Imaging reservoir quality: seismic signature of geological processes, SW Loppa High, Norwegian Barents Sea

This study focuses imaging reservoir quality of SW Loppa High using five exploration wells. The study area is located at the northern vicinity of the Hammerfest Basin, Norwegian Barents Sea. The geology of the Norwegian Barents Sea is far complex compared to other hydrocarbon provinces (North Sea, Norwegian Sea) in the offshore Norway. The geological complexity makes reservoir characterization in the Barents Sea quite difficult. Several stages of uplift and erosion influence the petroleum play and reservoir parameters. All these geological factors made reservoir rocks very complex. This study considered an integrated approach of petrophysical analysis, rock physics diagnostics and AVO modeling to characterize three reservoir sandstones of L. Cretaceous Knurr Formation, M. Jurassic Stø Formation and M. Triassic Snadd Formation. The Knurr Formation possesses clastic wedge deposits developed over the footwall during exhumation whereas the Stø Formation deposited during shoreface environment. whereas The northern side of the study area holds thick shale units of the Snadd Formation which are carrying reservoir sandstones, deposited during sea level fall. The Knurr Formation in well 7120/1-2 shows very good reservoir quality whereas in well 7120/2-2 high shale volume deteriorates the reservoir quality. The Stø Formation shows the same trend from well 7120/1-2 to 7120/2-2. The Snadd Formation which comprises thick units of shale holds sandstones with fair reservoir quality. The sandstone units embedded in oil mature source rock could be a possible future prospect. The petrophysical analysis revealed two types of trends; inter-formational changes from one well to the other and the intra-formational changes within a single well. The Knurr Formation which holds dominating part of the L. Cretaceous clastic wedge changes its facies from west to east. It becomes more shaly in the eastern part and the net-to-gross ratio reduces almost 50%. The porosity also decreases towards east which ultimately effects the hydrocarbon saturation which is almost negligible towards east. The Stø Formation showed no difference on net-to-gross towards east but the porosity decreased drastically. The hydrocarbon saturation towards east is also insignificant for the Stø Formation in the studied well (7120/2-2). The reduction in porosity is due to the deep burial diagenesis of high temperature which leads to chemical compaction. The reservoir quality of the Snadd Formation decreases from east to west. The effect of cementation, fluid sensitivity and lithology is analyzed using rock physics templates. The Knurr Formation found to have effect of less cementation in contrast to the deeply buried Stø Formation. The effect of cementation increased from west to east where the rocks are found at higher present day burial depth. The Snadd Formation has thickness ten times higher than the Knurr and Stø Formations in the Loppa High area found at shallower present day depth with low temperature gradient. The Rock Physics Templates revealed that the Snadd Formation has gone through chemical compaction which is also supported by the phenomenon of exhumation in the study area. The Snadd Formation prior to uplift has attained the greater burial depth and so higher temperature which was necessary for chemical compaction (cementation). It is clear from Rock Physics Diagnostics that the cemented reservoir sandstones are not that sensitive to fluid changes as compared to unconsolidated rocks. Combination of Rock Physics Diagnostics and AVO modeling for cemented reservoir section showed change in seismic parameters but not that robust as usually observed in the unconsolidated sandstones. Fluid replacement modeling shows gradual decrease in density of reservoir rocks with the increase in percentage of gas. The seismic velocities only shows sharp changes when the gas is introduced to the reservoir despite the amount of gas substituted to the reservoir sandstones. From above observations it can be concluded that the conventional methods of reservoir characterization are not good enough to image reservoir quality. Multi-disciplinary integration is the key to the success for hydrocarbon exploration. It minimizes the exploration risk and enhances the quality of imaging reservoir rocks.