Estimation of the Impact of Basement Heterogeneity on Thermal History Reconstruction: The Western Siberian Basin

Some of the simplifying assumptions frequently used in basin modelling may adversely impact the quality of the constructed models. One such common assumption consists of using a laterally homogeneous crustal basement, despite the fact that lateral variations in its properties may significantly affect the thermal evolution of the model. We propose a new method for the express evaluation of the impact of the basement’s heterogeneity on thermal history reconstruction and on the assessment of maturity of the source rock. The proposed method is based on reduced-rank inversion, aimed at a simultaneous reconstruction of the petrophysical properties of the heterogeneous basement and of its geometry. The method uses structural information taken from geological maps of the basement and gravity anomaly data. We applied our method to a data collection from Western Siberia and carried out a two-dimensional reconstruction of the evolution of the basin and of the lithosphere. We performed a sensitivity analysis of the reconstructed basin model to assess the effect of uncertainties in the basement’s density and its thermal conductivity for the model’s predictions. The proposed method can be used as an express evaluation tool to assess the necessity and relevance of laterally heterogeneous parametrisations prior to a costly three-dimensional full-rank basin modelling. The method is generally applicable to extensional basins except for salt tectonic provinces.

The mobility of fluids through rocks

Over the last decade, there has been an irreversible shift from hydrocarbon exploration towards carbon storage, low-carbon energy generation and hydrogen exploration. Whilst basin modelling techniques may be used to predict the migration of hydrocarbons through sedimentary basins on geological timescales, there remains little understanding of how fluids behave at the basin scale on present-day timescales. Maximum vertical fluid velocity, vmax, may be calculated as the product of mobility and buoyancy. We present am algorithm to determine the basin-scale mobilities of CO2 and methane with depth for sandstone and carbonate. CO2 and methane mobility and buoyancy increase by an order of magnitude at gas phase transitions and are significantly greater in sandstone than in carbonate. Critical properties of CO2 cause fluid mobility and buoyancy to be sensitive to changes in surface temperature. vmax for CO2 and methane are on scales of m/year. Our results indicate an optimal depth for CO2 storage of below 0.59 km and 1.24 km when surface temperature > 20oC and 0oC, respectively. vmax for hydrogen is approximately 2-10 times greater than other hydrocarbon fluids and this will have important consequences for the future use of basin modelling software for determining hydrogen migration for exploration and storage.

Integrated 1-D and 3-D Basin Modelling to Characterize the Deposition and Distribution of Asphaltenes Within Tar Zones from an Oil Field Offshore Abu Dhabi, UAE and Qatar

Increasing the recoverable reserves from oil fields by extracting from tar zones is becoming more desirable in the Middle East. One approach for improved definition of tar zones is to understand the factors which affected the deposition and distribution of asphaltenes within the target interval. In this paper we outline how integrated 1-D and 3-D basin modelling was used to identify the timing of hydrocarbon generation and expulsion from the Jurassic source rock to charge a prolific Jurassic carbonate reservoir formation of an oil field, offshore Abu Dhabi, UAE and Qatar. The source rock is modelled to be in the peak oil mature window today, with the onset of oil generation from the Cenomanian to the Turonian, depending on modelled and assumed source rock kinetics. The onset of oil expulsion was from the earliest Paleocene. Measured bulk fluid parameters in the reservoir formation have a significantly higher Gas-Oil Ratio (GOR) and elevated API gravity values when compared with predicted values. A possible mechanism to explain this discrepancy would be to invoke the contribution of higher GOR fluids from more mature source rocks within the fetch area of the field. Thermochemical sulphate reduction of anhydrite layers in the reservoir is predicted to have begun during the Eocene. Major uplift and erosion in the Oligocene and Mio-Pliocene significantly reduced reservoir pressure and temperature. This reduction in pressure and temperature is modelled to have caused precipitation of solids, gravity segregation and flocculation at the then oil-water contact, depositing the main tar zone and patchy tar in the reservoir beneath this zone as charge continued through time. We present a detailed review, interpretation and 3-D basin model; the first study of its kind conducted on this oil field. The 3-D basin model predicts the timing of the deposition and distribution of asphaltenes in the carbonate reservoirs of the studied field and demonstrate that local problems need to be understood in their regional context.

Using Basin Modelling to Understand Injected CO2 Migration and Trapping Mechanisms: A Case Study from the Sleipner CO2 Storage Operation

CO2 migration and trapping in saline aquifers involves the injection of a non-wetting fluid that displaces the in-situ brine, a process that is often termed ‘drainage’ in reservoir flow dynamics. With respect to simulation, however, this process is more typical of regional basin modelling and percolating hydrocarbon migration. In this study, we applied the invasion percolation method commonly used in hydrocarbon migration modelling to the CO2 injection operation at the Sleipner storage site. We applied a CO2 migration model that was simulated using a modified invasion percolation algorithm, based upon the Young-Laplace principle of fluid flow. This algorithm assumes that migration occurs in a state of capillary equilibrium in a flow regime dominated by buoyancy (driving) and capillary (restrictive) forces. Entrapment occurs when rock capillary threshold pressure exceeds fluid buoyancy pressure. Leaking occurs when fluid buoyancy pressure exceeds rock capillary threshold pressure. This is now widely understood to be an accurate description of basin-scale hydrocarbon migration and reservoir filling. The geological and geophysical analysis of the Sleipner CO2 plume anatomy, as observed from the seismic data, suggested that the distribution of CO2 was strongly affected by the geological heterogeneity of the storage formation. In the simulation model, the geological heterogeneity were honored by taking the original resolution of the seismic volume as the base grid. The model was then run at an ultra-fast simulation time in a matter of seconds or minutes per realization, which allowed multiple scenarios to be performed for uncertainty analysis. It was then calibrated to the CO2 plume distribution observed on seismic, and achieved an accurate match. The paper establishes that the physical principle of CO2 flow dynamics follows the Young-Laplace flow physics. It is then argued that this method is most suitable for the regional site screening and characterization, as well as for site-specific injectivity and containment analysis in saline aquifers.

Suppression Of Vitrinite Reflectance In The Malay And Penyu Basins, Offshore Peninsular Malaysia: A Review Of Available Data And Potential Implications

Suppression of vitrinite reflectance is a well-known phenomenon and, if not recognised and corrected for, could potentially have a big impact on the results of thermal history and basin modelling, and seriously affect exploration decisions. The Malay Basin is known to have shown evidence of vitrinite reflectance (Ro) suppression in a selection of wells that were also analysed using the FAMM (Fluorescence Alteration of Multiple Macerals) technique. Analysis of available data suggests that potential vitrinite reflectance suppression may be identified using an empirical regression line which separates “suppressed” from “normal” Ro values based on the FAMM data. The “FAMM minimum regression line” was used to screen through Ro data from 142 wells (drilled between 1969 and 2005) in the Malay Basin and it is estimated that a quarter of those wells might be affected by suppression. Possible suppression was also noted in the Penyu Basin, where bottom-hole temperatures in some wells are consistently higher than Ro-derived temperatures. The regression line could be used as a tool for quick screening of legacy Ro data for potential suppression of vitrinite reflectance. At the very least, it could raise suspicion about the quality of the Ro data and trigger further investigation as to whether the suppression is “real”, and help justify additional or specialised laboratory analyses such as FAMM and VIRF (Vitrinite-Inertinite Reflectance and Fluorescence) to correct for suppression.