This paper reports on a successful example of using the 2D NMR technique for determining oil-water contact (OWC) in difficult carbonate environments. An NMR diffusion-based interpretation method was used to identify oil, water, and transition zones and to quantify oil saturation in a limestone reservoir. Hydrocarbon typing and saturation determination from NMR logging usually require high contrasts of intrinsic or apparent relaxation times, diffusivity, or both. Many carbonate reservoirs in the Middle East contain large pores, which together with the low relaxivity of carbonates, create long T1 and T2 times for water. Furthermore, because light oil has a long relaxation time, there is little contrast in T2 or polarization between water and oil. When these reservoirs contain very light or high-GOR oils, the diffusivity contrast between oil and water is also less pronounced. Hence, it is difficult to distinguish between the oil and water signals with most NMR hydrocarbon-typing techniques. The example shows that a diffusion log constructed from 2D NMR interpretation works well even for marginal diffusion-contrast cases. In addition, a modification to the Coates permeability model is presented that is applicable to carbonate formations having partially connected vugs.


Formation characterization and reservoir-fluid identification and quantification in carbonate reservoirs are much more challenging than in clastic formations because the pore systems in carbonates are usually more complex, which makes the application of conventional saturation models more difficult. A number of Middle East limestone reservoirs containing light oil have abundant vugs that can be either connected or isolated. In such vugular carbonate reservoirs, NMR logging applications face unique challenges. First, the vugular and irregular pore systems in carbonate reservoirs cause apparent movable fluid volume (MBVM) estimates to be overly optimistic. Consequently, the Coates permeability model (Coates et al. 1991) may overestimate permeability if the "vug effect" is not corrected. Second, the lower surface relaxivity of carbonates reduces the relaxation contrast between light oil and water in large pores and vugs. As a result, the relaxation-time contrast alone is usually insufficient for hydrocarbon typing in carbonates. In addition, the diffusivity of light oil is not significantly different from that of water, making even diffusion-contrast-based NMR hydrocarbon typing difficult. In such cases, a many-faceted data-acquisition scheme, with a variety of TE and TW values, and a comprehensive data-processing procedure becomes critically important for obtaining reliable results for oil-water contact and saturations.

During the past several years, ADCO has actively explored opportunities for using new NMR logging tools for the improvement of reservoir characterization and rock typing and for identification and quantification of oil and water. This paper describes results from a new NMR logging tool—MREXSM—that was run in a vertical appraisal well on land in Abu Dhabi. The well was later sidetracked and completed as a horizontal producer. The present research concentrated on the evaluation of data, including a conventional core, acquired in the vertical pilot well.

Using NMR logs, the authors were able to compute oil and water saturations in the oil, transition, and water zones. The results compare favorably with those from resistivity-based saturation analysis and were later confirmed by production data.

Furthermore, a modified Coates permeability model is proposed here that takes into account vug-connectivity variations to improve permeability estimation for vuggy carbonate formations. The model is also applicable to other poorly connected pore systems.

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