Limits of 2D NMR Interpretation Techniques to Quantify Pore Size, Wettability, and Fluid Type: A Numerical Sensitivity Study
- Emmanuel Toumelin (Chevron Corp.) | Carlos Torres-Verdin (U. of Texas Austin) | Boqin Sun (Chevron Corp.) | Keh-Jim Dunn (Chevron Corp.)
- Document ID
- Society of Petroleum Engineers
- SPE Journal
- Publication Date
- September 2006
- Document Type
- Journal Paper
- 354 - 363
- 2006. Society of Petroleum Engineers
- 4.1.5 Processing Equipment, 5.1 Reservoir Characterisation, 5.2.2 Fluid Modeling, Equations of State, 4.1.2 Separation and Treating, 3.3 Well & Reservoir Surveillance and Monitoring, 1.11 Drilling Fluids and Materials, 1.2.3 Rock properties, 5.6.1 Open hole/cased hole log analysis, 4.3.4 Scale, 5.2.1 Phase Behavior and PVT Measurements, 5.2 Reservoir Fluid Dynamics
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Two-dimensional (2D) NMR techniques have been proposed as efficient methods to infer a variety of petrophysical parameters, including mixed fluid saturation, in-situ oil viscosity, wettability, and pore structure. However, no study has been presented to quantify the petrophysical limitations of such methods. We address this problem by introducing a pore-scale framework to accurately simulate suites of NMR measurements acquired in complex rock/fluid models. The general pore-scale framework considered in this paper is based on NMR random walks for multiphase fluid diffusion and relaxations, combined with Kovscek's pore-scale model for two-phase fluid saturation and wettability alteration. We use standard 2D NMR methods to interpret synthetic data sets for diverse petrophysical configurations, including two-phase saturations with different oil grades, mixed wettability, or carbonate pore heterogeneity.
Results from our study indicate that for both water-wet and mixed-wet rocks, T 2 (transverse relaxation)/D (diffusion) maps are reliable for fluid typing without the need for independently determined cutoffs. However, significant uncertainty exists in the estimation of fluid type, wettability, and pore structure with 2D NMR methods in cases of mixed-wettability states. Only light oil wettability can be reliably detected with 2D NMR interpretation methods. Diffusion coupling in carbonate rocks introduces additional problems that cannot be circumvented with current 2D NMR techniques.
Wettability state and oil viscosity can play a significant role in the NMR response of saturated rocks. This property of NMR measurements has been discussed in recent papers (Freedman et al. 2003) for particular examples of rock systems. However, to date, no systematic study has been published of the reliability and accuracy of NMR methods to assess fluid viscosity and wettability, including cases of mixed wettability. This paper quantifies the sensitivity of 2D relaxation/diffusion NMR techniques to mixed wettability and fluid viscosity in generic rock models.
Given that measurements are often made on rock samples with uncertain petrophysical properties and therefore uncertain corresponding measurement contributions, the work described in this paper is based on the numerical simulation of pore-scale systems. We introduce a general numerical model that simultaneously includes immiscible fluid viscosities, water or mixed wettability, variable fluid saturations and history, and disordered complexity of rock structure. Geometrical fluid distributions at the pore scale were considered a function of pore size, saturation history, and wettability following Kovscek et al.'s model of mixed-oil-wet rocks (1993). We simulated suites of NMR measurements with random walkers within these pore-scale geometries, and subsequently inverted into relaxation/diffusion NMR maps. The objective of this paper is to assess the accuracy of 2D NMR interpretation techniques to detect fluid and wettability types, and to quantify pore-size distributions.
The first section of the paper summarizes the principles and limitations of current NMR petrophysical interpretation. We then summarize our pore-scale modeling procedure, its assumptions, and limitations. Subsequent sections analyze simulation results obtained for drainage and imbibition involving water-wettability and mixed-oil-wettability with partial saturations of water and different hydrocarbon types in a generic clay-free rock model. Next, we consider the case of coupled carbonate rocks with emphasis on the assessment of wettability and microporosity.
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