Oil-Base Mud Filtrate and Hydrogen Index Effects on Magnetic Resonance Porosity in Gas Reservoirs

Abstract

Several drilling problems were encountered during the drilling of well A. The problems led to delays in drilling, and possible oil-based mud filtrate invasion in the gas-bearing reservoir sand. The client was unable to secure a license for use of radioactive sources in the determination of the sand porosity and hydrocarbon differentiation. Sourceless logging-while-drilling (LWD) magnetic resonance porosity was a useful substitute for density and neutron porosity. In the absence of oil-based mud filtrate invasion, the expected under-call of the porosity as a result of low hydrogen index (HI) in the gas zone can be easily corrected by modeling HI from reservoir pressure, temperature and gas composition. The Magnetic Resonance Dual Wait Time (DTW) approach takes advantage of Longitudinal Relaxation Time (T1) contrast to solve for hydrocarbon saturation. “In light hydrocarbons, in a water-wetting reservoir, the hydrogen atoms in the hydrocarbon fluid relax slower than the nonmovable and movable water. By using two polarization or wait times (Tw), it is possible to calculate hydrocarbon saturation using magnetic resonance tools” (Thorsen et al., 2008, January 1). Initial interpretation shows that the magnetic resonance-apparent porosity under-calls the true formation porosity. Using formation properties and the gas-specific gravity, predicted HI is 0.59. However, applying an HI of 0.59 to hydrocarbon volume causes a substantial over-estimation of the porosity. Therefore, it is necessary to determine an effective HI correction by correlating the magnetic resonance porosity with density, neutron or acoustic porosity from adjacent offset wells. Using an interpretation of the T2 peak position of the T2 distribution on the magnetic resonance log of the well, the T2 cut-off for irreducible water was shifted from 33ms to 100ms to accommodate the longer relaxing irreducible water component affected by the wettability alteration from water-wet to oil-wet, and an empirically derived HI of 0.8 was used to achieve a match of the magnetic resonance porosity of well A and density porosity of offset well B.

AAPG Datapages/Search and Discovery Article #90332 © 2018 AAPG International Conference and Exhibition, Cape Town, South Africa, November 4-11, 2018