Christopher J. Landry

Pore-Scale Lattice Boltzmann Modeling and 4D X-ray Computed Microtomography Imaging of Fracture-Matrix Fluid Transfer

We present sequential X-ray computed microtomography (CMT) images of matrix drainage in a fractured, sintered glass-granule-pack. Sequential (4D) CMT imaging captured the capillary-dominated displacement of the oil-occupied matrix by the surfactant-brine-occupied fracture at the pore scale. The sintered glass-granule-pack was designed to have minimal pore space beyond the resolution of CMT imaging, ensuring that the pore space of the matrix connected to the fracture could be captured in its entirety. This provided an opportunity to validate the increasingly common lattice Boltzmann modeling technique against experimental images at the pore scale. Although the surfactant was found to alter the wettability of the originally weakly oil-wet glass to water-wet, the fracture-matrix fluid transfer is found to be a drainage process, showing minimal counter-current migration of the initial wetting phase (decane). The LB simulations were found to closely match experimental rates of fracture-matrix fluid transfer, and trends in the saturation profiles, but not the irreducible wetting-phase saturation behind the flooding front. The underestimation of the irreducible wetting phase saturation suggests that finer image and lattice resolutions than those reported here may be required for accurate prediction of some macroscale multiphase flow properties, at a sizable computational cost.

Matrix-Fracture Connectivity in Eagle Ford Shale

Despite microto nano-Darcy matrix permeability, shales and mudrocks have become highly productive sources of hydrocarbons owing to advanced horizontal drilling and multi-stage hydraulic fracturing techniques. Production is attributed to an interconnected network of induced fractures that accesses the hydrocarbons stored in the rock matrix. It has been postulated that the induced fracture network results in part from reactivation of natural fractures. Natural fractures in these reservoirs are either lined or completely occluded with mineral cement with little to no connectivity among fracture pores or between the fracture and matrix pores. However, reactivation of natural fractures during hydraulic fracture stimulation may allow the interface between mineralized fracture and matrix to be broken, potentially resulting in increased well performance.

Nanoscale grain boundary channels in fracture cement enhance flow in mudrocks

Hydrocarbon production from mudrock or shale reservoirs typically exceeds estimates based on mudrock laboratory permeability measurements, with the difference attributed to natural fractures. However, natural fractures in these reservoirs are frequently completely cemented and thus assumed not to contribute to flow. We quantify the permeability of nanoscale grain boundary channels with mean apertures of 50–130 nm in otherwise completely cemented natural fractures of the Eagle Ford Formation and estimate their contribution to production. Using scanning electron imaging of grain boundary channel network geometry and a digital rock physics workflow of image reconstruction and direct flow modeling, we estimate cement permeability to be 38–750 nd, higher than reported permeability of Eagle Ford host rock (~2 nd) based on laboratory measurements. Our results suggest that effective fracture-parallel mudrock permeability can exceed laboratory values by upward of 1 order of magnitude in shale reservoirs of high macroscopic cemented fracture volume fraction.

Influence of Numerical Cementation on Multiphase Displacement in Rough Fractures

We present an application of 3D X-ray computed microtomography for studying the influence of numerical cementation on flow in a cement-lined rough-walled fracture. The imaged fracture geometry serves as input for flow modeling using a combination of the level set and the lattice Boltzmann methods to characterize the capillary-dominated fluid displacement properties and the relative permeability of the naturally cemented fracture. We further numerically add cement to the naturally cement-lined fracture to quantify the effect of increasing cement thickness and diminishing aperture on flow properties. Pore space geometric tortuosity and capillary pressure as a function of water saturation both increase with the numerically increased fracture cement thickness. The creation of unevenly distributed apertures and cement contact points during numerical cement growth causes the wetting and non-wetting fluids to impede each other, with no consistent trends in relative permeability with increasing saturation. Tortuosity of wetting and non-wetting fluid phases exhibits none to poor correlation with relative permeability and thus cannot be used to predict it, contrary to previous findings in smoother fractures.

Slip-Flow in Complex Porous Media as Determined by Lattice Boltzmann Modeling

The pores and throats of shales and mudrocks are predominantly found within a range of 1-100 nm, within this size range the flow of gas at reservoir conditions will fall within the slip-flow and early transition-flow regime (0.001 < Kn < 1.0). Currently, the study of slip-flows is, for the most part, limited to simple tube and channel geometries. However, the geometry of mudrock pores is often sponge-like (organic matter) and/or platy (clays). Here we present a local-effective-viscosity multi-relaxation-time lattice Boltzmann model (LEV-MRT-LBM) parameterized for slipand early-transition-flow regimes and adapted here to complex geometries. At the macroscopic-scale the LEVMRT-LBM is parameterized with local effective viscosities at each node to capture the variance of the mean-freepath of gas molecules in a bounded system. The corrected mean-free-path for each lattice node is determined using a three-dimensional wall function adaptable to complex pore geometries. At the microscopic-scale, a combined diffusive bounce-back boundary condition is applied to the pore-walls. The LEV-MRT-LBM is first validated in simple tube geometries, where good agreement is found for Knudsen numbers below 1.0. We then demonstrate the utility of the LEV-MRT-LBM by simulating pure methane flow in digital reconstructions of nanoporous bitumen at reservoir conditions, and compare the results to bulk tube models. We show that the bulk tube models grossly overestimate apparent permeability, and underestimate the increase in apparent permeability with decreasing pressure.