NERDDP Project 1033 had the primary objective of re-assessing the log analysis methods currently used for gas reserves assessment of the Cooper Basin. These methods include those of Porter (1976), Northcott (1982) and Overton and Hamilton (1986). Variations between these methods and their inherent assumptions have contributed in part to a significant degree of uncertainty in estimates of gas reserves during the past 15 years. However, all of these methods have now been superceded by recent theoretical advances in log analysis, particularly the new water saturation calculation equations based upon the counterion capacity per unit pore volume, Qv (Waxman and Smits, 1968, Waxman and Thomas, 1974, Clavier et al., 1977, 1984). In late 1985 the South Australian Department of Mines and Energy resolved to investigate the applicability of such state-of-the-art log analysis concepts to its gas reserves assessment procedures. Before these new equations could be applied in the Cooper Basin, however, a large amount of special core analysis measurements not previously undertaken on Cooper Basin cores were required to be obtained. In addition, factors allowing a more precise method of determining the cutoffs between productive and non-productive Permian gas reservoirs were required to be recognised. Important conceptual outcomes of the project are as follows: - A porosity reduction factor of 5% between conventional (ambient pressure) and reservoir (overburden pressure) core analyses for the Cooper Basin has been derived. Specifically, this means that the majority of the pre-existing core analyses for the Cooper Basin are over-estimating porosity by approximately 5% (0.5 of a porosity unit). As a consequence, earlier empirical log porosity calculations calibrated by core porosities that were measured at ambient conditions have also yielded porosities over-estimated by 5%. - A new core/log porosity equation has been developed for Cooper Basin gas reservoirs, based on overburden porosity distributions. When compared with existing log analysis equations such as the 'Overton' equation, which tends to overestimate low porosities, this equation shows a big improvement in core to log porosity correlation over the range of porosities typically encountered, particularly at low values where cutoffs between productive and non-productive reservoir are critical to reserves assessment. The equation also provides better determinations of high reservoir porosities from log data. - Laboratory methods for determining cation exchange capacity (CEC) using the wet chemistry method are inappropriate for the Cooper Basin, and will lead to gross overestimates of CEC (by up to 10 times). - By contrast, the multiple salinity method for CEC determination gives reliable results and also provides the additional parameters m and n for use in the Waxman-Smits water saturation (Sw) equation, although it is an expensive and time-consuming technique. - Use of the Simandoux or Indonesian equations for calculating water saturations will give unreliable results as the shale resistivity from an adjacent bed is not indicative of actual shaliness resistivity found within reservoir sands. Further, the shale volume (Vsh) derived from the GR log does not reliably indicate the volume of electrically active clay. The use of the alternative modified Waxman-Smits method, with field or formation-specific average values for CEC, m and n, is here recommended on the basis of the new laboratory data gathered as part of this project, since it yields a realistic comparison with well test results. The current practice of using apparent m values for water saturation calculations dependent on Vsh is incorrect and will result in erroneously low saturation estimates. - A new method for determining pay cutoffs has been developed which uses a sliding GR/porosity cutoff and is based on RFT log-derived permeability instead of conventional core analysis-derived data. Its adoption may extend primary gas reserves down to 6% porosity in fields previously considered tight. However, in the Cooper Basin certain reservoirs with porosities as high as 13% have also been shown to be non-productive when their intercalated shale content is similarly great.