A new automated, computer-directed, core measurement system furnishes porosity, air permeability, equivalent non-reactive liquid permeability (Klinkenberg), and Forcheimer (turbulence) factor at programmable, sequential overburden pressures from 500 to 10,000 psi. The system is accurate, precise, and flexible and furnishes enhanced routine core data. Capabilities and limitations of the system are discussed. Data are presented for selected rock types and a graphical technique is proposed to relate the system measured porosity and permeability values to uniaxial strain conditions.
Formations deposited in ancient times were buried under successive layers of sediments, resulting in increasing depth of burial and subsequent compression of the rock pore spaces. Core cutting and retrieval relieves the reservoir formation pressure and removes the weight of the overburden deposits, allowing expansion of the core. Consequently, routinely measured porosity and permeability values are higher than those present in the reservoir. permeability values are higher than those present in the reservoir. Adjustments to routine data have often been made by applying factors developed by simulating reservoir overburden stress conditions on representative but limited suites of cores from the formations of interest. Even then, air permeability data were often measured at low mean pressure in the core sample, resulting in gas slippage and air permeability values that were higher than at reservoir pressures. Corrections for this slippage effect were often applied by using published correlations for uniform sand-stones, and ignored in more heterogeneous carbonates where correlations were not valid. Low permeability formations have focused attention on the importance of both slippage correction and overburden effects.
The new automated, core measurement system offers a first-time capability to routinely and economically measure porosity and permeability at simulated overburden stress porosity and permeability at simulated overburden stress conditions, while simultaneously measuring the gas slippage corrected equivalent liquid permeability as well as the Forcheimer turbulence factor required to predict flow in high-rate wells. When placed in the calibration mode, the system is self-calibrating with self-diagnosis of valve leak problems if present. Core sequencing and movement into a hydrostatic core present. Core sequencing and movement into a hydrostatic core holder, application of up to eight selected sequential overburden pressure measurements, interim data display while testing, pressure measurements, interim data display while testing, calculations and final data presentation are performed automatically while under IBM PC control. Pore volume is directly measured by helium injection into the pore space, while permeability and turbulence factor are determined during permeability and turbulence factor are determined during unsteady-state flow utilizing principles described by Jones.
Gas slippage effects were documented by Klinkenberg, and the effect he observed is illustrated on Fig. 1. Unlike non-reactive liquid flow, where permeability of a rock is a constant, gas permeability is seen to vary linearly with the reciprocal mean pressure in the core. Mean pressure is defined as the average of the up-stream and down-stream pressure of the rock sample during flow. It is analogous to the formation pressure. At increasing mean pressures the gas molecules are forced closer together such that the gas becomes more dense, behaves more like a liquid, and has a lower measured permeability. At infinite mean pressure, the reciprocal of P mean equals zero and the gas is pressure, the reciprocal of P mean equals zero and the gas is visualized as having condensed and as flowing like an equivalent inert liquid.