History Matching of Multiphase-Flow Formation-Tester Measurements Acquired with Focused-Sampling Probes in Deviated Wells
- Carlos Torres-Verdín (The University of Texas at Austin) | Renzo Angeles (ExxonMobil Upstream Research Company) | Kamy Sepehrnoori (The University of Texas at Austin) | Hani Elshahawi (Shell International E&P)
- Document ID
- Society of Petrophysicists and Well-Log Analysts
- Publication Date
- February 2011
- Document Type
- Journal Paper
- 14 - 31
- 2011. Society of Petrophysics and Well Log Analysts
- 1 in the last 30 days
- 135 since 2007
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Complex tool and rock-formation properties are becoming prevalent in formation-testing operations. As hydrocarbon exploration shifts toward high-cost and high-risk frontiers, it is now common to measure pressures and to acquire fluidsamples in deviated and sidetrack wellbores. At the same time, standard analytical and numerical methods used for the interpretation of formation-tester measurements continue to be based on restricting physical assumptions such as single-phase flo, over-simplistic mud-filtrateinvasion radial profiles,and vertical wellbores. Interpretation of transient focused-sampling measurements acquired in wells drilled with oil-based mud (OBM) is particularly challenging. The combination of miscibility (between mud-filtrateand in-situ oil) and non-standard probe geometry requires more petrophysically reliable interpretation methods than currently available with single-phase analytical techniques.
We describe the successful application of a three-dimensional (3D) multiphase-flowmethod to interpret two fielddata sets acquired with focused-sampling probes in deviated wells. The interpretation method includes the dynamic effects of OBM mud-filtrateinvasion and their corresponding impact on fluidproperties, such as viscosity and density, in the near-wellbore region. Numerical simulations verify the consistency of the measurements and quantify the role played by petrophysical, fluid,and geometrical properties on the time evolution of the measurements. We adjust key petrophysical propertiesinvolved in the simulations to reproduce transient measurements of pressure and GOR acquired with a commercial focused fluid-samplingprobe. In addition, we numerically simulate resistivity logs to infer the spatial distribution of fluidsin the near-borehole region prior to the onset of fluid sampling. Sensitivitystudies further appraise the uncertainty of permeability estimates due to wellbore deviation, OBM filtrate viscosit, and radius of invasion.
The excellent agreement obtained between measured and simulated transient formation-tester measurements reveals key factors for the improved interpretation of focused-sampling probes in OBM environments: we found that irreducible water saturation was influentialto determining the spatial distribution of fluidsaround the wellbore as it affected both the separation of apparent resistivity curves and the early-time portion of pressure transient measurements; simulation results also indicate that the angle of wellbore deviation can bias permeability estimates especially for cases of high-permeability formations as well as for the case of large viscosity contrasts of the fluidsinvolved during invasion; our work confirmsthat numerical simulation and history matching of formation-tester measurements acquired under complex environmental conditions is a reliable procedure to diagnose noise, biases, and inconsistencies in transient measurements otherwise undetectable with standard interpretation methods.
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