Abstract Two major techniques are commonly used to model secondary and tertiary hydrocarbon migration: Darcy flow and invasion percolation. These approaches differ from each other in many ways, most notably in the physical modeling, the methods of resolution, and the type of results obtained. The Darcy approach involves not only buoyancy, capillary pressures, and pressure gradient, but also transient physics, thanks to the viscous terms. Although it can be numerically difficult and therefore time consuming, it is appropriate for slow hydrocarbon movement and it is able to provide a good description of cap-rock leakage. The invasion percolation approach, at least in the context of the implementation used in our examples, does not consider either viscosity or permeability; only buoyancy and capillary pressures drive the hydrocarbon migration. This method is relatively quick and especially useful to simulate secondary migration. Nevertheless, the viscous terms cannot be universally neglected as they can impact the timing of trap filling.

Abstract Early exploration of the Malvinas Basin (1979–1991) targeted Lower Cretaceous sandstones assuming that hydrocarbons would migrate laterally from the basin depocenter in the south to structures located in shallow water. Hydrocarbons were found, but not in large enough quantities to be commercially viable. Recently, exploration has moved closer to the depocenter and focuses on Eocene to Miocene sandstones a few thousand meters vertically above the mature Lower Cretaceous source rock. As no faults crosscut the entire section between the source rock and reservoirs, they cannot be evoked as conduits for hydrocarbon migration. Therefore, kilometer-scale vertical migration across fine-grained sediments was considered as the main process to transport hydrocarbons from source rock to reservoir. This migration mechanism is commonly mentioned, but poorly constrained. Darcy flow and invasion percolation calculators were used to simulate hydrocarbon migration. If we consider that hydrocarbons migrate along thin stringers, the relative permeability parameters have to be upscaled to consider that not all of the rock is being saturated by petroleum. Furthermore, fine-grained sediments present a very high specific area, which gives a higher sorption capacity for water, and therefore, less petroleum is needed to reach the saturation threshold for flow. Secondary migration across fine-grained sediments takes time to initiate, but as soon as hydrocarbons invade the pore space, the migration is effective; it occurs with minimal hydrocarbon losses and is essentially controlled by the expulsion rate of petroleum from the source rock and the stratigraphic architecture. From a physics standpoint, the Darcy method looks more appropriate because it incorporates the full physics of the problem. However, under these conditions, viscous forces can be ignored and the invasion percolation method seems appropriate to simulate secondary migration of hydrocarbons across fine-grained sediments.

Abstract Recent research focuses on the characterization of fluid flow through a burrow-mottled sandstone from the upper reservoir target within the Ben Nevis Formation in the Hibernia Field, offshore Newfoundland. Understanding effective permeability distributions, which are a function of relative saturations and the nature of the reservoir is key for enhanced hydrocarbon recovery strategies. In bioturbated reservoirs, the burrows are key to both parameters, thus trace fossils should not be overlooked or ignored. Understanding the nature of bioturbation gives great insight into how petroleum will flow through the reservoir. In the case of the bioturbated facies of the upper Ben Nevis Formation, mud-filled burrows represent a rather intricate, relatively impenetrable three-dimensional network of obstacles or baffles to fluid flow. As seen in the oil migration scenario, the resulting trajectory of petroleum migration is highly sinuous and tortuous as burrows induce dispersion (macroscopic mixing) caused by uneven co-current laminar flow A very important tool is introduced in this study – detailed, controlled probe permeametry combined with invasion-percolation modeling software. Textural and reservoir engineering data are then inputted into MPath, numerical modeling software that uses a modified percolation-invasion technique to simulate secondary petroleum migration through bioturbated media. The methodology outlined holds great potential for resolving reservoir heterogeneities and predicting their effect on hydrocarbon production. In the case of the Ben Nevis/Avalon, the technique utilized here can also be expanded to other bioturbated facies and upscaled for use toward reservoir recovery strategies.

Abstract Structural geometries, faults and their movement histories, together with the petrophysical properties of flow units, are some of the major controls on hydrocarbon migration pathways within sedimentary basins. Currently, structural restoration, fault-seal analysis and hydrocarbon migration are treated as separate approaches to investigating basin geohistory and petroleum systems. Each of these separate modelling approaches in their own fields is advanced and sophisticated but they are not compatible with each other. Lack of integration produces incorrect palaeogeometries in basin models and inaccurate migration pathways. A combined structural restoration and fault-seal analysis technique, integrated with fast hydrocarbon migration pathway modelling code based on invasion percolation (IP) methods, is described. These modelling methods are used to develop a 4D basin modelling workflow in which evolving basin geohistories and geometries form an integral part of the analysis of hydrocarbon migration and trapping. By combining structural restoration and 3D fault-seal analysis it is possible to investigate the evolution of structurally complex traps through time. Integration of these techniques with a numerically fast migration pathway modelling technique allows hydrocarbon migration pathways and accumulations to be modelled through the evolution of the basin with time. Additionally, the effects of uncertainties in structural geometry, fault seal or any of the model input parameters can be explored using a risk-driven approach to modelling. These methods are demonstrated using synthetic, computer generated, 3D models and a well-constrained model of the Moab Fault, Utah, USA. Comparison of modelled structural geometries, fault-seal properties and predicted trapped hydrocarbons with outcrop data is used to validate the integrated modelling approach. The validated techniques are then applied to a seismically derived, 3D model from the southern North Sea, UK, to demonstrate how an integrated, risk-driven approach to modelling allows the effects of uncertainties in the distribution of hydrocarbon accumulations to be investigated.

Abstract Faults are important elements of petroleum systems that influence the migration and trapping of hydrocarbons in sedimentary basins. When faults undergo displacement, their fluid transmissibility properties change as a result of juxtaposing lithologies across the fault, by smearing semi-permeable or impermeable argillaceous rocks within fault zones and by pumping or valving aqueous fluids. We describe here a 4D hydrocarbon migration model that incorporates juxtaposition and argillaceous smear processes. The technique uses the geometries of strata that are cut by faults and their physical properties to construct 3D models in which the evolution of cross-fault relationships can be calculated and the development of fault-zone argillaceous smear predicted. Hydrocarbon migration pathways through faulted structures are then investigated with a 4D migration model based on invasion percolation (IP) techniques. The controls on hydrocarbon migration have been investigated for fieldwork-derived models of rock volumes from the Moab Fault, Utah, USA to test the modelling techniques against reality. As a result predominantly of argillaceous smear, hydrocarbons are shown to accumulate in the hanging wall of parts of the modelled section of the Moab Fault, but leak across juxtaposed sandstones elsewhere on the fault to produce footwall accumulations. The techniques are then applied to a seismically derived model of the Artemis Field, UK Southern North Sea, to demonstrate how hydrocarbon charging history and pathways are influenced by fault geometries. Multiple model realizations enable the risk associated with charging of individual fault compartments to be assessed.