oa A novel approach for quantifying a dual-porosity system and its permeability distribution in a carbonate reservoir: A case study from Al Khalij field, Qatar

The Al Khalij field, located offshore Qatar, is quite a spectacular example of a complex carbonate field. It displays unusually high volumes of moveable water. The complexities are related to diagenesis (patchy cement), mixed and unpredictable wettability and lateral facies changes. The reservoir has been modeled with a dual-porosity model whereby path (productive) and fabric (nonproductive) pore volumes were defined. Quantifying these volumes has proven very difficult with standard petrophysical tools. Nuclear magnetic resonance (NMR) logs were acquired (pipe conveyed) in horizontal in-fill wells to evaluate and potentially quantify the dualporosity system, fluid saturations and permeabilities. Other log data included logging-while-drilling (LWD) gamma-ray, resistivity, neutron and density porosity, and borehole image logs. In addition we acquired formation tester data including four mini-DST datasets as well as between 20–30 single-probe tests in each well. Post-processing and petrophysical interpretation of the NMR logs, in combination with the other available data, resulted in an improved understanding of the porosity (pore size) distributions and rock-quality variations in the various reservoir layers. The partial porosity distributions characterize the pore (throat) size distribution<br>for each layer very clearly, adding to the geological understanding of the reservoir rock. Deriving permeability from NMR for complex carbonate formations is known to be very challenging. We applied the recently published (Di Rosa et al., 2006) pore-connectivity-<br>based permeability model to analyze this carbonate formation. By introducing a pore connectivity constant “p” to modify the Coates permeability model, our novel approach determined the path and fabric pore volume, as well as the permeability more realistically than that from the original Coates model. The connectivity factor “p” was determined using the formation tester mini-DST and probe-test permeability data. Using this approach, it became evident that each reservoir layer displays its own, distinct “p” value, clearly related to rock type. On the other hand, the default carbonate T2 cut-off value and the Coates parameters were kept invariable for all layers, making the interpretation much simpler and explainable. Once the calibrated “p” value was found, a “p”-corrected MBVMC was calculated. This MBVMC can be regarded as the productive path porosity, whereas MBVI + the volume by which MBVM has been reduced represent the nonproductive fabric. Fluid saturations derived both directly from the NMR logs as wells as from using LWD basic log data were then superimposed onto the newly derived pore volume distributions.