The response of NMR in the unconventional gas play in the Beluga formation of the Cook Inlet basin at Ninilchik Gas Field does not match the conventional predicted pressure and temperature model, because the zones are at a relatively shallow depth of 1500 to 3200 vertical feet and the pressure gradient is approximately 0.44 psi/ft. This paper presents insights and results of applications of NMR in these unconventional low-pressure hydrocarbon formations. The integration of NMR with other LWD logs, including density, neutron, and acoustic, showed the need for combined petrophysics and petrofacies interpretation.

NMR measurements exhibited that the free-fluid T2 cutoff was around 110 ms, well above the usual 33 ms for sandstone. Low pressure gas produces an NMR signal that not only is weaker but one that also relaxes faster than it does at high pressure. This is because of reduced hydrogen index and enhanced diffusion effects as pressure reduces.

The crossover of density and NMR porosity curves was used to identify the pay zones. The difference of the porosities is due to the gas hydrogen index effect, resulting in a crossover similar to density and neutron crossover. Unlike neutron, NMR porosity is mineralogy independent. Therefore, it may be more reliable than neutron-density crossover to identify gas. Porosity and gas saturation were computed based on the differences between apparent density porosity and apparent NMR porosity - the density and NMR crossover methodology (DMR).

Density and neutron logs were acquired while drilling and in the presence of dissolved gas trapped in formation porous space. Using the equations summarizing density and NMR porosity log sensitivities, the DMR method was applied to correct for the gas effect. The DMR method, with the help of additional logs such as neutron and density, enhances the understanding of NMR responses on these formation conditions. Once DMR porosity is computed, the free-fluid index can be recomputed to its actual value after gas correction; and gas-corrected permeability can now be estimated from the calibrated Coates-Timur model. Gas-corrected porosity and NMR permeability improved accuracy in determining the actual lithology.

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