Abstract Temperature-time–based first-order kinetic models are currently used to predict hydrocarbon generation and maturation in basin modeling. Physical chemical theory, however, indicates that water pressure should exert significant control on the extent of these hydrocarbon generation and maturation reactions. We previously heated type II Kimmeridge Clay source rock in the range of 310 to 350°C at a water pressure of 500 bar to show that pressure retarded hydrocarbon generation. This study extended a previous study on hydrocarbon generation from the Kimmeridge Clay that investigated the effects of temperature in the range of 350 to 420°C at water pressures as much as 500 bar and for periods of 6, 12, and 24 hr. Although hydrocarbon generation reactions at temperatures of 420°C are controlled mostly by the high temperature, pressure is found to have a significant effect on the phase and the amounts of hydrocarbons generated. In addition to hydrocarbon yields, this study also includes the effect of temperature, time, and pressure on maturation. Water pressure of 390 bar or higher retards the vitrinite reflectance by an average of ca. 0.3% Ro compared with the values obtained under low pressure hydrous conditions across the temperature range investigated. Temperature, pressure, and time all control the vitrinite reflectance. Therefore, models to predict hydrocarbon generation and maturation in geological basins must include pressure in the kinetic models used to predict the extent of these reactions.

Abstract The purpose of the this study was to apply the biodegradation model BioClass 0D proposed by Haeseler et al. (2010) to three nonbiodegraded oils representative of the three main types of source rocks (types I, II, and III of Tissot et al., 1974 ; Tissot and Welte, 1978 ). The oils are described by seven chemical classes: (1) the gas fraction is split into H 2 S, CO 2 ,C 1 , and C 2 –C 4 ; (2, 3) the C 6 –C 14 fraction including saturates and aromatics; and (4–6) the C 14+ fraction, including n-, iso-, cyclo-alkanes, aromatics, and nitrogen, sulfur, and oxygen–containing compounds (NSOs). This 0D model reconstructs the chemical evolution of the residual oil with increasing biodegradation and the amounts of products generated during either aerobic or anaerobic processes. Results show that with increasing biodegradation, the residual oil composition depends on the initial proportion of the different chemical classes. For instance, for the type I oil enriched in paraffins, the C 14+ n-alkanes are still present when 60% of the original oil has already disappeared, whereas for the type II oil, the same chemical class disappears after only 30% of total hydrocarbon loss. During methanogenesis, the gas-oil ratio of the initial fluid significantly increases with increasing biodegradation. However, the volume of methane may be reduced because of its solubility in water or it may leak through the cap rock. The production of H 2 S is always very low when sulfur minerals that can provide electron acceptors are absent. Results also show that the amount of water needed to provide the electron acceptors depends strongly on the biological process responsible for oil biodegradation. The water ratio between aerobic biodegradation and methanogenesis might be as high as 10 7 . Consequently, aerobic biodegradation may be limited compared with methanogenesis in petroleum systems in which the oil-water volume ratio varies during fluid history.

Abstract The Carupano Basin is located in northeastern offshore Venezuela. This area is characterized by the interaction between the Caribbean and the South American Plate. It has two structural highs, the Los Testigos High located in the northern limit of the basin and the Patao High, which is between the Caracolito subbasin and the Paria subbasin. In the latter are located the main gas fields. The generated gas is characterized by low maturity, and it has been attributed to biogenic processes because of its carbon isotopic signature. Nevertheless, gas compositions show that a thermogenic signature predominates with an increase of gas maturity from the east to the west, where condensates were found associated with gas. To understand the origin of the gas, the total organic carbon (TOC) SR methodology was used to define continuous TOC profiles from sonic and resistivity wirelogs. As a result, we have shown that the whole column from the Eocene to the Pliocene consists of a poor source rock, except the middle Miocene that could be considered as a good source rock. The average TOC content of the middle Miocene can reach values around 2.5%. The kerogen is mostly type III continental–derived organic matter. The thermal calibration and the basin modeling study shows that the bottom of the Paria subbasin has reached the oil window, whereas the bottom of the Caracolito sub-basin has reached the gas window. Nevertheless, simulations of fluid-flow migration conducted using default type III kinetic parameters were not able to fill any of the known fields. We conclude that the default kinetic parameters used for basin modeling are not able to reproduce the nature of these fluids. Indeed, in our study, the main part of the fields drainage area is in a low-maturity domain where the vitrinite reflectance (R 0 )is less than 0.6%, but the kinetic parameters used were calibrated with kerogen samples for which Ro was taken to be approximately 0.6%. Considering default type III kerogen as a starting point and using observed natural data such as gas compositions, a new set of kinetic parameters were derived to account for low gas maturity. This modified type III kerogen differs from the previous one by a 13% increase of the hydrogen index. The simulations conducted with this modified type III scheme allowed us to reproduce quite well the filling of the fields, as well as the composition of the hydrocarbons.

Abstract Proper two-dimensional and three-dimensional basin modeling relies on accurate seismic processing and interpretation, correct depth conversion of the identified sedimentary layers, reliable modeling of the thermal history of the basin, and understanding of the regional geodynamic setting. Seismic reprocessing using the common reflection surface (CRS) stack technique allows revised interpretation of the structural setting and the evolution of salt plugs in the area of the Glueckstadt Graben, located near the center of the North German Basin (NGB). Reprocessing of seismic data also provides an alternative view of the geodynamic origin of the basin. Reprocessing of data clearly demonstrates the capabilities of the CRS technique to improve the quality of low-fold data. The images display a considerably improved signal-to-noise ratio and much more detail than the common midpoint processing (CMP) of the 1980s. Moreover, a velocity model consistent with the data was built and used to perform prestack and poststack depth migrations. The image of a Jurassic salt plug indicates tectonics similar to observations in the Allertal region at the northern fringe of the inverted Lower Saxony Basin, where overthrusting plays a major role in the evolution of salt structures. Consequently, shortening of the Mesozoic strata was included in the revised interpretation. The reprocessing also provided new insights into the petroleum systems in this area, indicating possible new exploration targets. The results may lead to a new geologic understanding of the area. Instead of a two-story salt plug, steep reverse faults and associated salt structures similar to the features along the Allertal lineament may best explain the investigated seismic line. Furthermore, CRS processing leads to a new view of the shape of the Moho in the center of the NGB. This view supports the assumption that the origin of the NGB may be more related to metamorphic processes during basin initiation than to crustal stretching.

Abstract Applying basin modeling technology to predict high-resolution fluid distribution and properties, taking into account the local high resolution of the sediment properties in fields and prospects has been a growing need for the past 10 yr. To minimize simulation time, local grid refinement (LGR) techniques have been introduced. The main interest of LGR is to gain computing time and memory with respect to classical methods, such are Tartan gridding. With LGR, it is possible to define local areas with high resolution in a regional model. The LGR approach gives a more detailed picture of individual fields or prospects while using models of reasonable size. The models incorporate various regional elements of the petroleum system that include source rock and seal, for instance, to obtain a detailed understanding of local processes such as trap filling history. To validate the LGR approach, a benchmark is performed. It aims at comparing the different refinement methods: (1) a high-resolution grid, (2) an LGR grid, (3) a Tartan grid, and (4) windowing. To test the behavior of and the results produced by LGR, this method is applied to a real case study from northern Kuwait. It illustrates the coupling between LGR and compositional three-dimensional Darcy flow modeling to predict the distribution of hydrocarbon composition and properties in local reservoir rock areas where accumulations are predicted. The LGR approach efficiently fills the gap between conventional basin modeling and reservoir modeling. Its application in northern Kuwait provides useful guidelines to predict API gravities, gas-oil ratio, and oil-water contact depth estimates in new prospects.

Abstract Construction of three-dimensional (3-D) basin models in areas of detached salt tectonics poses difficult challenges but is necessary to simulate the 3-D thermal effects of salt and correctly model subsalt burial histories. Over much of the offshore northern Gulf of Mexico Basin, a regional salt canopy detaches shallow structures, formed by growth and subsequent collapse of allochthonous salt sheets, from subsalt structures formed mostly in response to movement of deep (autochthonous) salt. Dynamic simulation modeling of this system requires (1) understanding the evolution of salt distribution and thickness through time, (2) a methodology to incorporate thickness changes within the simulation model, and (3) geometric solutions to account for the fact that allochthonous salt occurs at various stratigraphic levels across the basin. Twenty regionally mapped horizons, including top and base of allochthonous salt and a composite weld representing areas of collapsed salt canopy, were used to build a regional Gulf of Mexico numerical simulation model. Salt isopach maps for sequential stages of the basin evolution were derived by vertical backstripping using “regionals” constructed to approximate the predeformation geometry of selected horizons. For a given horizon, the salt thickness changes since horizon deposition is represented by the difference between a mapped horizon and its regional. Simple rules were applied to partition the derived salt thicknesses between the allochthonous and autochthonous salt levels. To model the climb of the salt canopy across stratigraphy, the basin model was divided into subsalt and suprasalt parts containing horizons of equivalent age separated by an intervening allochthonous salt layer. The thickness of both the allochthonous and autochthonous salt layers were altered through time using the salt isopachs. The resulting simulation model reasonably represents the large-scale structural evolution of the northern Gulf of Mexico Basin, including (1) progressive southward displacement and evacuation of salt along the Louann level, (2) basinward stratigraphic climb and progressive welding of salt within the canopy, (3) seaward progradation of depositional systems throughout the Mesozoic and Cenozoic, and (4) Miocene uplift and erosion of the onshore part of the basin. The methodology outlined can be adapted to assist in building basin models in other structurally complex basins.

Abstract Seismic interpretation and various modeling techniques, including structural modeling, fault-seal analysis, and petroleum systems modeling, have been combined to conduct an integrated study along a tectonically complex compressional cross section in the Brooks Range foothills of the Alaska North Slope. In the first approach, relatively simple models have been developed to show the interaction and codependency of various parameters such as changing geometry over time in a compressional regime, character and timing of faults with respect to sealing or nonsealing quality, thermal and maturity evolution of the study area, as well as petroleum generation, migration, and accumulation over time, with respect to the geometry changes and the fault properties. Modeling results show that a comprehensive understanding of all aspects involved in basin evolution is crucial to understand the petroleum systems, to be able to reproduce what is observed in the field, and to ultimately predict what can be expected from a prospect area. This integrated approach allows a better understanding of the complex petroleum systems of the Brooks Range foothills.

Abstract Structural modeling combined with basin modeling was used to demonstrate the influence of the structural history on hydrocarbon generation. For this purpose, a tectonic setting in the Netherlands was selected that shows large-scale tectonic inversion, associated erosion, and later subsidence. On the basis of a 300-km (186-mi) two-dimensional section that crosses the main tectonic features of this setting, a structural model consisting of 21 paleosections was created. The results generated by the structural model show that the Late Cretaceous inversion affected the basins the most, whereas the erosion in the Jurassic had the strongest influence on the structural highs. This can be seen from the amount of erosion associated with these erosion phases. Using the structural model as input for the basin model allowed the temperature and maturity of the sediments to be calculated. A temperature profile at 2000-m (6562-ft) depth along the section shows that the present-day temperature distribution is also strongly influenced by the inversion. In the inverted basins, highly conductive layers, such as overcompacted sediments or salt, are closer to the surface, which results in higher temperatures than in the noninverted. Finally, the timing of hydrocarbon generation from the Posidonia Shale source rock was found to be related to the structural history within the basin. In strongly inverted parts of the basin, present-day burial is insufficient to restart hydrocarbon generation, but in less inverted parts, hydrocarbon generation resumed during the Tertiary.

Abstract In basin and petroleum system modeling, the spatial resolution of models is too coarse to cover all of the relevant geologic processes that occur in reservoirs. Reservoir models are built on a static (time invariant) grid and cannot cover the charge history of a field or processes related to changing geologic structures through time. A new method to combine regional-scale petroleum system models and local reservoir- or prospect-scale models was developed and applied to an oil field in Kuwait. In the field, heavy oil zones occur at the original oil-water contact and also in stratigraphic and structural positions above it. Heavy oil occurs in the highly permeable Fourth Sand and Middle Third Sand of the Burgan Formation in the field. This study demonstrates that the heavy oil distribution in those layers can be explained by the petroleum charge history. An early charge from the Cretaceous Makhul Formation was replenished by the Cretaceous Kazhdumi Formation, the stratigraphic equivalent of the Burgan Sands. These sediments were deposited in the area of the Dezful Embayment of the Zargos Fold Belt. No Jurassic charge, breaking through the Gotnia evaporites, is needed to fill the structures of the Cretaceous Burgan reservoirs in the field. Well data and the results of the high-resolution petroleum system model covering the area of the oil field and describing the distribution of charge from the regional model to the field scale lead to the conclusion that the heavy oil zones are mainly the result of gravity segregation, although some influence of water washing cannot be excluded.

Abstract Arapidly growing demand for improved understanding of the Dutch subsurface exists because of the need for alternative energy supplies, such as geothermal energy, as well as for finding and producing more oil and gas in this mature area for petroleum exploration. We use basin modeling to integrate the wealth of new data and information that are increasingly available on the Dutch subsurface. In addition, we develop different approaches to improve the basin modeling results. Here, we present novel approaches to reconstruct the surface and bottom thermal boundary conditions for basin modeling. The first approach involves assessment of Tertiary sediment-water interface temperatures from information on local and global climate changes that was recently discovered using geobiological and geochemical techniques. The second approach involves multiple one-dimensional probabilistic tectonic heat-flow modeling to calculate the basal heat-flow history and construct paleo–heat-flow maps. This chapter presents modeling results for the Terschelling Basin and southern part of the Dutch Central Graben that demonstrate the effect of incorporating the tectonic heat-flow boundary condition and detailed knowledge of Tertiary climate changes on source rock maturity and hydrocarbon generation. The simulation results show a marked difference in generated hydrocarbon volumes and a shift in the timing of Tertiary generation compared with simulations using a default surface temperature boundary condition based on paleolatitudes of the research area.

Abstract Oil modeling in sedimentary basins commonly involves a great variety of complex physics, which leads to a fully coupled nonlinear set of partial differential equations. The most classical sequential time stepping is the fully implicit method, which computes pressure and oil saturation simultaneously. Although this method provides accurate solutions, it turns out to be computationally expensive. The aim of this chapter is to propose a new time-stepping strategy that allows computational cost to be minimized while preserving the accuracy of the numerical solution. The new approach is based on separating pressure from oil saturation and using a local time-step technique to calculate the oil saturation. An effective reduction of the central processing unit time is reached and is illustrated through several case studies.

Abstract Basin models are used to address a variety of questions concerning oil and gas generation, reservoir pressure and temperature, and oil quality. A large number of input parameters are required for a basin model, and many are functions of both space and time. Examples include isopach thicknesses and ages, amount of eroded/ missing section, rock properties (e.g., porosity, thermal conductivity), and heat flow and surface temperature boundary conditions. Most, if not all, of these model input parameters have associated uncertainties, and it can be difficult and time consuming to adequately quantify these uncertainties and propagate them through a basin model to assign error bars, probabilities, and risks to the output properties of interest. In this chapter, we propose a workflow that allows a basin modeler to identify key input parameters and quantify and propagate uncertainties in these key input parameters through a model to evaluate the model results in light of a business question. We demonstrate this workflow using a hypothetical illustration in which uncertainties in key input parameters that control hydrocarbon generation, volumes, and timing are identified, quantified, and propagated through a basin model. The workflow proposed in this chapter was designed to (1) identify the purpose(s) of the model; (2) develop a base-case scenario; (3) identify the input parameters whose uncertainty might affect the output property of interest; (4) perform screening simulations to identify the key input parameters; (5) evaluate the range of uncertainty in the key input parameters; (6) propagate the uncertainty in key input parameters through the model to the output properties of interest and estimate ranges of uncertainty for these input parameters; and (7) iterate as needed to fine tune the input parameters and dependencies between input parameters, fine tune error bars and weights for calibration data, and improve the base-case scenario.

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 Basin modeling software includes tools to statistically vary model input parameters, such as fetch area, depth, source thickness, total organic carbon, hydrogen index, temperature gradient, or heat flow, and consider the impact on fluid phase and volumes. We can rank these parameters, but we should be aware of pitfalls. The underlying geologic assumptions may account for the greatest uncertainty in new basin areas, where data are sparse and models remain poorly calibrated. Modeling tools must be flexible enough to allow multiple working hypotheses within the project time frame. These multiple hypotheses are best evaluated by an integrated project team that includes the basin modeler. The team members’ shared knowledge of regional basin history, tectonics, stratigraphy, and source rock depositional models can provide an advantage in weighing alternative geologic scenarios and hydrocarbon charge risk. This chapter provides seven examples of modeling pitfalls based on new ventures exploration studies performed using a combination of flow path and two-dimensional models. Although not representative of all possible pitfalls, these examples illustrate the substantial impact of some pitfalls on model outcome.

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 Apetroleum system modeling (PSM) study was performed on the Jeanne d’Arc Basin, offshore eastern Canada, to study the constraints and reliability of the reconstruction of petroleum reservoir filling histories. Petroleum generation and phase behavior were analyzed using phase-predictive compositional kinetic models (PhaseKinetics) determined by pyrolysis of Egret Member source rock samples. Various additional calibration data (well, rock, and fluid data), such as porosity, permeability, temperature (bottom-hole temperature, apatite fission tracks, fluid inclusions), maturity (vitrinite reflectance), and petroleum properties, such as API, gas-oil ratio, formation volume factor, and saturation pressure were integrated into this model. Different charge scenarios were tested for the effects of open and closed faults in the carrier system to reconstruct the most likely migration pathways for the petroleum that is trapped in the Terra Nova (TN) oil field. The most probable filling history includes charge to the reservoir from a local kitchen and a second kitchen located between Hibernia and TN that was responsible for the long-range migration. In the model, the hydrocarbons migrate from this kitchen in the northwest part of the study area along pathways defined by closed transbasin faults from the north into the field. This new migration concept differs from the traditional explanation based on geochemical measurements only von der Dick et al., 1989 ), which infers that local generation was solely responsible for filling the TN field. The latter can be disproved based on a simple mass balance calculation.

Abstract Understanding the distribution of oil quality and its impact on the development of deep-water reservoirs is a major challenge in many offshore basins of Brazil. Traditional geochemical approaches have used bulk properties (API gravity, viscosity, and sulfur content) and the biomarker compositions of oils to resolve the effects of source rock facies, thermal maturity, and biodegradation on oil quality in the present-day reservoir. These techniques, however, cannot fully resolve the effects of hydrocarbon charge timing, charge rate, timing of trap formation, and reservoir temperature history on the quality of the oil. In the Roncador and Frade fields, offshore Brazil, lacustrine-derived oils from Upper Cretaceous (Maastrichtian) and lower Tertiary (Oligocene–Miocene) reservoirs have gravities ranging from 14 to 33° API. In Upper Cretaceous (Maastrichtian) reservoirs of the Roncador field, better quality light oil (average, 28° API) occurs in the northeastern part, and mostly heavy oil (average, 17° API) is encountered in the southwestern part. The Frade field to the west of Roncador also contains heavy oil (16–19° API) but in shallower lower Tertiary (Oligocene–Miocene) reservoirs. Geochemical analyses have identified the depletion of n-alkanes and the presence of 25-norhopanes (demethylated hopanes) in varying proportions in oils from the Frade and Roncador fields of the Campos Basin, offshore Brazil, indicating a complex history of biodegradation and mixing from at least two hydrocarbon charges in the reservoir. This study uses both one-dimensional and multisurface thermal models in the area to help determine charge histories for the source rocks and reservoir temperature histories for the reservoirs. These results are used to evaluate the effects of charge and reservoir temperature histories and biodegradation on the ultimate composition and quality of reservoired oils. An interactive biodegradation tool in Trinity software is used to predict the API gravity, and the results are constrained by the geology and the geochemical composition of the present-day fluids in the reservoir. Several examples of charge rate and timing, trap timing, and temperature history are presented for parts of the Roncador and Frade fields to illustrate the importance of these factors on controlling the quality of oil in the present-day reservoir.