Validation of a Workflow for Digitally Measuring Relative Permeability
- Gary R. Jerauld (BP) | Joanne Fredrich (BP) | Nathan Lane (BP) | Qiang Sheng (BP) | Bernd Crouse (Exa) | David M. Freed (Exa) | Andrew Fager (Exa) | Rui Xu (Exa)
- Document ID
- Society of Petroleum Engineers
- Abu Dhabi International Petroleum Exhibition & Conference, 13-16 November , Abu Dhabi, UAE
- Publication Date
- Document Type
- Conference Paper
- 2017. Society of Petroleum Engineers
- 1.6.9 Coring, Fishing, 5 Reservoir Desciption & Dynamics, 5.5.2 Core Analysis, 5.5 Reservoir Simulation, 5.3.4 Reduction of Residual Oil Saturation, 1.6 Drilling Operations, 3 Production and Well Operations
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This paper provides a validation of a Digital Rocks workflow for computing relative permeability from micro-CT images of rock using Lattice Boltzmann simulation. The workflow has the potential to dramatically reduce the time and cost of measuring relative permeability by experimental techniques. Additionally, this workflow utilizes smaller volumes of rock than traditional laboratory techniques enabling the possibility of using side-wall cores and a further reduction in costs by avoiding costly coring operations.
The approach taken is to construct computational grids from segmented micro-CT images to define the pore space available for fluid flow, to run two-phase Lattice Boltzmann simulations, and derive relative permeability from the computed flow fields. Strategies for simulating both steady-state method and unsteady-state method relative permeability protocols are discussed. Five distinct stages of validation are described beginning with idealized 2-phase benchmark studies, progressing to physical micromodel experiments with a range of wettabilities, physical flow experiments in 3D grain packs with differing wettabilities, trapped gas measurement on sandstones with demonstrated dependence of trapped gas on pore structure, and finally corefloods on reservoir rocks.
The simulations quantitatively reproduce the displacement fronts and residual fluids distributions seen in physical experiments, and observed relative permeability behavior in coreflood experiments. Simulations of 2½-D micromodels reproduce the experimentally observed invading water front shape along with quantitatively matching residual oil saturation for the full range of wettabilities modelled; from water-wet to oil-wet. Importantly, simulations accurately capture the enhanced sensitivity of residual oil to intermediate wettability exhibited in the micromodel experiments. Residual oil trends for a range of 3D sandpacks of controlled wettability are predicted by simulation. The dependence of trapped gas on pore structure for Fontainebleau sandstone is reproduced quantitatively. And finally, simulations of relative permeability for reservoir rock for a range of plausible wettabilities are shown to be consistent with the results of laboratory measured relative permeability for reservoir rock from the same plug.
|File Size||3 MB||Number of Pages||20|
Fredrich, J.T., Lakshtanov, D.L., Lane, N.M., Liu, E.B., Natarajan, C.S., Ni, D.M. and Toms, J.J., 2014, October. Digital rocks: Developing an emerging technology through to a proven capability deployed in the business. In SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers.