Magnetic Resonance (NMR) Approach for Permeability Estimation in Carbonate Rocks

Abstract

Complex pore structure in carbonate rocks causes the petrophysical characterization and formation evaluation a challenge. Permeability is one of the main evaluation parameters for determining the potential production of a reservoir because it defines the ability of fluids to flow through rocks. It is not possible to directly measure permeability using a wireline tool; one method to obtain it, however, is from Nuclear Magnetic Resonance (NMR) logs using various models such as Timur-Coates, T2LM (Kenyon) and P-connectivity which are adjusted using laboratory core analysis. Interpretation methods were developed to obtain permeability of the formation from NMR readings. These models relate permeability with other petrophysical properties such as porosity that can be directly estimated using well log information. The NMR models include parameters such as c, m, n and T2,cutoff, that must be calibrated with NMR laboratory analyses because they vary for each formation. In some cases, NMR models must be modified to estimate rock permeability more accurately. This paper presents a workflow to modify the NMR models to determine permeability in carbonate rocks. The correlation between conventional laboratory core analysis and NMR permeability from Timur-Coates and Kenyon models is improved using an adjustment factor applicable for each equation. The adjustment factor can be correlated with petrophysical properties of the rocks such as NMR porosity, the irreducible fluid volume (BVI) and the moveable fluid volume (BVM). The results of calculating NMR permeability in carbonate rocks applying the modified equations to laboratory data and NMR log is also presented. Permeability from formation tests is used to correlate with NMR permeability using log data.

Low-field NMR investigation on interaction of ZnO nanoparticles with reservoir fluids and sandstone rocks for enhanced oil recovery

“…For processing the T 1 distribution data of sandstone cores using Eq. 3, the default value of 10 was employed for C (Coates coefficient: p.u./md 1/4 ) (Trevizan et al 2015). T 1 distributions were utilized in the present study to estimate both the volume of producible fluid (Straley et al 1991) and to show potential wettability alterations in sandstone rocks with certain porosities because T 1 distributions are reflections of porous media saturated with different fluids: low viscous FW versus highly viscous crude oil (Giraldo et al 2013;Dang et al 2013).…”