Mineralogical modelling and petrophysical parameters in Permian gas shales from the Roseneath and Murteree formations, Cooper Basin, Australia (original) (raw)
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Porosity and water saturation are the most critical and fundamental parameters for accurate estimation of gas content in the shale reservoirs. However, their determination is very challenging due to the direct influence of kerogen and clay content on the logging tools. The porosity and water saturation over or underestimate the reserves if the corrections for kerogen and clay content are not applied. Moreover, it is very difficult to determine the formation water resistivity (Rw) and Archie parameters for shale reservoirs. In this study, the current equations for porosity and water saturation are modified based on kerogen and clay content calibrations. The porosity in shale is composed of kerogen and matrix porosities. The kerogen response for the density porosity log is calibrated based on core-based derived kerogen volume. The kerogen porosity is computed by a mass-balance relation between the original total organic carbon (TOCo) and kerogen maturity derived by the percentage of c...
Analysis of the Behavior between Mineralogical Composition and Porosity from X-Ray Diffraction Data
The increasing interest in unconventional resources guides the need to characterize the pore networks of source rocks. Unlike conventional reservoir rocks, basin mudrocks rich in organic matter are more complicated to characterize due to its very fine allochemicals grain size (silty to clayish grain sized), causing a very small pore size and very low permeabilities. Petrographic descriptions, scanning electron microscope images, X-ray diffraction analysis, TOC determination and mercury injection porosimetry were performed on core samples and the results were compared as a function of depth. The results show that there is a direct relationship between mineralogical composition, TOC, porosity values and pore size.
FTIR, XRF, XRD and SEM characteristics of Permian shales, India
The emergence of shale gas as potential hydrocarbon resource has changed the global energy landscape. Fourier Transform Infrared (FTIR), X-ray diffraction (XRD), X-ray florescence (XRF) and Scanning Electron Microscope (SEM) characteristics of thirty nine borehole shale samples belonging to the Barakar (Lower Permian), Barren Measures (Upper Permian) and Raniganj (Upper Permian) Formations from different parts of Raniganj basin, India were studied. FTIR analysis indicates the presence of aromatic hydrogen, aromatic carbon, aliphatic CeH stretching, aliphatic CeH bending, OH functional group within the organic matter and presence of kaolinite, quartz and carbonates within the studied samples. XRF studies indicate that the shales have undergone intermediate to strong weathering condition, and are marked by presence of clay minerals mainly illite and kaolinite. In addition to illite, kaolinite and quartz, alkali feldspar, siderite and calcite were identified within the shales through XRD. Marked development of amorphous character was noted in the XRD plot of one heat affected shale sample. FTIR analysis of this sample also indicates removal of aliphatics and disordering of kaolinite within the sample due to the impact of heat. Through SEM studies different types of surface morphologies, different types of pores and pore shapes in organic matter were identified. SEM studies also indicate intimate mixing of organic matter and mineral matter in shales even at submicroscopic levels. This intimate association appears to have impact on the retention of hydrocarbons by the mineral matrix during Rock Eval pyrolysis. The various micropores, microcracks, fracture traces, macropores and vacuoles may play significant role in diffusion and flow of hydrocarbons.
A B S T R A C T The mineralogical complexity of mudstone reservoirs has led to the increased usage of multimineral optimizing petrophysical models for estimating porosity, water, and hydrocarbon volumes. A key uncertainty in these models is the log response parameter assigned for each log equation related to each volumetric variable. Default parameter values are commonly used and often need to be modified by considering subjective local knowledge or intuition to achieve a result that is considered acceptable. This paper describes the methods developed at Chevron for calibration of mineral log response parameters using core data. Mineral log response parameters are controlled by the major and trace element chemistry of the individual minerals in the formation rock matrix. BestRock™ uses a nonlinear approach to optimize whole-rock chemistry with mineralogy to calculate individual mineral structural formulas and trace element associations from which certain log response parameters can then be calculated. Accurate quantitative phase analysis (QPA) to determine mineral content is a critical step in the process, which is achieved here by rigorous sample preparation methods and QPA by x-ray diffraction (QXRD). The QXRD in combination with whole-rock elemental analyses are processed using Chevron's BestRock optimization software to provide refined quantities of the mineral species present in the formation, their structural formulas, and their predicted wireline log responses. Calibrated petrophysical models are built
The Cogollo Group Formations, Maraca, Lisure and Apon are the main carbonate oil reservoirs in Western Venezuela. The Cretaceous 09 reservoir was discovered in 1970 and produced oil with maximum production rate 16,000 BOPD. Totally 9 wells were drilled, but currently only one well is active and producing an average hydrocarbon rate, 400 BOPD. Generally these formations have low porosity and low permeability with secondary porosity, fractures and vugs. Basically more than half of total porosity is secondary porosity. The new reservoir development plan will be allowed to improve reservoir performance. Therefore a petrophysical study was conducted in due course using Interactive Petrophysics software. The main challenge in this study was modeling a multi mineral lithology model (Sand/lime/dolo/shale) with poor quality and lack of full set porosity and lithology logs (neutron, density, sonic and PEF). For reliable quantitative log evaluation synthetic porosity logs (NPHI, RHOB, and DT) were generated for most of the wells with statistical analysis using Mutilinear Regression (MLR) method. The applied Methodology lets us to resolved multi mineral volumes (Vsand, Vlime and Vdolo). The shale volume calculated from GR with conjunction of neutron and density and linked to the calculated dry matrix volumes from Three Mineral Model (MID chart). The porosity was estimated from neutron density cross plot and remove clay bound water effect on total porosity, finally effective porosity was estimated. The Monte Carlo uncertainty analysis was used to estimate uncertainty of porosity, water saturation, permeability and shale volumes for P10, P50 and P90. The core data show, Cogollo group Formations have a complex texture which cementation and saturations exponents vary by rock types. For valid water saturation SCAL data were used to establish different equations for m and n from porosity, Formation resistivity factor and resistivity index. The overburden pressure corrected routine core porosity and permeability were used to establish different por-perm relationships based on rock type to calculate permeability. Also FZI method was used to estimate permeability. The raw log data were used to calculated rock type from Fuzzy Logic method. The sonic and density logs were used for calculation of rock elasticity parameters and fluid substitution. Sonic and density logs corrected to invasion effect were used to estimate Reflection Coefficient for AVO Analysis. Petrophysical parameters were determined using conventional log analysis method, core and log integration were conducted for definition of reservoir rock type and permeability. INTRODUCTION According to Geomechanics, a fracture is a surface where there was a loss of cohesion and generally is a discontinuity that breaks the rock strata in blocks, through cracks, fissures and Joint through which there is no displacement. Fractured reservoirs differ from conventional reservoirs. The density and intensity of the fracture are essential steps in the description of a fractured reservoir is much more complex evaluating the porosity and permeability than in a conventional reservoir.