Development of an Improved Petrophysical Model based on Semi Quantitative Mineralogy, Jurassic-Cretaceous Succession, Cooper Area, Eromanga Basin
Melissa C Vallee
Master of Science 2010
University of Adelaide
Providing reliable petrophysical interpretations in reservoirs with complex mineralogy can be particularly challenging. These challenges are exacerbated when the sediments are rich in lithic grains and subsequent diagenesis has modified the pore structure by filling the pores with a variety of clays and other cements. In order to constrain the petrophysical models for the oil reservoirs in the Cooper area of the Eromanga Basin, a petrological study was proposed, incorporating thin sections analysis, X- Ray diffraction (XRD) and Scanning Electron Microscopy (SEM) to quantify the mineralogy and pore structure, document provenance evolution and redefine the petrophysical model used in the area.
A series of four cored wells were selected over a fairly wide area of the Cooper area to provide coverage of the majority of producing horizons. The target sandstones were located in the Hutton, Birkhead, Westbourne, Namur and Cadna-owie Formations. Previous diverse studies have defined the overall structure of these reservoirs; however, the presence of smectite and other clays and the influences of diagensis have been poorly described and interpreted. As these reservoirs are often marginal in terms of production and reserves, the impact of clays and alteration in pore structure have significant influence on recovery factors.
Detailed work was completed using traditional grainsize-permeability plots, XRD analysis and SEM to identify trends and mineralogy. This was complemented with Quartz-Feldspars-Rock Fragment (QFR) plots to understand composition and provenance evolution. The determination of clay mineralogy by formation represented a key factor in understanding clay variations with depth and across the succession and how these influence the physical properties of the reservoirs. As a result, an improved petrophysical model was built, generating more robust and accurate interpretations for further wells drilled in the area.
Following the QFR classification by Folk (1974), results from ternary plots suggested that most analysed samples would be classified as arkose, subarkose and lithic arkose, however, the Birkhead Formation samples are feldsphatic litharenites. XRD analyses and SEM photomicrographs revealed the presence of smectite, kaolinite, illite, chlorite and mixed layer clays as the main authigenic clays. Siderite and calcite were identified as the main cements in the Westbourne and Birkhead Formations, whilst silica and kaolin cements were present in the Namur and Hutton Formations.
Investigation results changed the understanding of clay minerals through the formations, including now smectite and chlorite. In the new petrophysical model a framework mineral, calcite, was substituted by chlorite (an authigenic clay) due to the limited amount of electrical logs used in the modelling. In general, an increase in the volume of clays was observed within the formations as a consequence of the modifications in the clay mineralogy model, with a slight decline of the total porosity. Yet, an increase in effective porosity between 0.1 - 0.7% and an increase in water saturation between 5 - 10% was noticed. These changes were due to the effects of the bound water associated with the chlorite. Chlorite, due to its high surface area, has a significant volume of associated water (clay-bound water), and this contributes to the overall water saturation; however, this additional volume of water associated with the clay is not mobile.
Water saturation and porosity are two key parameters for oil in place estimations. Consequently, the diminution of their absolute values will ultimately decrease the previously determined oil in place.