Novel Method to Calculate Free-Gas-Filled Porosity for Shale-Gas Reservoir and Production Prediction Using Wireline Nuclear Magnetic Resonance: A Case Study in Sichuan Basin, China

Abstract The performance of shale-gas wells varies significantly from well to well, and free-gas volume dominates the initial testing production of shale-gas wells. The uncertainties in pore-pressure estimation will lower the accuracy in quantifying the free-gas-filled porosity of shale-gas reservoirs, which translates into high uncertainties for the overall formation evaluation. Therefore, it is necessary to incorporate other methods independent of pore pressure for the free-gas calculation. In this paper, the authors present a customized shale-gas formation evaluation workflow that integrates core analyses and wireline logging data. The pore fluid of the shale-gas reservoir is a mixture of free gas, adsorbed gas, and water. The hydrogen index and density of the free gas are different from those of adsorbed gas and water. The free gas, adsorbed gas, and water-filled porosities can be quantified when nuclear magnetic resonance (NMR) and triple-combo logs are incorporated, using an iterative method. A robust methodology integrating free-gas ratio (FGR) and other wireline measurements shows great advantage in shale-gas production prediction. Case studies are presented from the shale-gas reservoirs of Taiyang and Daan Blocks in PetroChina's Zhejiang Oilfield. These case studies incorporate wireline-induced gamma ray spectroscopy, NMR, borehole images, dipole sonic measurements, and some special core measurements. The core NMR experiment and ion-milled backscatter scanning electron microscope indicate that the organic pore size ranges from 3 to 42.3 nm, the inorganic pore size ranges from 16.8 to 42.3 nm, and the ratio of organic pores to inorganic pores is about 2.5:1. The quantification of free gas, adsorbed gas, and water-filled porosities proves to be successful. The FGR varies in different wells. It is usually higher than 50% in the reservoir, and it can reach more than 80% in the sweet zone. Wells with high FGR prove to have promising gas production. Wells with abundant fractures and high formation dip angle prove to have low gas production. The core-validated petrophysical properties of lithology, porosity, permeability, total organic carbon content, gas content, water saturation, and triaxial stress magnitudes alleviate the uncertainties in determining the best zones. In this paper, a novel application of core-validated formation evaluation of shale-gas reservoirs is discussed, which helps the operator ascertain the potential for future development. The FGR shows a good match to the gas production. The workflow can be applied to other shale-gas plays in China.