Gas volumes for gas shale reservoirs are generally estimated through a combination of geochemical analysis and complex log interpretation techniques. Here geochemical data including TOC (Total Organic Carbon) and results from pyrolysis-based on core and cuttings are integrated with log derived TOC and other petrophysical outputs to calculate the volume of kerogen (for adsorbed gas), kerogen and clay-free porosity, and best estimates of volume of clay (VCL) and water saturation (Sw ). The samples and logs come from the Cooper basin, Australia, where the Roseneath and Muteree fomarions are currently of interest for shale gas potential. This study developed a framework to assist in the selection of a proper mineralogical model. The framework involved grouping of similar minerals into a single mineral category to make a simple mineralogical model because of shortcomings of the stochastic petrophysical techniques, which cannot solve for more minerals than the input curves (only a handful of logs were available for all the wells). The same mineralogical model was used for other wells in the study area where there was no XRD and core data available.Total Organic Content is the basis for the absorbed gas and provides means to correct the total porosity for kerogen and clay. Hence, TOC was estimated cautiously. The log-derived TOC profiles exhibit the best fit to core data in the Murteree Shale as compare to Roseneath Shale where both the resistivity and the sonic logs depict the best overlay. When a proper core calibrated mineral model is chosen that fits well with the XRD mineral proportions, then the porosity fits well with the core derived porosity. After achieving a good correlation between the log-derived mineral constituents and XRD mineral constituents, the user only requires additional conductivity estimates from the Waxman and Smits techniques to solve for gas volume in a gas shale reservoir. The input parameters of the wells having a full log and core data were noted and used consistently in the other wells from the Cooper Basin, which had often either only short core sections available or core data missing. Murteree Shale exhibits excellent potential in and around Nappameri, Patchawarra and Tenappera Troughs but the poor potential in Allunga trough, where Roseneath Shale shows moderate potential in these troughs. The petrophysical interpretation shows that Murteree Shale has the potential to produce commercial quantities of hydrocarbon economically because of significant volume of kerogen (for adsorbed gas), good porosity, significant amount of brittle minerals and producible hydrocarbon.

The India-Asia collision is the most spectacular, recent, and still active tectonic event of the Earth’s history, leading to the uplift of the Himalayan-Tibetan orogen, which has been explained through several hypothetical models. Still, controversy remains, such as how and when it occurred. Here we report a paleomagnetic study of Cretaceous-Tertiary marine sediments from the Tethyan Himalaya (TH) in the Hazara area, north Pakistan, which aims to constrain timing for the onset of the India-Asia collision and to confirm the validity of already proposed models, particularly in western Himalaya’s perspective. Our results suggest that the TH was located at a paleolatitude of 8.5°S ± 3.8° and 13.1°N ± 3.8° during the interval of ca. 84−79 Ma and 59−56 Ma, respectively. A comparison between paleopoles obtained from the current study and coeval ones of the India Plate indicates that the TH rifted from Greater India before the Late Cretaceous, generating the Tethys Himalaya Basin (THB). Our findings support a model for a multi-stage collision involving at least two major subduction systems. A collision of the TH with the Trans-Tethyan subduction system (TTSS) began first in Late Cretaceous-Early Paleocene times (ca. 65 Ma), followed by a later collision with Asia at 55−52 Ma. The onset of the collision between the TH (plus TTSS) and Asia could not have occurred earlier than 59−56 Ma in the western Himalaya. Subsequently, the India craton collided with the TH, resulting in the diachronous closure of the THB between ca. 50 and ca. 40 Ma from west to east. These findings are consistent with geological and geochemical evidence and have a broad implication for plate reconfigurations, global climate, and biodiversity of collisional processes.

In this study the hydrocarbon generation potential of the coal and coaly shale samples collected from coal mines in Attock-Cherat Range of Pakistan is optically and analytically evaluated. These samples, representing the Paleocene Hangu Formation, are analyzed across a range of thermal maturity stages to understand their hydrocarbon generation potential. The visual examination of maceral type and values of vitrinite reflectance have been considered while interpreting the geochemical results for the coal and associated sediments from the Paleocene Hangu Formation. The maceral group is dominated by vitrinite, mainly collodetrinite, followed by inertinite and liptinite, and suggests Type III kerogen for the samples. The geochemical parameters suggest that the samples are post mature, however, the vitrinite reflectance measurements show late mature conditions for a gas-prone generation. The overall petrographical and geochemical data suggest that the coal and coaly shale appear to occupy the gas window and fall in the dry gas zone. Based on the maceral types and Rock–Eval data, an anoxic to terrestrial environment is inferred for the deposition of the coal and associated sediments. The vitrinite reflectance, Rock–Eval pyrolysis, and the type and frequency of macerals show that the coal is of good quality, i.e., medium to high volatile bituminous and hard brown coal, mature, and is lying in the gas window. Oxygen index is continuously low throughout the analyzed interval, which further supports that the coal is of good quality.

This study investigates petrophysical characteristics of lacustrine Permian Murteree and Roseneath shales in relation to reservoir evaluation of the most prospective gas shale plays in the Cooper Basin, Australia. Both shales were investigated for gas volumes by employing unconventional petrophysical techniques through a combination of source rock parameters acquired by geochemical analysis, and integrating the extracted parameters into log interpretation and core studies. Modeling mineralogical composition using wireline logs require the selection of a proper mineral model. In this study, the mineral model was built in the Interactive Petrophysics (IP's) Mineral Solver module by integrating all regional sedimentological, petrographic, SEM (Scanning electronic microscope), pulse decay and X-ray diffraction data (XRD) from core and chip cutting samples. This study developed a mineral grouping framework to assist in the selection of a proper model to easily solve complex shale gas reservoirs for gas volumes. Furthermore, the permeability of both shales depends on insitu confining stress and permeability of these cores and can be calculated through decay rate of a pressure pulse applied to experimental data. Subsequent to the integrated study as explained above, it is concluded on the basis of extruded parameters (shale porosity, permeability, volume of kerogen, volume of brittle minerals and water saturation) that Murteree formation exhibits better potential than Roseneath formation in and around Nappameri, Patchawarra and Tenappera troughs, while poor potential is exhibited in the Allunga trough. The only location where Roseneath exhibits better potential is in Encounter-01 well.

No abstract