Evidence for a Variable Archie Porosity Exponent “M” and Impact from Saturation Calculations for Mesaverde Tight Gas Sandstones; Piceance, Uinta, Green River, Wind River, and Powder River Basins

Robert M. Cluff¹ and Alan P. Byrnes^2
1The Discovery Group, Inc, Denver, CO
²Kansas Geological Survey, Lawrence, KS

We have measured formation resistivity factors (FRF =Ro/Rw) on a suite of over 300 Mesaverde core plugs at four brine salinities. The samples range from 0.2 to 23.4% porosity at 4000 psi NCS (phi_i); in situ permeability from 2 nD to 206 mD; and brine salinities of 20K, 40K, 80K and 200K ppm NaCl. The Archie porosity (cementation) exponent “m” was calculated from the measured FRF assuming a=1. Our prior unpublished work in the Washakie basin focused on sample sets with porosity > 6% and found only a weak correlation between m and porosity.

Present data show strong curvature where m decreases as a function of porosity below approximately 8% porosity. The relationship can be described by the dual porosity model or equally well by a family of logarithmic equations: m = a ln(phi_i) + b (m standard deviation = 0.13). The zero porosity intercept b increases with salinity from 1.25 (20K ppm) to 1.57 (200K ppm). The coefficient “a” decreases (0.23 to 0.16) with increasing salinity.

The impact of these relationships is that m decreases with decreasing porosity and salinity. At low porosity (<6%) m is significantly less than the nominal constant value of 1.85 commonly assumed for tight gas sandstones. Above 12% porosity, m is best characterized by a constant value of 1.9+0.05. Therefore there is more gas in these rocks at low porosities than a constant m model predicts, but there is little impact on saturation calculations at high porosity.

AAPG Search and Discovery Article #90092©2009 AAPG Rocky Mountain Section, July 9-11, 2008, Denver, Colorado