Formation permeability is one of the most important parameters for reservoir evaluation and optimization. Despite its importance, accurate estimation of continuous permeability is difficult due to its high variability and its dependence on the scale of measurement. To date, there is no generally accepted logging method for evaluating the continuous permeability of a formation. However, recent advances in the NMR logging (CMR* Combinable Magnetic Resonance tool) hold the greatest promise for a generally accepted continuous measurement of formation permeability.

We present comparison of permeability estimates from the CMR tool with the permeability estimates from other sources (i.e., cores, well tests, formation testers, and minipermeameter). Because permeability can vary by several orders of magnitude over short vertical distances and because different sources measure permeability at different scales, it is essential that permeability be properly averaged (arithmetic, harmonic or geometric depending on the type of heterogeneities) before such comparisons are made.

With the help of field examples, we show the utility of permeability esimates from the CMR tool for reservoir engineering applications. Due to the empirical nature of the permeability evaluation from T2 distributions, the absolute value of permeability must be calibrated with other sources of permeability information. However, the variation of permeability in a zone is estimated quite accurately. The continuous record of the variation of permeability in a zone is useful for establishing a completion/stimulation strategy and for establishing optimum reservoir management through reservoir simulation.


Of all the formation parameters that are needed in the evaluation of hydrocarbon resources, permeability, which is a measure of how easily a fluid of certain viscosity flows through the rock under a pressure gradient, is the most important and, at the same time, the most difficult to evaluate. It is vital for establishing producibility, which determines whether a well should be completed and brought on line. The knowledge of the level and distribution of permeability is also essential in reservoir management for choosing the optimal drainage points and production rate, designing perforations, and selecting a stimulation strategy. Permeability of sedimentary rocks has a wide range, from near zero in some shales to 10,000 mD in coarse-grained sandstones. It can also vary greatly within a few inches in the same formation. Permeability of a formation is determined by the complex interaction of a number of variables. During deposition the grain size and the degree of homogeneity of the original particles are primary factors in determining permeability. How densely these particles are arranged, both initially and later during burial, can significantly alter pore diameters and subsequent permeability of the reservoir. Permeability generally increases with porosity, grain size and certain bedding patterns, but these relationships are far from consistent. Some apparently highly permeable rocks are rich in clay that migrates with production and plug pores, diminishing permeability. On the other hand, some relatively impermeable rocks may produce copiously through a network of fractures. In general, permeability increases with the size and interconnectedness of a rock's pores, but unforeseen details are frequently influential and extremely difficult to account for. This makes the estimation of permeability a difficult task under most circumstances.

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