Despite the success of gas and oil productions from source rock reservoirs worldwide, the average Estimated Ultimate Recovery remains low: ~6% for shale oil and 25% for shale gas from U.S. EIA. For many of these reservoirs, the light hydrocarbons are stored within pores with size from 1 to 100 nm and varying/mixed wettability. Networks of these pores, together with possible fractures, form the flow paths for light hydrocarbons to flow from the matrix to hydraulic fractures; therefore, to improve and optimize production from source rocks, it is fundamentally important to know the hydrocarbon storage and flow in these nanoporous networks in the source rocks.
The physical behaviors of fluids storage and flow in nano-confined spaces differ from that in the bulk. At nanoscale, fluid behavior is a function of both fluid-fluid interactions, as it is in the bulk, and fluid-pore wall interactions. Capillary and adsorptive forces alter phase boundaries, phase compositions, interfacial tensions, fluid densities, fluid viscosities, and saturation pressures in nanopores. The pore size, shape, and interconnectivity; pore wall roughness, composition, and wettability; and fluid composition and molecular size all play important roles in determine physical behavior of confined fluids.
In this webinar we will review:
Current understanding and research efforts in the nano-confined phase behaviors in source rock reservoirs using various advance technologies including nuclear-magnetic- resonances (NMR), small-angle-neutron-scattering, and isotherm measurement of composite fluids.
Improved method to estimate hydrocarbon-in-place accounting for both adsorption and capillary condensation of multi-component fluids in tight reservoirs
Fluid flow in the matrix of unconventional reservoirs including molecular diffusion of mixed phase fluids
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