Petroleum Accumulation and Leakage in a Deeply Buried Carbonate Reservoir, Nispero Field (Mexico)
The filling history of the Níspero deeply buried Lower Cretaceous carbonate reservoir (below 4000 m) from the south part of Gulf of Mexico was studied using a combination of data from petrography, stable isotopes and fluid inclusions and compared with a one-dimensional burial model to derive timing. A combination of techniques such as microthermometry, confocal laser scanning microscopy (CLSM) and Raman microspectroscopy have been used to characterize the different fluid inclusion assemblages and discriminate between the reequilibrated and the preserved fluid inclusions. The Níspero reservoir is composed of a fractured finely crystalline replacement dolostone. A first generation of fractures is filled by a non-planar dolomite cement, and a second generation by a planar-e dolomite cement and a blocky sparite. The reservoir is lastly stylolitised. Dolomite has δ13C values between 0.9 and 4.0 ‰ (PDB) and δ18O values between -4.5 and -10.8 ‰ (PDB). Calcite has δ13C values between 3.8 and 4.4 ‰ (PDB) and δ18O values between -4.9 and -5.5 ‰ (PDB). These values suggest that the calcite represents a change in water composition, and that dolomite and calcite cements do not precipitate from petroleum-derived fluids. However, geological fluids are trapped as aqueous and oil inclusions in the calcite cements. Three petroleum-aqueous inclusion assemblages were identified: pseudo-primary brown oil paired with brine inclusions and pseudo-primary yellow oil paired with low salinity water inclusions distributed in local concentrations; and secondary colourless oil paired with low salinity aqueous inclusions distributed in healed microfractures. The burial model, calibrated with bottom hole temperatures, has been calculated using PetroMod® 1D to generate the rock PT history under hydrostatic and lithostatic regimes. Reconstructed temperatures of initial trapping of fluid inclusion and calculated temperatures from δ18O measured in dolomite and calcite cements are in good agreement. Data suggests that the reservoir was being filled at 97ºC-315 bar by heavy black oils in presence of high salinity water during the Miocene period (11.6 m.y.). The maximum estimated pressure of 700 bar at 130ºC is reconstructed by petroleum inclusions trapping black oil and associated low salinity aqueous inclusions. These PT conditions were reached during the Pliocene (3 to 2 m.y.). Present day reservoir conditions of 145ºC and 500 bar are recorded by reequilibration of most of the fluid inclusions of the two assemblages and correspond to hydrostatic pressure. The drop of pressure from 700 bar to 500 bar may be an explanation for the late stylolitisation.
AAPG Datapages/Search and Discovery Article #90340 ©2018 AAPG Geoscience Technology Workshop, Deep and Ultra Deep Petroleum Systems, Beijing, China, October 26-28, 2018