pose SCAL challenges in case of the relatively small average nodule sizes. In total 24plugs (as homogeneous as possible representing either matrix or nodule) were drilled andcleaned, followed by porosity and gas permeability measurements. The measuredporosity distribution indicates a porosity range from 0.10 to 0.45, which can be groupedinto two porosity classes: 0.15-0.20 for the nodules and 0.30-0.40 for the matrix.The air permeability was measured for 17 samples and shows two orders of magnitude of permeability variations across the matrix and nodules. The cross-plot of the permeabilityvs. porosity relationship is shown in Figure 4. It is noted that the general trend of thepermeability vs. porosity curve is consistent with the typical core analysis data (of regular1-1.5 inch plugs) from the Natih formation. In general some Natih formation porosity-permeability scatter (not shown here) may be caused by the relatively small fraction of either the matrix material in nodule plugs or the nodule material in matrix plugs.
Primary Drainage Capillary Pressure
After the porosity and permeability measurements, mercury-air capillary pressure curveswere measured on the small plug samples. The measurements as shown in Figure 5 revealtwo distinctive groups of capillary pressure curves: one for the matrix (the high porosityclass) and the other for the nodules (low porosity class). The mercury-air capillarypressure data were then converted to the corresponding brine-crude system taking intoaccount the interfacial tension and contact angle (
)) for the specific brine-crudesystem. The capillary pressure curves show significant impact on the initial oil saturationespecially in the layers close to the free water level.In this study, the data were synthesized into two representative primary drainage curves,one for matrix and the other for nodules as shown in Figures 5 & 6. In general, furtherscaling of capillary pressure with permeability and porosity within each rock type(nodules and base matrix) following the Leverett-J type of approach can be made.
Imbibition Capillary Pressure and Relative Permeability
Due to the small size of the selected plugs, the imbibition capillary pressure curves werenot measured directly on all the selected samples. The cored matrix and nodule plugs ingeneral did not have adequate sizes suitable for multi-phase flow and centrifugemeasurements to represent the matrix and the nodules separately.Since the two rock types have different porosity, permeability and primary drainage data,they are expected to have different imbibition capillary pressure curves. No spontaneousimbibition of water was observed on samples from the reservoir under study followingwettability restoration (Mookerjee and Alias, 2006), and in general low (< 20%) residualoil saturation was found for both rock types. Recently it has been reported that theimbibition capillary pressure for samples showing no spontaneous imbibition, which isgenerally the case for limestone oil reservoirs, may be calculated from the correspondingprimary drainage capillary pressure (Masalmeh and Jing, 2006). The procedure requires