Permeability, a major reservoir property that reservoir engineers strive to measure as accurately as possible, is nevertheless always measured indirectly, by estimation, either through well-testing or specific logging tools and techniques. Permeability measurement utilizing reservoir rock samples does not necessarily guarantee accurate results, as fluid saturation of rock samples may change dramatically due to stresses and pore pressure changes take place during coring and transportation of samples to the laboratory for testing. In attempting to extrapolate fluid flow behavior in the reservoir from such samples, tremendous efforts have been directed up to now towards producing useful meanings of horizontal, vertical and directional permeabilities.
This paper introduces a new permeability measurement approach that brings fresh understanding to reservoir permeability and a truer reflection of fluid flow behavior around producing wells. The traditional use of horizontal, vertical and directional permeabilities to reflect the conductivity of a formation to fluid flow is often misleading. Actually, the flow comes from everywhere in the reservoir and reduces to the wellbore, and in many cases ended at the perforations. The flow pattern takes a shape of a cone where the base is at the boundary and the head is at the wellbore or the perforation opening. This flow pattern produces a conical or "tapering" permeability. This new 3-D permeability term should enhance the accuracy of the models used to represent fluid flow in porous media.
A three-dimensional permeability term is newly introduced here. A three-dimensional spot gas permeameter device and techniques for measuring this term have been constructed in the laboratory. This device is intended to enable direct measurement of gas permeability at any spot on the surface of the sample, regardless of sample shape or size.
The issues of probe sealing and gas slippage have been resolved by introduction of a rubber baker at the tip of the probe, and by allowing low-pressure injection. A new mathematical model has been derived to describe the flow pattern associated with measuring gas permeability using the proposed device. The proposed mathematical model along with numerical solution presented is expected to find application beyond the gas permeameter case, as its usefulness is proven more relevant to reservoir behavior.
With increased application of reservoir simulation and modeling, demand for truer representation and accurate measurement of reservoir data has increased. When it comes to the quality of the input data used in reservoir simulators, petrophysical data measurement is a source of uncertainty and questionable reliability, creating doubts about the credibility of whatever the simulator predicts.
Permeability as the indicator of the ability of the porous media to transmit fluids is considered the most important term in any reservoir flow model. Its measurement usually entails analysis of seismic and well-logging data collected from the area of interest. After drilling, more specific measurements are sought. Retrieved core samples from drilled wells can be tested to evaluate permeability as well as other petrophysical properties. However, such samples undergo different disturbances and alteration, from the time of coring, through the duration of the trip to the surface, as well as from the well site to the laboratory, potentially affecting the samples' otiginal state enough to give rise to misleading results from the simulator.
The idea of measuring reservoir permeability non-destructively in three dimensions is novel, while the model and its numerical solution sufficiently suggestive and appealing that the device being designed for the task holds out serious promise. In the near future it is expected that some initial design shortcomings of the device will be overcome. For the moment, the methodology proposed in this paper represents advance in permeability measurement and calculation.