Facies, Deposional Environments and Reservoir Properties of the Albian Age Gas Bearing Sandstone of the Ibhubesi Oil Field, Orange Basin, South Africa
With an upbeat in hydrocarbon exploration effort in the Lower Cretaceous, emphasis is increasingly laid on the geologic settings of the Orange basin. The Orange basin was formed during the late Jurassic to early Cretaceous periods due to Gondwana breakup and rifting and later drifting apart of the African and South American plates. The basin consists of siliciclastic sandstone which took its sediment supply from river system with a rivaling delta to the north of the basin.
Petroleum reservoir characterization is a process for quantitatively describing various reservoir properties in spatial variability using all available field data. Porosity and permeability are two reservoir properties which relates to the amount of fluid contained in a reservoir and its ability to flow. These properties have significant impact on petroleum fields operations and reservoir management. In an un-cored intervals and well of heterogeneous formation, porosity and permeability estimation from conventional well logs could be problematic. Heterogeneity of pore structures and the lack of quantitative understanding of it are one of the fundamental causes of inefficient oil recovery. The key element influencing oil flow is the connection between pores. Dissolution of calcite and other minerals (authigenic clays) is one of the major factors in geological evolution that creates complex pore geometry and connectivity in reservoir rocks.
The present study considered 5 wells in the Orange Basin with attention to the Albian age gas bearing sandstone. The methods include the description and calibration of spot cores with conventional standard logging record responses coupled with detailed petrographic (SEM, TEM, XRD and Thin section) and geochemical (pore water geochemistry, FTIR and XRF) analyses and reservoir properties evaluation and interpretation to unravel the complexities with regard to facies association, depositional environment and diagenesis.
Linking diagenesis to depositional facies and sequence stratigraphy has given a clearer picture to the spatial and temporal distribution of diagenetic alterations and thus of evolution of reservoir quality in the reservoir sand. This thesis demonstrate that employing this approach is possible because depositional facies and sequence stratigraphy can provide useful information on parameters controlling the near surface diagenesis such as changes in (i) influence of organic matters on pore water geochemistry (ii) residence time of sediment under certain geochemical conditions (iii) detrital composition and proportion of extra and intra-basinal grains.
Petrophysical evaluation of the different reservoir bodies shows a relatively fair to good porosity and permeability while laboratory analysis on selected core samples shows adverse effect of authigenic minerals (chlorite, kaolinite, calcite, illite and mica) on the reservoir properties of the Albian age reservoir sands. The integration of petrographic analysis with pore water data explains cements succession in the sandstones mixing with acid water derived from dewatering of interbedded organic rich mudstones which probably added Mg2+ and Fe2+ to partially buffer the loss of these cations to chlorite. The acid produced during the breakdown of this organic matters are presumed to have mixed into sandstone pore fluid due to further compaction of muds leading reduction of initial alkalinity in some of the studied wells. The changes in the chemical characteristics of the pore fluid leads to a more complex distribution of reservoir porosity at different depths than that of the secondary porosity formed by classical acidic water. Three depositional facies were identified based on a detailed core description. A fluvio-deltaic and shallow marine environment was also interpreted from the core description with regards to the sedimentary structures and minerals observed while the log interpretation shows that the different reservoir units spans between LST, TST and HST.
AAPG Search and Discovery Article #90094 © 2009 AAPG Foundation Grants in Aid