Nuclear-Magnetic-Resonance Response of Brine, Oil, and Methane in Organic-Rich Shales

Summary The application of nuclear-magnetic-resonance (NMR) methods to evaluate the fluid content in hydrocarbon reservoirs requires the understanding of the NMR response of the fluids present in the rock. The presence of multiple fluids such as liquid, gaseous, or adsorbed phases in nanometer-sized pores (associated with various minerals and organic matter) adds another degree of complexity to the interpretation of NMR data in shales. We present a laboratory study on the NMR responses of brine, oil, and methane in shales at 2 MHz. NMR transverse relaxation time (T2) distributions were acquired on core plugs from the Haynesville, Barnett, and Woodford shale formations. The NMR T2 distributions were acquired after brine (2.5% potassium chloride) and oil (dodecane) imbibition and saturation. After brine imbibition, we observed an increase in porosity at T2 ≤ 1 ms. However, after saturation at increasing pressures we observe a porosity increase at T2 ≈ 6–20 ms. Dodecane imbibition and saturation induced a porosity increase at T2 ≈ 10 ms. The measurements with methane were conducted on Haynesville core plugs at a methane pressure of 4,000 psi. The NMR T2 signal of methane in shales appears to be at approximately 10 ms. These results show that the NMR response of methane and oil is very similar in shales. Monitoring the saturation increase with NMR shows that brine can enter the entire pore spectrum, whereas oil and methane have access only to a fraction of the pore space.

USE OF NUCLEAR MAGNETIC RESONANCE AND NEW CORE ANALYSIS TECHNOLOGY FOR DETERMINATION OF GAS SATURATION IN PRETTY HILL SANDSTONE RESERVOIRS, ONSHORE OTWAY BASIN

The failure of conventional log interpretation of low resistivity gas-bearing reservoirs in the Lower Cretaceous Pretty Hill Sandstone, onshore Otway Basin, has led to the use of the saturation versus height, Leverett J function as a basis for predicting hydrocarbon saturation.The recent application of a new method of proprietary core analysis (corEVAL™*) in the 1998 gas discovery well Redman–1, allowed the derivation of a more realistic Leverett J function to water saturation transform for the Pretty Hill Sandstone. Furthermore, this transform could be applied beyond the cored interval to the remaining reservoir section by calibrating the core with its nuclear magnetic resonance response. An algorithm, which converts Schlumberger's combinable magnetic resonance (CMR*) cumulative T2 distributions into a pseudo- capillary pressure curve, has been derived enabling the calculation of gas saturation directly from this log. The CMR derived permeability log also assisted in facies differentiation of the reservoir section and in the selection of wireline pressure and formation fluid sampling points.The combined application of nuclear magnetic resonance technology and proprietary core analysis, independently validated by formation sample and test data, resulted in a 30% increase over previous methods, in average gas saturation in the reservoir being calculated. This has lead to a predicted increase in estimated gas in place at the Redman Field

The effect of tetra-n-butylammonium salts on the nuclear magnetic resonance of nitrobenzene

Tetra-n-butylammonium salts effect the nuclear magnetic resonance response of the para and meta protons of nitrobenzene to a greater extent than that of the ortho protons in solutions in carbon tetra chloride. It is suggested that this effect may be due to a specific interaction between the salt, in ion-pair form, and the aromatic ring of nitrobenzene.