Summary
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.
Introduction
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.
© 2008. Society of Petroleum Engineers
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History
- Original manuscript received:
9 September 2006
- Meeting paper published:
5 November 2006
- Revised manuscript received:
16 May 2007
- Manuscript approved:
6 October 2007
- Version of record:
25 April 2008
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