Flow behavior of gas confined in nanoporous shale at high pressure: Real gas effect

Gas-producing wells in the Barnett Formation show a steep decline from initial production rates, even within the first year, and only 12–30% of the estimated gas-in-place is recovered. The underlying causes of these production constraints are not well understood. The rate-limiting step in gas production is likely diffusive transport from matrix storage to the stimulated fracture network. Transport through a porous material such as shale is controlled by both geometry (e.g., pore-size distribution) and topology (e.g., pore connectivity). Through an integrated experimental and theoretical approach, this work finds that the Barnett Formation has sparsely-connected pores. Evidence of low pore connectivity includes the sparse and heterogeneous presence of trace levels of diffusing solutes beyond a few mm from a sample edge, the anomalous behavior of spontaneous water imbibition, the steep decline in edge-accessible porosity observed in tracer concentrations following vacuum saturation, the low (about 0.2–0.4% by volume) level presence of Wood's metal alloy when injected at 600 MPa pressure, and high tortuosity from mercury injection capillary pressure. Results are consistent with an interpretation of pore connectivity based on percolation theory. Low pore connectivity of shale matrix limits its mass-transfer interaction with the stimulated fracture network from hydraulic fracturing, and serves as an important underlying cause for steep declines in gas production rates and a low overall recovery rate.

https://agupubs.onlinelibrary.wiley.com/doi/pdf/10.1002/2015JB012103

Low nanopore connectivity limits gas production in Barnett Formation

A fully coupled multiscale shale deformation-gas transport model for the evaluation of shale gas extraction

Flow in shale nanopores may be vastly different from that in the conventional permeable media. In large pores and fractures, flow is governed by viscosity and pressure-driven. Convection describes the process. Pores in some shale media are in nanometer range. At this scale, continuum flow mechanism may not apply. Knudsen diffusion and hydrodynamic expressions such as the Hagen-Poiseuille equation and their modifications have been used to compute flow in nanopores. Both approaches may have drawbacks and can significantly underestimate molecular flux in nanopores. In this work, we use the dual control volume-grand canonical molecular dynamics simulations to investigate methane flow in carbon nanopores at low and high pressure conditions. Our simulations reveal that methane flow in a slit pore width of 1–4 nm can be more than one order of magnitude greater than that from Knudsen diffusion at low pressure and the Hagen-Poiseuille equation at high pressure. Knudsen diffusion and Hagen-Poiseuille equations do not account for surface adsorption and mobility of the adsorbed molecules, and inhomogeneous fluid density distributions. Mobility of molecules in the adsorbed layers significantly increases molecular flux. Molecular velocity profiles in nanopores deviate significantly from the Navier-Stokes hydrodynamic predictions. Our molecular simulation results are in agreement with the enhanced flow measurements in carbon nanotubes.

Flow of methane in shale nanopores at low and high pressure by molecular dynamics simulations

Nanopores to megafractures: Current challenges and methods for shale gas reservoir and hydraulic fracture characterization

Understanding Shale Gas Flow Behavior Using Numerical Simulation

Shale gas has changed the energy equation around the world, and its impact has been especially profound in the United States. It is now generally agreed that the fabric of shale systems comprise primarily of organic matter, inorganic material and natural fractures. However, the underlying flow mechanisms through these multi-porosity, multi-permeability systems are poorly understood. For instance, debate still exists about the predominant transport mechanism (diffusion, convection and desorption) as well as the flow interactions between organic matter, inorganic matter and fractures. Furthermore balancing the computational burden of precisely modeling the gas transport through the pores versus running full reservoir scale simulation is also contested. To that end, commercial reservoir simulators are developing new shale gas options but some, for expediency, rely on simplification of existing data structures and/or flow mechanisms. We present here the development of a comprehensive multi-mechanistic (desorption, diffusion and convection) multi-porosity (organic materials, inorganic materials and fractures), multi-permeability model that uses experimentally determined shale organic and inorganic material properties to predict shale gas reservoir performance. Our multi-mechanistic model takes into account gas transport due to both pressure-driven convection and concentration-driven diffusion. The model accounts for all the important processes occurring in shale systems, including desorption of multi-component gas from the organics surface, multi-mechanistic organic-inorganic material mass transfer, multi-mechanistic inorganic material-fracture network mass transfer, and production from a hydraulically fractured wellbore. Our results show that Dual-porosity Dual-permeability (DPDP) with Knudsen diffusion is generally adequate to model shale gas reservoir production. By comparing Triple-porosity Dual-permeability (TPDP), DPDP and Single-porosity Single-permeability (SPSP) formulations under similar conditions, we show that Knudsen diffusion is a key mechanism and should not be ignored. We also guide the fractures design by analyzing flow rate limiting steps. This work provides a basis for long-term shale gas production analysis and also helps define value-adding laboratory measurements.

Understanding Shale Gas Production Mechanisms Through Reservoir Simulation

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Understanding Shale Gas Flow Behavior Using Numerical Simulation

Understanding Shale Gas Production Mechanisms Through Reservoir Simulation