Estimation of in-situ fluid-flow rock properties via expedient numerical simulation for formation-tester measurements
The extension of pressure transient analysis (PTA) from drill stem tests (DST) to probe-type formation-tester operations (pretest) in the 1960s unlocked the potential to estimate fluid-flow rock properties from formation-tester measurements. Unlike DST, pretest operations involve small withdrawn fluid volumes, resulting in small rock volumes investigated by pressure pulsing. Due to these volumetric properties, pretests often only exhibit spherical flow regimes on PTA diagnostic plots. This thesis aims to (a) determine which rock properties are critical to estimate spherical permeability accurately, (b) assess the feasibility of deriving horizontal permeability from pretest pressure measurements, and (c) provide best recommended practices for pretest-derived permeability estimates in formation evaluation. To that end, I implement a three-dimensional, finite-difference single-phase numerical flow simulator to evaluate tool parameters, reservoir petrophysical properties, and reservoir geometry effects on pretest pressure measurements displayed with pressure-time charts or PTA log-log plots. Additionally, I investigate anisotropy effects on pressure transient measurements to verify the feasibility of decomposing spherical permeability into its horizontal and vertical components. The same numerical single-phase flow simulator is used to fit actual field measurements acquired in a siliciclastic sedimentary sequence. Synthetic cases with constant spherical permeability show that anisotropy impacts both flowing and early-time buildup pressure. Permeability estimated from the classical steady-state drawdown equation correlates with the highest-magnitude permeability direction in anisotropic rocks. However, permeability estimated with the steady-state drawdown equation is unreliable to evaluate formation permeability anisotropy because it remains highly sensitive to damaged-zone fluid flow properties. Fluid compressibility effects also overlap with anisotropy effects on early-time buildup pressure, hence biasing permeability anisotropy estimates. Porosity, fluid compressibility, and horizontal boundary locations all affect the onset of the spherical flow regime, leading to uncertainty in spherical permeability estimation. Therefore, numerical fitting of pretest field measurements must consider porosity, reservoir geometry, and fluid compressibility values as interpreted from well logs and available contextual information, leading to several input models and permeability outputs. It is found that pretest-derived horizontal permeability from numerical simulations of field measurements yields values comparable to core-derived permeability. I conclude that the numerical matching of pretest pressure measurements is a reliable and practical option to replace side-wall core operations for in-situ permeability estimation.