Print this pagePermeability of Tight Gas Sands from Digital Images
Basin-centered gas deposits are abundant in North America. Recently, such reservoirs have become attractive exploration and development targets because they contain vast domestic deposits of natural fuel. A key property required to plan and optimize production in these reservoirs is permeability. The latter is notoriously difficult to measure in a physical laboratory. The reason is extremely low and often disconnected porosity and the resulting small permeability, often in the nano-Darcy domain. This makes the standard steady-state flow approach virtually impossible to implement and calls for such intricate and lengthy techniques as pulse-decay flow measurement. An alternative to a physical measurement is a digital simulation of fluid flow in a 3D pore space accurately imaged by high-resolution CT scanning.
We present an example of this digital technique for two samples from the Williams Fork formation in Colorado Basin from one well drilled by Occidental Petroleum with the total porosity ranging from 0.01 to 0.10.
The porosity of the first sample was about 0.08. It was dominated by fairly large pores connected by narrow conduits. This pore space was successfully imaged in a micro-CT machine with resolution about 5 microns per voxel. The resulting permeability, as calculated by simulating fluid flow in this sample, was in the 1 to 5 milliDarcy range. The formation factor ranged from 1,000 to 2,000.
The pore space of the second sample was not discernable at this micro-CT resolution. It was consequently imaged in a nano-CT machine with 0.065 microns per voxel resolution. This image revealed a disconnected pore structure with equidimensional pores of approximately 1 micron in size and predominantly located within calcite crystals, presumably due to secondary dissolution of carbonate inclusions. As expected, the permeability was zero. This result makes the second formation an obvious target for hydrofracturing. The permeability of such fractured formation is also predicted in our computational experiments by mathematically placing the cracks of assumed density and aperture inside the digitally imaged sample.
AAPG Search and Discovery Article #90090©2009 AAPG Annual Convention and Exhibition, Denver, Colorado, June 7-10, 2009