Schlumberger

Technical Paper: Carbonate Petrophysics in Wells Drilled With Oil-Base Mud

Society: SPWLA
Paper Number:
Presentation Date: 2011
 

Abstract

Several classification schemes have been developed to aid formation evaluation in carbonates. These are based on quantifying carbonate rock texture by either by grain size (Archie, 1952; Lucia, 1995), pore-size (Choquette and Pray, 1970; Pittman, 1971; Cantrell and Haggerty, 1999) or pore-throat size (Marzouk et al., 1995; Clerke, 2009). They were developed from visual inspection of cores and cuttings, thin-section microscopy or mercury porosimetery. Recent advances in NMR log and core analysis, complemented by more quantitative use of borehole image logs, has led to the application of logbased porosity partitioning based on some of these models. The foundation of this approach is the link between Nuclear Magnetic Resonance (NMR) Transverse Relaxation Time (T2) distributions and poresize distributions obtained from special core analysis. Several case studies have now been presented where this approach was successfully used in carbonate formations drilled with water-base mud, where the NMR response is well characterized and has been validated by core analysis.

The recently discovered carbonate reservoirs offshore Brazil are typically drilled with oil-base mud to avoid problems in the 2,000 meters of salt overlying the reservoir. NMR logs are routinely run in the reservoir section and the interpretation methods developed for carbonates drilled with water-base mud have now been shown to be potentially adapted for evaluating reservoir quality, even when oil-base mud is used. The tendency of these carbonates to be oil-wet to both the 28-30 API reservoir oil and the oil-base mud filtrate ensures that surface relaxivity is the dominant relaxation mechanism in the NMR response, which enables the correlation of T2 distributions with the variety of pore sizes in the reservoir zones. Interpreting NMR logs in such conditions requires detailed knowledge of the oil-base mud filtrate properties, the reservoir oil properties and the wettability of the formation at down-hole conditions. Performing lab NMR measurements on these fluids and representative core samples at PVT conditions is one of the key requirements for correctly interpreting the NMR log data.

Examples of lab measurements, performed on native state, restored state, brine saturated, and partially saturated cores at PVT conditions when compared with down-hole NMR log data show that many of these carbonate classification schemes can be applied in the pre-salt carbonates. The common features of these schemes will be examined and the various models will be reviewed in terms of their relevance for formation evaluation in the pre-salt carbonates. Options for analyzing borehole image logs in carbonates drilled with oil-base mud will also be presented as an aid to porosity typing with NMR. The key considerations will then be summarized for core analysis and also for acquiring, processing and analyzing NMR and borehole image logs in carbonates drilled with oil-based mud.

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