Summary
Rock-formation permeability is one important flow parameter associated with subsurface production and injection. Its importance is reflected by the numberof available techniques (well-log evaluation, core measurements, and well testing) typically used to estimate it. The literature is full of comparisons and correlations of permeability from these sources. Too often these comparisons and correlations are used to make important conclusions without proper regard to the interrelationships among them. Permeability estimates by individual techniques within the various permeability sources can vary with the state of rock (in-situ environment), fluid saturation distribution, flow direction, and the scale of the medium under investigation. This paper reviewsthe commercially available permeability-estimation techniques and discusses theimportant factors that illustrate their interrelationships. Knowledge ofappropriate interrelationships among the various techniques allows meaningful permeability comparisons and correlations. Usefulness of the interrelationships is demonstrated with field data. Also, the interrelationship concepts presentedare a cornerstone for reservoir flow characterization.
Introduction
Of all the formation parameters that petroleum engineers use, permeability is one of the most important. In the oil and gas industry it is used todetermine whether a well should be completed and brought on line. Permeabilityis also essential in overall reservoir management and development (e.g., forchoosing the optimal drainage points and production rate, optimizing completionand perforation design, and devising EOR patterns and injection conditions). Oil and gas companies use both accurate and approximate permeability values. These values frequently are compared and correlated without much attention tohow each value was determined. Such comparisons and correlations are then usedto make important conclusions about formation flow potential and for variousaspects of reservoir management and development. But establishing a correlation between unstressed core plug permeability and drillstem-testing (DST) permeability and then using the correlation with other unstressed core plugpermeabilities to evaluate the flow potential of other zones, for example, maybe futile unless the scale factor, measurement environment, and physics are adequately considered. The scale factor considers the relative size of thevolumes being investigated and the nature of heterogeneity, and the measurementenvironment and physics consider the state of the rock environment, fluid saturation distribution, flow direction, and sensitivity of the measured or inferred variables that constitute permeability calculations. To address the appropriate correlations among techniques, we first define the various permeabilities that are measured by the permeabilities that are measured by thevarious techniques.
Permeability Definitions Permeability Definitions The classic definition of permeability, as described by Darcy, is the intrinsic characteristic of amaterial that determines how easily a fluid can pass through it. In the petroleum industry, the darcy is the standard unit of measure for permeability. It represents 1 cm3 of fluid with a viscosity of 1 cp flowing through a 1-cm2cross-sectional area of rock in 1 second under a pressure gradient of 1 atm per1 cm of length in the direction of flow. This intrinsic rock property is called absolute permeability when the rock is 100% saturated permeability when therock is 100% saturated with one fluid phase. Permeability is also measured inreference to a fluid phase when the rock is saturated with a multiple-fluidphase. Such a permeability is the effective permeability of the rock to the particular flowing fluid. (The ratio of effective to absolute permeability isthe relative permeability.) These definitions are simple and straight forward when the measurement is performed in the laboratory. when downhole rockpermeability is measured, however, complications arise because of lack ofknowledge about the downhole environment, the volume, and the measurement method. Almost every discipline within the oil industry has its own definition of permeability. This inconsistency creates a significant problem whenpermeability is to be used problem when permeability is to be used to defme theproduction performance of a particular formation, reservoir, or well.particular formation, reservoir, or well. A core analyst's version ofpermeability may be an accurate representation of the 1-in.-diameter,1-in.-long core sample; however, the measured value may have no significantbearing on the production characteristic of the formation represented by the core sample. The core measures absolute permeability, but formation flow isgoverned by relative permeability. Also, core permeabilities permeability. Also, core permeabilities are influenced by the microscopic nature of themeasurement and the environment (absence of in-situ pressure, temperature, and saturation conditions). At times, a combination of these influences may resultin a permeability that corresponds to the well flow performance, but this ismore a coincidence than a planned result. Similar consequences are observedwhen petrophysicists evaluate permeability with log-measured values. Most logmethods, except the repeat-formation-tester (RFTSM) method, measure absolute permeability. Even though the parameters used to infer permeability from logsare measured at in-situ conditions, the complexity of rock structures and inadequate parameterization make the log less than parameterization make thelog less than derived permeability transforms nonuniversal.
JPT
P. 578
