Controls on reservoir quality in Early Cretaceous carbonate oil fields and implications for basin modelling

Abstract

Carbonate reservoirs hold more than 50 % of Earth’s remaining conventional hydrocarbon. However, recovery from these reservoirs is notoriously difficult due to the complex and multiple scales of porosity. This heterogeneity is a function of both the depositional environment and of subsequent diagenetic processes. This thesis examines the processes that have controlled the reservoir quality of three Early Cretaceous carbonate oil fields (A, B, and C), in particular the role of deposition, diagenesis and the timing of oil charge in controlling final properties. Results are then used to help provide a theoretical basis for the modelling and prediction of reservoir quality and to improve the calibration of basin models. Field A and B are stacked and highly compartmentalised giant oil fields in the U.A.E. that are dominated by muddy fabrics and have a highly variable porosity (0- 35 %) and permeability (0.01-830 mD). Although the depositional environment strongly determines the location of reservoirs extensive diagenesis, through cementation and dissolution, has greatly modified the porosity and permeability of the reservoirs. Bulk δ13C values obtained from the main pore occluding calcite and dolomite cements are similar to the δ13C values of bulk micrite for the reservoir interval in which they are now present. This suggests that the cements that are occluding the pore space in each stacked reservoir are locally sourced and implies that each reservoir behaves as a relatively closed system during cement precipitation. In-situ (SIMS) δ18OVPDB values were obtained for the complete calcite cementation history of multiple reservoirs in Field A and B. The δ18OVPDB values for the first (oldest) calcite cement zone in each reservoir can be related to the global δ18OVPDB marine curve during the Hauterivian-Aptian and to million-year scale major climatic cooling events. The δ18OVPDB values for successive cement zones then progressively decrease, which is related to successive precipitation as a result of increasing temperature during burial in a relatively closed system. In-situ (SIMS) δ18OVPDB data together with oil inclusion occurrence suggest that initial oil charge (from the Dukhan Formation), at ~ 55-45 Million years ago (Mya) in Field A, reduced the cementation rate in the oil reservoir and preserved porosity. Whereas in the coeval aquifer a large volume of cement precipitated, after oil entered the oil reservoir, that greatly reduced porosity. Furthermore, the most reduced δ18OVPDB and mMg/mCa values are obtained from the cements in the shallowest (youngest) reservoirs, suggesting that cementation ceased in the deepest reservoirs first. This can be related to hydrocarbon stopping cementation or to the complete occlusion of effective porosity in the older reservoirs prior to the younger. After calcite and dolomite cementation ceased in the reservoirs of Field A and B a large scale dissolution event has been identified which significantly enhanced porosity. This dissolution event is then followed by the precipitation of authigenic kaolinite. Basin modelling reveals that this dissolution event is likely to be related to the thermal maturation of sedimentary organic matter that is present within local intraformational seals and to the migration of organic acids prior to a second hydrocarbon charging event (at ~ 45 Mya). The aluminium, that is required for the formation of kaolinite, would then have been brought into the system by complexing with the organic compounds derived from this maturation event. Field C is an oil field located in offshore Brazil. The field is dominated by high energy facies that have porosities which range from 5 % to 39 %, and permeabilities from 0.1 mD to 8.1 D. The depositional poro-perm properties of the oil reservoir have undergone little diagenetic alteration; however, the aquifer is extensively cemented and the porosity is much reduced. All the cements identified, by both petrography and stable isotopic analyses, in the oil reservoir are early and are thought to have formed from a pore fluid similar to, or slightly evolved from, Early Cretaceous seawater. Basin modelling suggests that oil may have entered the field slightly after deposition (at ~105 Mya) and led to the preservation of high porosities and permeabilities in the oil reservoir by stopping cementation.