AAPG ANNUAL CONFERENCE AND EXHIBITION
Making the Next Giant Leap in Geosciences
April 10-13, 2011, Houston, Texas, USA
Innovative Methods for Flow Unit and Pore Structure Analysis in a Tight Gas Reservoir, Montney Formation, NE BC
(1) Department of Geoscience, University of Calgary, Calgary, AB, Canada.
(2) Department of Chemical and Petroleum Engineering, University of Calgary, Calgary, AB, Canada.
Tight gas reservoirs are notoriously difficult to characterize using laboratory-based methods because of: the existence of heterogeneity at several scales; fine pore structure that may not correlate to depositional controls and environment due to the impact of diagenesis; stress sensitivity of porosity and permeability; sensitivity of permeability to fluid saturation; and non-Darcy flow effects under laboratory conditions, etc. Porosity, pore size distribution and permeability are correspondingly difficult to measure in the laboratory and upscale to reservoir scale. A promising technique to characterize flow heterogeneity in tight gas reservoirs is to relate permeability to dominant pore throat size; permeability is measured using steady- or non-steady-state techniques and dominant pore size is typically estimated using the mercury intrusion method. Permeability and porosity is measured on full-diameter core or core plugs which may contain heterogeneities that are at a much finer scale than the sample size, resulting in composite estimates of both properties.
We investigate the use of non-routine methods to characterize permeability heterogeneity and pore structure of a tight gas reservoir for use in flow unit identification. Profile permeability is used to characterize fine-scale (< 1 inch) vertical heterogeneity in a tight gas core; over 500 measurements were made. Profile permeability, while useful for characterizing heterogeneity, will not provide in-situ estimates of permeability; further the scale of measurement is much smaller than log-scale. Pulse-decay permeability measurements collected on coreplugs under confining pressure were used to correct the profile permeability measurements to in-situ and point averages of profile permeability were used to relate to log-derived porosity measurements. Finally, a new method (for tight gas) was used to estimate the pore size distribution of several tight gas samples: N2 adsorption. A uni- or bi-modal distribution was observed for the samples, with the larger peak corresponding to the dominant pore throat radius, as inferred from the rp35 calculations. Further, the adsorption-desorption hysteresis loop was used to interpret the dominant pore shape as slot-shaped pores, which is typical of many tight gas reservoirs. The N2 adsorption method provides for rapid analysis and does not suffer from some of the same limitations of Hg-injection, however the method is limited to fine pore structures (< 1000 nm).