Allegra Hosford Scheirer

Basin and Petroleum System Modeling

Since the early 1970s, basin and petroleum system modeling (BPSM ) has evolved from a simple tool, used mainly to predict regional source rock thermal maturity, to become a critical component in the worldwide exploration programs of many national and international oil companies for both conventional and unconventional resources. The selection of one-dimensional 1-D, 2-D or 3-D BPSM depends on available input data and project objectives. Organic richness and rock properties must be reconstructed to original values prior to burial. For example, in geohistory analysis each unit is decompacted to original thickness and corrected for paleobathymetry and eustasy. Boundary conditions for thermal evolution include heat flow and sediment-water interface temperature corrected for water depth through time. Default petroleum generation kinetics available in most software should be used only when suitable samples of the source rock organofacies are unavailable. Kinetic parameters are best measured using representative, thermally immature equivalents of the effective source rock. 3-D poroelastic and poroplastic rock stress modeling are significant advances over the 1-D Terzaghi method employed by most software. Calibration should start with the available pressure data, followed by thermal calibration (e. g., corrected borehole temperatures or vitrinite reflectance) and calibration to other measurements (e. g., petroleum composition). The dynamic petroleum system concept has proven to be a more reliable tool for exploration than static play fairway maps used in the past, partly because BPSM accounts for the timing of trap formation relative to generation-migration-accumulation. Tectonic activity and other processes can result in remigration or destruction of accumulations and more than one critical moment on the petroleum system event chart. Organoporosity within the kerogen and solid bitumen accounts for much of the petroleum in unconventional mudstone reservoirs, and secondary cracking of oil to gas is particularly important. Hybrid unconventional systems, which juxtapose ductile organic-rich and brittle, more permeable organic-lean intervals are typically the best producers.

Combining seismic reservoir characterization workflows with basin modeling in the deepwater Gulf of Mexico Mississippi Canyon area

In this study, we explore the value added by application of basin modeling to seismic reservoir characterization in a structurally complex area. We focus on the Thunder Horse minibasin in the Gulf of Mexico. First, we build a two-dimensional basin model along the strike direction of the main structure in the area to investigate differences in pressure and thermal histories. The results suggest differences in both histories across the study area, and these differences can be reasonably assessed by basin modeling even with a single well calibration. We combine basin modeling results with rock physics models to build a training data set of seismic impedance derived lithofacies. The training data set thus captures spatial trends in the desired property beyond available well data. In addition, we demonstrate how to improve the seismic inversion results by integrating the basin modeling insights with limited well data. Our new workflow combining basin modeling output with rock physics and impedance-based lithofacies prediction significantly improves the predicted spatial distribution of reservoir lithofacies in the scenarios of spatially limited well control.

Past, present, and future of basin and petroleum system modeling

Basin and petroleum system modeling (BPSM) has had increasing impact on industry decisions related to exploration and new venture opportunities over the last decade. Basin and petroleum system modeling technology, usability, and user group size have grown as a result of its capacity to reduce exploration risk. Based on current statistics, improvements in BPSM have significant potential to reduce future well failures, particularly when caused by lack of petroleum charge. To bring BPSM practitioners from academia and industry together, an AAPG Hedberg Research Conference was organized to discuss the latest developments and issues in this field. A survey was conducted during the conference in Santa Barbara, California (April 2016), and this paper summarizes the results. A key takeaway was an overarching consensus throughout the BPSM community that improved understanding of hydrocarbon migration and more flexible workflows are necessary to better assess charge and migration risk in exploration and new ventures. In addition, BPSM is increasingly used to predict pore pressure and porosity at field scales, which opens new opportunities to integrate BPSM workflows with other technologies, such as seismic rock property analysis and reservoir quality modeling. In this paper, we discuss these and other issues that arose from in-depth discussion and an online survey.