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Abstract: NMR Logging For Reservoir Characterization and Evaluation in a Conglomerate Complex Lithology

Rodriguez, M. R. - Petrobras/E&P; Padilha, S. T C. S. - Schlumberger; Gasperi, P. M. - Petrobras/E&P

The main purpose of the recent NMR technology for well evaluation is to provide a lithology independent porosity and producibility to enhance the confidence of reservoir rock quality parameters.

In Sergipe-Alagoas Basin the exploitation of the oilfields requires an accurate reservoir characterization and formation evaluation, due to the rift and drift deposits from this passive margin environment. The Aptian fan delta depositional system is formed by a complex lithology, being an interesting target for NMR logging. The reservoir studied is a sequence of fine- to coarse-grained sandstones interbedded with matrix- and grain-supported conglomerates with a variable matrix density and mineralogical composition. The reservoir facies are clean sandstones (RF-1) and conglomerates composed by quartz, feldspars, micas, quartzite, slate, schists and dolomite (RF-2). The non-reservoir facies corresponds to silt, shale and diamictite (NRF).

Using traditional log information to evaluate this type of reservoir is usually a difficult challenge and does not always provide a conclusive analysis. Based on these, a CMR* log was run and correlated with petrophysical core data in order to validate porosity and permeability quantification.

The evaluation model applied to this reservoir calculates an effective porosity (PHIE) from gamma ray, density and neutron logs using a matrix density of 2.74 g/cc, obtained from the minerals percentage at thin sections.

On Figure 1 (track 5), there is a discrepancy between the core and log matrix density (RHGX). Where RF-1 is thinner and intercalated with RF-2, RHGX agrees with core measurements and the respective porosities are well determined, considering their scales. On the other hand, where RF-1 is thicker, the calculated PHIE is overestimated, due to the high value of 2.74 g/cc used.

On track 2, the total and effective CMR porosities agree with the ones calculated from petrophysical laboratory data. For the free fluid porosity (CMFF), laboratory NMR measurements made in different plugs saturated with the high salinity formation water, showed a transverse relaxation time decay (T2) cutoff of 10 ms for RF-I and RF-2. The use of this cutoff shows some quantity of free fluid in the NRF, which indicates that the four production zones are hydraulically communicated, although the predominant fluids are trapped by capillary forces.

Permeability data from plug, continuous analyzer and calculated from Timur-Coates model, which uses a CMR curve as an input, showed a strong correlation.

The NMR results improve porosity and permeability determination for a more accurate reserves calculation and give an idea about the reservoir behavior as well.

AAPG Search and Discovery Article #90933©1998 ABGP/AAPG International Conference and Exhibition, Rio de Janeiro, Brazil