Dynamics of calcite cementation in response to oil charge and reservoir evolution: Thamama, Group, U.A.E.
Al Harthi, Amena Dhawi Juma Mayoof
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Carbonate rocks consider as significant reservoirs for hydrocarbon. More than 60% of the world’s hydrocarbon is placed in carbonate reservoirs. Carbonate rocks are heterogeneous and contain complex pore system. This complexity causes the hydrocarbon recovery from these reservoirs difficult; having less than 35% of hydrocarbon is being recovered. The heterogeneity and the variation in pore system are a result of various depositional settings and successive diagenetic overprints. Diagenetic overprints account for most of the pore system complexity in subsurface. This project undertakes one of the important diagenetic processes, calcite cementation, which though to have major impact on reservoir quality. The project aims to better understand the controls on calcite cementation in five Lower Cretaceous Reservoirs, in particular the role of calcite cementation with relation to oil charge in reservoir quality. Other diagenetic processes were also asses including dolomitization, dissolution, micritization and chemical compaction. The five reservoirs (A, B, C, F & G) are from Field A which is located in Abu Dhabi, UAE. The reservoirs comprise of interbedded porous “Reservoir” and low porosity-permeability “Dense” limestones deposited in broad range of settings, ranging from restricted to open marine platform. Reservoir intervals are part of HSTs, deposited during higher sea level time. The dense intervals were deposited during TST and thought to be cemented early resulting in early compartmentalization in all reservoirs. The mMg/Ca and in-situ (SIMS) δ18OVPDB were measured through complete calcite cement stratigraphy obtained from equant, syntaxial and blocky calcite in all reservoirs. Both mMg/Ca and δ18OVPDB of oldest calcite cement zone are matching with published mMg/Ca and δ18OVPDB of Lower Cretaceous, suggesting precipitation from Lower Cretaceous seawater. The mMg/Ca and δ18OVPDB also vary from reservoir to another reflecting change in Cretaceous seawater. These data also coincide with trace element observations particularly Mn and Sr. All these parameters show fluctuations in Cretaceous seawater during 135-123Ma caused by global changes in climate and oceanic crust production rates. Lower reservoirs including F (133Ma) and C (130Ma) were more probably affected by the Hauterivian global cooling which resulted in higher δ18OVPDB in the early precipitated cements. Precipitation in upper Reservoir B (126Ma) was most likely affected by the abrupt warm episode just before the OAE1. Reservoir A (123Ma) precipitation may be affected by the Early Aptian cooling episode and the OAE1. Reservoir G is the only one not recording δ18OVPDB similar of Cretaceous seawater. Cementation in Reservoir G was affected by depleted δ18OVPDB fluids from early stage, perhaps hot, basinal waters. More interestingly, the mMg/Ca, δ18OVPDB Mn and Sr means of younger calcite cement zones which thought to be evolved during burial show similar trend to the oldest cement zones with various offsets. This suggests that calcite cement in each reservoir evolved in a relatively close system inferring by this that the reservoirs are compartmentalized. The compartmentalization is probably due to the sysedimentary or early cemented hardgrounds in the Dense Zones. The Dense Zones acted as seals for the reservoirs from early stage causing the later precipitated calcite cement which is diagenetically affected to behave in predictable and similar way. Moreover, calcite precipitation temperatures inferred from mMg/Ca and δ18OVPDB show progressive increase towards younger cement zones indicating fluid evolution with burial in also relatively close system. In-situ δ18OVPDB and oil inclusions suggest earlier oil charge in the shallower reservoirs compared with deeper reservoirs and coeval water leg. Consequently, cementation in the shallower reservoirs continued with lower rate and hence preserved some primary and secondary pores. Conversely, in the water leg cementation continue to occlude most of the pore spaces. Furthermore, early oil emplacement in the shallower reservoirs increased the cementation temperature of calcite in the oil leg to reach maximum precipitation temperatures of ~144˚C. Whereas, in the water leg and deeper reservoirs, cementation continued to a temperature of ~110˚C. Overall, reservoir quality in Thamama Group was affected by various diagenetic processes. Some have resulted in reservoir quality enhancement such as dolimitization which involves formation of microporosity as a result of replacive rhombic dolomite, dissolution particularly the late one which believed to be due organic acid, and micritization with yield microporosity particularly in Reservoir B. Open fractures might have also enhanced reservoir quality to some extent. Diagenetic events that have deteriorated reservoir quality include calcite and saddle dolomite cementation as well as stylolitization. Greater calcite cementation can be found in water leg compared with oil leg because oil thought to decrease cementation rate.