The overall objective of this project is to gain fundamental understanding of the hydrocarbon fluid phase behavior and flow properties in nanoporous shale formations. Hydrocarbon fluids (as well as water) exhibit significantly different behavior in unconventional reservoirs due to nanopore confinement effects and complex, heterogeneous fluid-rock interactions. The traditional, continuum models used for describing fluid behavior and for developing production strategies for conventional reservoirs, are inadequate for shale and other tight formations. Thus, acquiring new knowledge of fluid flow properties and phase behavior in nanoporous media is essential for maximizing the ultimate oil/gas recovery from unconventional reservoirs.
The researchers will employ an integrated experimental and numerical approach to investigate fluid behavior and fluid-solid interactions in nanoporous media. Experimentally, they will characterize the compositions and microstructures of shale core samples (obtained from Chevron — an industrial partner) using a suite of analytical techniques. Small-angle neutron scattering (SANS), combined with custom-designed high-pressure cells, is used to examine in situ the fluid behavior and related changes in nanopores at reservoir pressure (P) – temperature (T) conditions. The Lattice Boltzmann method (LBM) is utilized to develop physics-based relationships among permeability, nanopore structure, and flow conditions informed by experiments.
Los Alamos National Laboratory (LANL), Los Alamos, NM 87545
Although shale oil/gas production in the U.S. has increased exponentially, its low energy recovery (less than 10 percent for oil and 30 percent for gas) is a daunting problem that needs to be solved for continued growth. The fundamental mechanisms underlying the low oil/gas recovery rates lie in gaining a better understanding of the hydrocarbon fluid behavior in shale nanopores. This information is critical for estimating effective permeability of tight rocks, assessing potential for multi-phase flow, and optimizing operational parameters such as well spacing, bottom hole pressures, and pumping rate, to maximize hydrocarbon recovery. Predictive models based on the new knowledge of nanopore hydrocarbon behavior are required to optimize production from unconventional reservoirs.
LANL will integrate experimental characterization and observation with pore-scale modeling in this research. Integration between laboratory measurements and numerical calculations will facilitate the understanding of nanoscale fluid behavior and development of effective predictive relationships that can be ultimately used to design better production approaches. Previous integrated experimental/modeling studies have been scarce and have focused on description of nanopore topologies and connectivities at ambient conditions. This projects integration of SANS measurements with LBM modeling will be first-of-its-kind in examining nanoscale hydrocarbon fluid behavior at relevant reservoir P-T conditions.
This project consists of two phases, each lasting nine months. In Phase 1, LANL characterized the compositions and microstructures of field shale core samples using various analytical techniques, measured shale nanopores and their interactions with fluids (water and hydrocarbon) as a function of P-T using SANS, and simulated single-phase hydrocarbon transport behavior with LBM. In Phase 2, LANL will complete the core sample characterization and hydrostatic pressure SANS data analyses, and characterize the fluid flow behavior in nanoporous shales under in-situ loading conditions with SANS coupled with an oedometer cell designed in Phase 1. LBM modeling will be extended to simulate hydrocarbon phase change and multiphase flow, and integrated with the experiments.
This project will lead to a fundamental understanding of the hydrocarbon fluid phase behavior and flow properties in nanoporous shale formations. In particular, successful completion of both the experimental and modeling tasks on fluid flow studies will provide important insights into the fundamental mechanisms underlying shale matrix diffusion and will ultimately help develop effective strategies for long-term unconventional oil/gas production.
LANL acquired a Wolfcamp core sample (from a depth of 10,500 feet, corresponding to a pressure of 5,200 psi and a temperature of 70 °C) from Chevron and characterized the sample using a variety of analytical methods including quantitative X-ray diffraction, X-ray fluorescence, differential scanning calorimetry/thermogravimetry, and scanning electron microscopy coupled with the focused ion beam technique. The results reveal that the core is made of organic-matter (OM)-rich and OM-lean layers that exhibit different chemical and mineral compositions, and microstructural characteristics.
Using the hydrostatic pressure system and gas-mixing setup, researchers conducted several sets of in-situ high-pressure SANS experiments at pressures up to 20 kpsi using water and methane as the pressure media. Initial data processing has been completed, and further analyses are ongoing.
Researchers performed the first numerical study to calculate the correction factor (ratio of apparent permeability to intrinsic permeability) for complex kerogen nanoporous structures using the lattice Boltzman method. The results show that the correction factor is always greater than one, indicating that the non-Darcy effects play an important role in the gas flow in kerogen nanopores. In addition, the correction factor increases with decreasing pore size, intrinsic permeability, and pressure, which is in good agreement with the nanopore Knudsen correction.
The researchers conducted SANS and ultrasmall-angle neutron scattering (USANS) measurements of a Wolfcamp shale sample (provided by Chevron) and developed/tested an oedometer system for later high-pressure SANS/USANS experiments.
The researchers completed characterization of a Marcellus shale sample using focused ion beam scanning electron microscopy and conducted high-pressure small-angle neutron scattering measurements using our custom-made oedometer system.
The researchers also completed LBM simulations on the effects of fracture density on effective permeability in a shale matrix-fracture system.
The researchers have measured the nanopore size distributions of two samples of Marcellus shale provided by Noble Energy; one has a high total organic carbon (TOC) and the other has a low TOC. The goal of the characterization is to provide a 3D description of the pore structure of these materials that can then be used in a simulation of gas adsorption. The researchers characterized the microstructures and mineralogy of two Marcellus shale samples with different amounts of TOC using focused ion-beam scanning electron microscopy, with an emphasis on characterizing kerogen and inorganic materials, including both pyrite and clays (illite).
Experimentally, the researchers conducted high-pressure SANS experiments on Marcellus shale samples using water as a pressure medium at the National Institute of Standards and Technology Center for Neutron Research (NCNR). These experiments were to address the question of where the water goes in the shale matrix during hydraulic fracturing.
Computationally, the researchers have simulated oil/water two-phase flow in porous media with the same geometry but different oil-wet solid fractions ranging from 0.0 to 1.0, to investigate the effect of wettability heterogeneity on relative permeability of two-phase flow in porous media.
LANL researchers have found that the relative permeabilities of both water and oil phases in fractionally wet porous media (FWPM) exhibit very different characteristics from those in the purely wet porous media. Particularly, the simulations indicate additional flow resistance in FWPM at an intermediate water (oil) saturation. Through detailed analysis, LANL has concluded that this additional flow resistance is mainly caused by the extremely tortuous flow paths.
The researchers have applied a regularized multiple-relaxation-time LBM model to analyze gas flow in a 2-dimensional reconstructed micro-porous medium at the pore scale. The velocity distribution inside the porous structure was analyzed. The effects of the porosity and specific surface area on the rarefied gas flow and apparent permeability were investigated. The simulation results indicate that the gas exhibits different flow behaviors at various pressure conditions and the gas permeability is strongly related to the pressure.
As part of their quantification of gas-water distribution in the Marcellus shale matrix pores, LANL researchers investigated the interactions of methane gas with shale nanopores at high pressures using SANS at NCNR. The sample used was Marcellus shale from the Marcellus Shale Energy and Environment Laboratory (MSEEL) in the form of a wafer cut from the MSEEL core. Results from this investigation suggest that there may exist more hydrocarbon gases than currently estimated without considering the nanopore confinement effect.
LANL researchers previously (as part of their quantification of the effects of nano/meso-scale processes in the Marcellus shale-matrix pores) developed an LBM model for flow in straight nanochannels based on slip length and effective viscosity, which is applicable for both gas and liquid flow. Based on that model, researchers have further taken into account surface diffusion by combining the Maxwell-Stefan approach and Langmuir adsorption theory. These simulations indicate that surface diffusion of adsorbed gas can enhance apparent permeability even at high pressure. To enable the model to simulate hydrocarbon flow in nanopores of shale matrix, LANL researchers extended the boundary treatment to arbitrarily complex geometry and considered interaction forces for various hydrocarbon-organics pairs.
LANL researchers found that the enhancement of permeability due to the nanoscale effect in complex nanoporous media is less significant than in long straight nanochannels, and it is more so for liquid flow than for gas flow. Researchers suspected that this was caused by the bending of streamlines resulting from the tortuosity of porous media (end effect). The end effect may lead to additional flow resistance in complex nanopores. Researchers further investigated the different mechanisms contributing to permeability enhancement in nanopores and found that for gasses, the permeability enhancement is roughly equally caused by viscosity decrease near the solid surface and slip at the solid surface, while it is mainly caused by slip for liquids. Because the end effect mainly affects the slip, it counteracts the permeability enhancement more significantly for water flow than for gas flow in complex nanoporous media.
With Marcellus Shale samples obtained from MSEEL, LANL determined the nano-porosity variation as a function of pressure using highpressure SANS with deuterated methane (CD4) as the pressure medium. With increasing pressure, more methane fills in nanopores and thus the nano-porosity decreases. However, a large portion of the total porosity (~59 percent) is still inaccessible to methane, which suggests that a significant portion of nanopores are either closed or have narrow throats, where the hosted hydrocarbon may not be accounted for in the current estimate of original hydrocarbon in place using traditional methods. In an effort to better characterize the nanoporosity, LANL is currently teaming with Sandia National Laboratory to derive nanopore structures from focused ion beam scanning electron microscopy (FIB-SEM) images of Marcellus shale samples.
LANL determined that the Beskok-Karniadakis (B-K) model could be improved with respect to apparent permeability. The original B-K model overestimates gas flow ability in tight porous media, while the improved model can better predict the gas flow ability. LANL has found that different nanoscale transport mechanisms enhance the gas flow ability (apparent permeability) in different pressure regimes.
Phase 1 – DOE Contribution: $500,000
Phase 2 – DOE Contribution: $500,000
Phase 3 – DOE Contribution: $800,000
Planned Total Funding:
DOE Contribution: $1,800,000