanopores under the condition of laboratory experiments.
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.48)