Thomas Hantschel

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.

Integrated charge and seal assessment in the Monagas fold and thrust belt of Venezuela

Conventional basin and petroleum systems modeling uses the vertical backstripping approach to describe the structural evolution of a basin. In structurally complex regions, this is not sufficient. If lateral rock movement and faulting are inputs, the basin and petroleum systems modeling should be performed using structurally restored models. This requires a specific methodology to simulate rock stress, pore pressure, and compaction, followed by the modeling of the thermal history and the petroleum systems. We demonstrate the strength of this approach in a case study from the Monagas fold and thrust belt (Eastern Venezuela Basin). The different petroleum systems have been evaluated through geologic time within a pressure and temperature framework. Particular emphasis has been given to investigating structural dependencies of the petroleum systems such as the relationship between thrusting and hydrocarbon generation, dynamic structure-related migration pathways, and the general impact of deformation. We also focus on seal integrity through geologic time by using two independent methods: forward rock stress simulation and fault activity analysis. We describe the uncertainty that is introduced by replacing backstripped paleogeometry with structural restoration, and discuss decompaction adequacy. We have built two end-member scenarios using structural restoration, one assuming hydrostatic decompaction, and one neglecting it. We have quantified the impact through geologic time of both scenarios by analyzing important parameters such as rock matrix mass balance, source rock burial depth, temperature, and transformation ratio.

Pore pressure prediction while drilling: Three-dimensional earth model in the Gulf of Mexico

Subsalt Gulf of Mexico deep-water wells routinely cost in excess of

Mudstone compaction and its influence on overpressure generation, elucidated by a 3D case study in the North Sea

100 million. A reliable pore pressure prediction can translate into considerable savings in terms of drilling costs and safety. Traditional methods used to determine pore pressure are based on either logs (e.g., Eaton’s or Bowers’ methods) or seismic data (e.g., calibrated seismic velocities, acoustic impedance). Another method for pore pressure prediction is based on basin modeling: building a three-dimensional earth model and simulating the processes of pressure formation, through geologic time. Recent advancements in basin modeling, such as the coupling of stress and pressure and the implementation of models for mineral diagenesis and rock failure, have significantly improved its applicability. However, no single method is commonly accepted as better than another, therefore, using, comparing, and integrating all three methods together in a predrilling project can provide a higher degree of confidence for pore pressure prediction. The purpose of this paper is to describe a new approach to pore pressure prediction that combines the above methods with petroleum system modeling. A special emphasis is put on the explanation of the basin modeling workflow. The first step of the workflow is to create and calibrate a regional model based on a set of regional maps with the main goal of providing the regional context. The second step is to create a smaller area of interest (AOI) model using high-resolution structural and facies maps. This refined model is then used for pore pressure prediction at the prospect scale. The smaller AOI model, albeit at very high resolution, allows a model to be run overnight, so that pore pressure can be predicted ahead of the drilling bit. Finally, the predicted pore pressure and fracture gradient allow the drilling engineer to optimize well performance and reduce drilling costs.