Petroleum System Modeling Research Articles

2-D Basin modeling study of petroleum systems in the Levantine Basin, Eastern Mediterranean

ABSTRACT The Levantine Basin has proven hydrocarbons, yet it is still a frontier basin. There have been significant oil and gas discoveries offshore the Nile Delta, e.g. several Pliocene gas plays and the Mango Well with ca. 10,000 bbls/day in Lower Cretaceous rocks and recently, Noble Energy discovered two gas “giants” (> 5 TCF and one estimated at 16 TFC) one of which is in a pre-Messinian strata in ca. 1,700 m (5,577 ft) water depth. Regional two-dimensional (2-D) petroleum system modeling suggests that source rocks generated hydrocarbons throughout the basin. This paper provides insight into the petroleum systems of the Levantine Basin using well and 2-D seismic data interpretations and PetroMod2D. Tectonics followed the general progression of the opening and closing of the Neo-Tethys Ocean: rift-extension, passive margin, and compression. The stratal package is up to 15 km thick and consists of mixed siliciclastic-carbonate-evaporite facies. Five potential source rock intervals (Triassic – Paleocene) are suggested. Kerogen in the older source rocks is fully transformed, whereas the younger source rocks are less mature. There are several potential reservoir and seal rocks. The model suggests that oil and gas accumulations exist in both structural and stratigraphic traps throughout the basin.

MASS BALANCE CALCULATIONS FOR DIFFERENT MODELS OF HYDROCARBON MIGRATION IN THE JEANNE D'ARC BASIN, OFFSHORE NEWFOUNDLAND

Basin and petroleum systems modelling is a powerful tool in petroleum exploration, but uncertainties remain in terms of the evaluation of a petroleum accumulation's size and quality, even when the petroleum system is well known and the latest modelling technology is applied. In order to interpret the results of a modelling exercise, it is necessary to understand the advantages and disadvantages of the various possible approaches used to assess petroleum migration and accumulation. This paper attempts to compare the influence of different migration modelling techniques – the flowpath, Darcy “hybrid” and invasion percolation approaches – on basin‐wide mass balance calculations for a temperature‐ and pressure‐calibrated, numerical four‐dimensional basin model. The study was performed using PetroMod® software.The study area is the well‐known Jeanne d'Arc Basin located offshore Newfoundland, eastern Canada. Model predictions were verified against pre‐existing data including the quantity and quality of discovered hydrocarbons in the basin. Modelling results showed that the Darcy method produced substantially different results compared to the other migration techniques and this was due to the high accumulation efficiency. The flowpath method, and a combination of flowpath and Darcy methods (referred to as the “hybrid” method) yielded similar results; furthermore, the hybrid method predicted the petroleum composition quite accurately. The invasion percolation method gave similar results to the hybrid approach, but little or no variation in API and GOR across the basin was predicted.The adsorption model initially applied did not adequately reproduce the natural behaviour of source rocks with respect to petroleum expulsion efficiency. Therefore a revised model was implemented in which the adsorption capacity was reduced with increasing maturity. This revised adsorption model led to more realistic volumes of hydrocarbons being retained within the source rock. The application of this approach had only a minor impact on the volume and quality of the petroleum present in the reservoir units.

Energy potential of the Millungera Basin: a newly discovered basin in north Queensland

Deep seismic reflection surveys in north Queensland that were collected in 2006 and 2007 discovered a previously unknown sedimentary basin, now named the Millungera Basin, which is completely covered by a thin succession of sediments of the Jurassic–Cretaceous, Eromanga-Carpentaria Basin. Interpretation of regional aeromagnetic data suggests that the basin could have areal dimensions of up to 280 km by 95 km. Apart from regional geophysical data, virtually no confirmed geological information exists on the basin. To complement the seismic data, new magnetotelluric data have been acquired on several lines across the basin. An angular unconformity between the Eromanga and Millungera basins indicates that the upper part of the Millungera Basin was eroded prior to deposition of the Eromanga-Carpentaria Basin. Both the western and eastern margins of the Millungera Basin are truncated by thrust faults, with well-developed hangingwall anticlines occurring above the thrusts at the eastern margin. The basin thickens slightly to the east, to a maximum preserved subsurface depth of ˜3,370 m. Using sequence stratigraphic principles, three discrete sequences have been mapped. The geometry of the stratigraphic sequences, the post-depositional thrust margins, and the erosional unconformity at the top of the succession all indicate that the original succession across much of the basin was thicker–by up to at least 1,500 m–than preserved today. The age of the Millungera Basin is unknown, but petroleum systems modelling has been carried out using two scenarios, that is, that the sediment fill is equivalent in age to (1) the Neoproterozoic-Devonian Georgina Basin, or (2) the Permian–Triassic Lovelle Depression of the Galilee Basin. Using the Georgina Basin analogue, potential Cambrian source rocks are likely to be mature over most of the Millungera Basin, with significant generation and expulsion of hydrocarbons occurring in two phases, in response to Ordovician and Cretaceous sediment loading. For the Galilee Basin analogue, potential Permian source rocks are likely to be oil mature in the central Millungera Basin, but immature on the basin margins. Significant oil generation and expulsion probably occurred during the Triassic, in response to late Permian to Early Triassic sediment loading. Based on the seismic and potential field data, several granites are interpreted to occur immediately below the Millungera Basin, raising the possibility of hot rock geothermal plays. Depending on its composition, the Millungera Basin could provide a thermal blanket to trap any heat which is generated. 3D inversion of potential field data suggests that the inferred granites range from being magnetic to nonmagnetic, and felsic (less dense) to more mafic. They may be part of the Williams Supersuite, which is enriched in uranium, thorium and potassium, and exposed just to the west, in the Mount Isa Province. 3D gravity modelling suggests that the inferred granites have a possible maximum thickness of up to 5.5 km. Therefore, if granites with the composition of the Williams Supersuite occur beneath the Millungera Basin, in the volumes indicated by gravity inversions, then, based on the forward temperature modelling, there is a good probability that the basin is prospective for geothermal energy.

Carbon dioxide (CO2 ) geological storage potential of the Bass Basin

Abstract Evaluation of the Bass Basin’s suitability for CO 2 storage has been undertaken by analysing several key basin analysis elements, including seal capacity and integrity, reservoir quality, petroleum systems modelling and CO 2 migration and storage modelling. Seal geometry, capacity and integrity of the Demons Bluff Formation has been investigated to evaluate CO 2 containment in the basin. The study revealed good to excellent sealing capacity for the Demons Bluff Formation and for the intraformational seals within the Eastern View Group (EVG). Faults traversing the reservoir/regional seal boundary, as well as faults intersecting the top of the regional seal were evaluated for future risk of reactivation. There is some risk of reactivation associated with N-E striking faults, fortunately these faults are mostly confined to the margins of the basin. Reservoirs of the Upper EVG generally have high porosity and permeability. Hydrocarbon migration and accumulation in the basin were simulated, to examine the petroleum potential of specific reservoirs within the basin. Migration models suggest most of the trapped hydrocarbons occur in the reservoir sands of the Middle EVG. Reservoirs of the Upper EVG were have received little hydrocarbon charge, except for the northeastern part of the basin. CO 2 migration paths within reservoirs of the Upper EVG were simulated based on a buoyancy driven migration model. Migration pathways within the Upper EVG and CO 2 accumulations under the regional seal were identified. In addition, total available pore volumes for CO 2 storage associated with structural traps was calculated at >2 billionm3.

Understanding the plumbing of the Gippsland Basin: new results on fluid migration and reservoir quality

Understanding the CO2 storage potential and petroleum prospectivity of the Gippsland Basin are critical to managing the resources of this region. Key controls on determining the prospectivity for CO2 storage and petroleum include understanding the fluid migration history and reservoir characteristics in the basin. Gippsland Basin hydrology, reservoir characteristics and petroleum systems are being studied to better understand how CO2 can be safely stored in the subsurface. Hydrocarbon migration pathways have been delineated using petroleum systems modelling. The latest hydrocarbon charge history data has been acquired to test the containment potential of individual structures along these migration pathways. The charge history results indicate the Golden Beach gas field has had a complex hydrocarbon fill history, and that early charge has migrated through the regional seal. The results also indicate that early oil charge was very common in the basin, including large structures that are now filled with gas (e.g. Barracouta). The results allow the regions with good CO2 containment potential to be delineated for further storage investigations. A new evaluation of the reservoir characteristics of the Latrobe Group—through porosity/permeability analysis and automated mineral analysis (AMA)—has provided insights into CO2 injectivity and capacity. The AMA results constrain the mineralogy and diagenetic history of the reservoirs and seals. In addition, the data highlights the presence of carbonates, glauconite and K-feldspar that are potentially reactive with injected CO2.

メキシコ湾南部大水深海域における石油システムモデリング

メキシコ湾南部大水深海域における石油システムモデリング

Geology and petroleum prospectivity of the deepwater Otway and Sorell basins: new insights from an integrated regional study

The frontier deepwater Otway and Sorell basins lie offshore of southwestern Victoria and western Tasmania at the eastern end of Australia’s Southern Rift System. The basins developed during rifting and continental separation between Australia and Antarctica from the Cretaceous to Cenozoic. The complex structural and depositional history of the basins reflects their location in the transition from an orthogonal–obliquely rifted continental margin (western–central Otway Basin) to a transform continental margin (southern Sorell Basin). Despite good 2D seismic data coverage, these basins remain relatively untested and their prospectivity poorly understood. The deepwater (> 500 m) section of the Otway Basin has been tested by two wells, of which Somerset–1 recorded minor gas shows. Three wells have been drilled in the Sorell Basin, where minor oil shows were recorded near the base of Cape Sorell–1. As part of the federal government-funded Offshore Energy Security Program, Geoscience Australia has acquired new aeromagnetic data and used open file seismic datasets to carry out an integrated regional study of the deepwater Otway and Sorell basins. Structural interpretation of the new aeromagnetic data and potential field modelling provide new insights into the basement architecture and tectonic history, and highlights the role of pre-existing structural fabric in controlling the evolution of the basins. Regional scale mapping of key sequence stratigraphic surfaces across the basins, integration of the regional structural analysis, and petroleum systems modelling have resulted in a clearer understanding of the tectonostratigraphic evolution and petroleum prospectivity of this complex basin system.

Methanogenic biodegradation of petroleum in the West Siberian Basin (Russia): Significance for formation of giant Cenomanian gas pools

Approximately 1700 tcf (48 trillion m3) of dry gas (99% methane) reserves and resources occur in western Siberia, mostly in shallow (1500 m [4921 ft]) Cenomanian pools in the northern part of the basin. This dry gas constitutes about 11% of the world's conventional gas endowment and about 17% of the annual gas production. The origin of the dry gas has been debated extensively over the last 45 yr but remains controversial. Widely discussed hypotheses on the origin include early-mature thermogenic gas from coal, primary microbial gas from dispersed organic matter or coal, and thermogenic gas from deep source rocks. However, all these hypotheses are in some ways inconsistent with the molecular or isotopic composition of the gases or the results of basin and petroleum systems modeling. Here, I present geochemical and geological evidence that a significant (although yet not quantified) part of the shallow dry gas in the northern West Siberian Basin originated from methanogenic biodegradation of petroleum. Circumstantial evidence includes the occurrence of heavily biodegraded oil legs and residual oil in many Cenomanian gas pools, as well as geochemical evidence of heavy to slight biodegradation in Jurassic–Albian reservoirs commonly underlying the Cenomanian pools. Direct evidence includes, most importantly, 13C-enriched CO2 in pools with biodegraded oil (although data are limited), which indicates 40–70 wt.% conversion of oil-derived CO2 to secondary microbial methane. Distinctive hydrocarbon molecular and isotopic compositions of most gases in Cenomanian pools (average dryness C1/(sum C1-C5) is 0.9976; average 13C of methane is 51.8) suggest that they represent mixtures of biodegraded thermogenic gases from deep, mainly Jurassic, source rocks and secondary microbial methane with an occasional small addition of primary microbial methane. Contribution of early-mature coal-derived gas is possible in areas with the most significant thermal stress of Hauterivian–Aptian sediments but remains speculative. Review of petroleum habitats of five representative oil-gas-condensate fields in western Siberia (including the world's second largest gas field, Urengoyskoe) suggests that methanogenic biodegradation may best explain the observed distribution and properties of fluids in the shallow reservoirs of those fields. Recognition of secondary microbial gas in western Siberia helps explain the observed dominance of gas in the shallow, cool northern part of the basin, where conditions were more favorable for prolonged petroleum biodegradation than in the central and southern parts of the basin. Secondary microbial gas has been recognized worldwide and may (1) represent a volumetrically significant exploration target in shallow reservoirs (perhaps more significant than primary microbial gas) and (2) indicate effective thermogenic petroleum systems in the deeper sections. Large volumes (up to 66,500 tcf [1884 trillion m3]) of secondary microbial methane could have been generated from biodegraded petroleum accumulations worldwide. Although a part of that gas accumulated as oil-dissolved, free, and hydrate-bound gas, most gas apparently escaped into the overburden, atmosphere, and ocean and could have affected global climate in the geologic past.

The Potiguar integrated exploration project: CSEM prospectivity assessment offshore Brazil

Newly acquired CSEM data were integrated with several different types of complementary measurements and techniques in an exploration prospect evaluation study—which included petroleum systems modeling (PSM)—of the deepwater offshore area of the Potiguar Basin, northeast Brazil (Figure 1). Potiguar is the second most productive basin in Brazil, but to date, all production is from its onshore and nearshore areas. A 2D seismic data set was reprocessed then interpreted to provide regional scale horizons, which were used as input, along with other geological and geochemical information, for the study. The CSEM data clearly defined resistive anomalies over five features interpreted as potential traps on the seismic data. The CSEM resistivity volumes have provided added value to the PSM and prospectivity study of this basin.

Programed oil generation of the Zubair Formation, Southern Iraq oil fields: results from Petromod software modeling and geochemical analysis

D petroleum system modeling was performed on wells in each of four oil fields in South Iraq, Zubair (well Zb-47), Nahr Umr (well NR-9), West Qurna (well WQ-15 and 23), and Majnoon (well Mj-8). In each of these fields, deposition of the Zubair Formation was followed by continuous burial, reaching maximum temperatures of 100°C (equivalent to 0.70%Ro) at depths of 3,344- 3,750 m of well Zb-47 and 3,081.5-3,420 m of well WQ- 15, 120°C (equivalent to 0.78%Ro) at depths of 3,353- 3,645 m of well NR-9, and 3,391-3,691.5 m of well Mj-8. Generation of petroleum in the Zubair Formation began in the late Tertiary, 10 million years ago. At present day, modeled transformation ratios (TR) indicate that 65% TR of its generation potential has been reached in well Zb-47, 75% TR in well NR-9 and 55-85% TR in West Qurna oil field (wells WQ-15 and WQ-23) and up to 95% TR in well Mj-8, In contrast, younger source rocks are immature to early mature (<20% TR), whereas older source rocks are mature to overmature (100% TR). Comparison of these basin modeling results, in Basrah region, are performed with Kifle oil field in Hilla region of western Euphrates River whereas the Zubair Formation is immature within temperature range of 65-70°C (0.50%Ro equivalent) with up to 12% (TR=12%) hydrocarbon generation efficiency and hence poor generation could be assessed in this last location. The Zubair Formation was deposited in a deltaic environment and consists of interbedded shales and porous and permeable sandstones. In Basrah region, the shales have total organic carbon of 0.5-7.0 wt%, Tmax 430- 470°C and hydrogen indices of up to 466 with S2=0.4-9.4 of kerogen type II & III and petroleum potential of 0.4-9.98 of good hydrocarbon generation, which is consistent with 55-95% hydrocarbon efficiency. These generated hydro- carbons had charged (in part) the Cretaceous and Tertiary reservoirs, especially the Zubair Formation itself, in the traps formed by Alpine collision that closed the Tethys Ocean between Arabian and Euracian Plates and developed folds in Mesopotamian Basin 15-10 million years ago. These traps are mainly stratigraphic facies of sandstones with the shale that formed during the deposition of the Zubair Formation in transgression and regression phases within the main structural folds of the Zubair, Nahr Umr, West Qurna and Majnoon Oil fields. Oil biomarkers of the Zubair Formation Reservoirs are showing source affinity with mixed oil from the Upper Jurassic and Lower Cretaceous strata, including Zubair Formation organic matters, based on presentation of GC and GC-MS results on diagrams of global petroleum systems.

2009 Napa AAPG Hedberg Research Conference on Basin and Petroleum Systems Modeling

Marek Kacewicz is a research consultant with Chevron Energy Technology Company in Houston, Texas. Prior to joining Chevron, Marek worked as a research geologist for ARCO Exploration and Production Research Center in Plano, Texas, and worked as a basin modeler for Unocal Exploration and Exploitation Technology in Sugar Land, Texas. He has more than 20 years of experience in basin modeling, exploration, and research. His experience covers a wide range of geographic areas worldwide. Some of his professional honors include receiving the 1986 International Association for Mathematical Geology Vistelius Research Award, being selected as an Alexander von Humboldt Fellow (Germany), and receiving the 2005 AAPG Gabriel Dengo Memorial award. He has an M.S. degree in computer science/numerical mathematics and a Ph.D. in earth sciences, both from the University of Warsaw (Poland). Kenneth Peters is a geochemical advisor for Schlumberger. He is the principal author of The Biomarker Guide (2005, Cambridge University Press) and consulting professor at Stanford University where he leads the Basin and Petroleum System Modeling Industrial Affiliates Program. He is a chair of the AAPG Research Committee, AAPG distinguished lecturer for 2009 and 2010, associate editor for AAPG Bulletin and Organic Geochemistry , and editor for the 2009 AAPG Datapages publication Getting Started in Basin and Petroleum System Modeling . He is the recipient of the 2009 Schlumberger Henri Doll Prize for Innovation and the 2009 Alfred E. Treibs Award presented on behalf of the Organic Geochemistry Division of the Geochemical Society. He has a Ph.D. in geochemistry from the University of California, Los Angeles, and spent 15 years with Chevron, 9 years with Mobil and ExxonMobil, and 6 years with the U.S. Geological Society. David Curry is a senior geological advisor on petroleum systems in the Offshore Division at Devon Energy in Houston, focusing primarily on petroleum …

Petroleum systems of the Bass Basin: a 3D modelling perspective

Petroleum generation, expulsion, migration and accumulation have been modelled in 3D at basin-scale for the Bass Basin, Tasmania. The petroleum systems model shows several source rocks of different ages have generated and expelled sufficient hydrocarbons to fill structures in the basin; however, the lithologies and fault properties in the model result in generally limited migration after hydrocarbon expulsion started. Impermeable faults, together with several fine-gained sealing facies in the Lower and Middle Eastern View Group (EVG) have resulted in minor vertical hydrocarbon migration in the lower parts of the EVG. An exception occurs in the northeastern part of the basin, where strike-slip movement of suitably oriented faults during Miocene reactivation resulted in breaches in deeper accumulations and migration to upper reservoir sands and, in several cases, leakage through the regional seal. The Middle Eastern View Group source rocks have produced most of the gas in the basin. Oil appears to be largely limited to the Yolla Trough, related to the relatively high thermal maturation of Narimba Sequence source rocks. In general, most of the hydrocarbon expelled from the Otway Megasequence occurred prior to the regional seal being deposited; however, modelling predicts it can contribute to the hydrocarbon inventory of the Cape Wickham Sub-basin. In particular, the modelling predicted an Otway sourced accumulation at the site of the recently drilled Rockhopper–1. In the Durroon Sub-basin in the Bark Trough, the Otway Megasequence is predicted to be the main source of accumulations. The modelling has provided detailed insights into migration in the existing plays and has allowed assessment of the reasons for previous exploration failures (e.g., a migration shadow at Toolka–1) and to suggest new locations with viable migration histories. Reservoir sands of the Upper EVG are only prospective in the Yolla and Cormorant troughs where charged by Early Eocene sources; however, Miocene reactivation is a major exploration risk in this area.

3D hydrocarbon migration by percolation technique in an alternate sand–shale environment described by a seismic facies classified volume

Modelling hydrocarbon migration in complex depositional environments is a difficult task. This paper illustrates a workflow that has been developed in order to make use of information at seismic resolution for migration modelling purposes. After a regional identification of the main seismic sequence boundaries and systems tracts, the first step of the workflow consists in a semi-automatic classification of the sand and shale prone seismic facies that are interpretable in the seismic volume. A software based on supervised neural network techniques and textural seismic attributes supports volumetric classification. Each class represents a different facies with specific petrophysical properties (threshold pressure, porosity, irreducible water saturation, etc.), assigned according to concurrent sedimentological studies; the result is a 3D lithofacies model. Petroleum system modelling is performed on a 3D regional model up to the calculation of hydrocarbon quantities expelled from the source rock. Then migration modelling is performed on the smaller area covered by the 3D lithofacies model. Invasion percolation approach has been chosen because it allows to perform migration modelling at a scale that is small enough to maintain a sufficient detail of the channels' shape and of their connections. A probabilistic approach allows to estimate charge risk in new prospects and to check modelling consistency. This workflow has been applied in a deep water setting in West Africa, characterized by an interconnected channel system, where a number of prospects had to be evaluated. A well was drilled in the area prior to this study, resulting dry in spite of being located in a position where the source rock is present and is deemed to have expelled interesting amounts of hydrocarbons. This study has shown that hydrocarbons expelled from the source appear to be deviated laterally by the presence of a local seal and therefore do not reach the channel system in the well location.

Integrating structural geology and petroleum systems modeling – A pilot project from Bolivia's fold and thrust belt

For the first time, a new approach to petroleum systems analysis is presented which allows full integration of tectonic and palinspastic restoration with three-dimensional (3D), PVT-controlled, multi-component, three-phase petroleum migration analysis through time. A systematic modeling study has been applied to a study area dominated by fold and thrust belts located in the Sub Andean orogeny near Tarija, Bolivia. The project has been performed with a special focus on the simulation technique and on the correct distribution of temperature, source-rock maturity and pressure development through time with reference to its input data. This is the first pilot project presenting a 3D numerical model in a compressional structural regime to which the basin modeling approach has been applied to explain the observed distribution of temperature, pressure, maturity and petroleum accumulations in general.

Modeling an atypical petroleum system: A case study of hydrocarbon generation, migration and accumulation related to igneous intrusions in the Neuquen Basin, Argentina

In the Altiplanicie del Payún area (Neuquen Basin, Argentina), immature source rock sections intruded by up to 600 m thick Tertiary laccoliths show full spectrum maturity aureoles over hundreds of meters from the contacts. Commercial oil accumulations (20–33°API) and oil shows are located along the entire column, both in sandstone/carbonate and fractured igneous reservoirs. A challenging numerical model that included the emplacement of the intrusive bodies, with extreme temperature ranges and unusually short calculation time steps, has been done with the aim to better understand hydrocarbon generation and migration processes related to these thermal anomalies. A 2D petroleum system model achieved satisfactory results when accounting for thermal maturation, oil and gas generation, composition, migration, and known accumulations. This atypical petroleum system is characterized by thermal anomalies lasting thousands of years that are the result of the progressive cooling of the igneous intrusions. Host source rocks were exposed to a wide range of temperatures that varied in time and space generating different maturity products. High generation pressures, source rock fracturation, and convective water flows facilitated migration and mixing of hydrocarbons and the charge of the igneous bodies as they were fractured during thermal contraction. Oil and source rock analyses were done in order to calibrate and support modeling results. Geochemical correlations suggest an in situ generation related to the igneous intrusions. In particular, diamondoids' measurements show mixing processes of high-mature (cracked) with low-mature hydrocarbons. Oils generated and cracked close to the laccoliths and oils generated from more distant source rock sections, less affected by the thermal anomalies, were probably mixed as they migrated towards the igneous bodies and shallower reservoirs. The integration of a wide set of geochemical analyses and recent modeling techniques based upon time and temperature calculation performance enhancements, led to novel insights on this atypical petroleum system.

Timing and petroleum sources for the Lower Cretaceous Mannville Group oil sands of northern Alberta based on 4-D modeling

The Lower Cretaceous Mannville Group oil sands of northern Alberta have an estimated 270.3 billion m3 (BCM) (1700 billion bbl) of in-place heavy oil and tar. Our study area includes oil sand accumulations and downdip areas that partially extend into the deformation zone in western Alberta. The oil sands are composed of highly biodegraded oil and tar, collectively referred to as bitumen, whose source remains controversial. This is addressed in our study with a four-dimensional (4-D) petroleum system model. The modeled primary trap for generated and migrated oil is subtle structures. A probable seal for the oil sands was a gradual updip removal of the lighter hydrocarbon fractions as migrated oil was progressively biodegraded. This is hypothetical because the modeling software did not include seals resulting from the biodegradation of oil. Although the 4-D model shows that source rocks ranging from the Devonian–Mississippian Exshaw Formation to the Lower Cretaceous Mannville Group coals and Ostracode-zone-contributed oil to Mannville Group reservoirs, source rocks in the Jurassic Fernie Group (Gordondale Member and Poker Chip A shale) were the initial and major contributors. Kinetics associated with the type IIS kerogen in Fernie Group source rocks resulted in the early generation and expulsion of oil, as early as 85 Ma and prior to the generation from the type II kerogen of deeper and older source rocks. The modeled 50% peak transformation to oil was reached about 75 Ma for the Gordondale Member and Poker Chip A shale near the west margin of the study area, and prior to onset about 65 Ma from other source rocks. This early petroleum generation from the Fernie Group source rocks resulted in large volumes of generated oil, and prior to the Laramide uplift and onset of erosion (58 Ma), which curtailed oil generation from all source rocks. Oil generation from all source rocks ended by 40 Ma. Although the modeled study area did not include possible western contributions of generated oil to the oil sands, the amount generated by the Jurassic source rocks within the study area was 475 BCM (2990 billion bbl).

Integrating stratigraphic modelling and seismic interpretation: two practical examples

In the future, the oil industry will have to exploit more and more complex sedimentary basins regarding sedimentology and tectonics. Basin studies will have to integrate more and more advanced and interrelated concepts from different disciplines. Fully integrated basin studies are not yet common practice, but some elements of an integrated workflow are starting to be proposed to the industry. These involve new computer modelling capabilities, such as computer-assisted seismic stratigraphy, 4D kinematic restoration, stratigraphic modelling and petroleum system modelling. Integration of seismic interpretation and sedimentology modelling is one element of this workflow which remains particularly challenging. Stratigraphic modelling is proposed to facilitate this integration; it consists of computerized forward simulation of sedimentary processes at basin scale and geological time-scale. A new simplified stratigraphic modelling method, based on the approximation of the sedimentary history by a succession of sequences during which the sedimentation is supposed to be steady state, will help to invert these stratigraphic models more easily. In particular, the results of seismic interpretation in terms of time-line interpretation and sedimentary environment can now be used as input data to the stratigraphic modelling procedure. The use of seismic data as validation data of the sedimentological model can also be considered, but their relevance depends largely on seismic modelling methods as well as input acoustic parameters.

A smooth transition from serial to parallel processing in the industrial petroleum system modeling package PetroMod

Petroleum system modeling is a crucial technology to numerically simulate the generation, migration, accumulation, and loss of oil and gas through geologic time. The OpenMP programming paradigm is used to achieve modest parallelism on a shared-memory computer for the industrial petroleum system modeling package PetroMod. The significant advantage of this shared-memory parallelization approach is the simplicity of the OpenMP paradigm allowing a smooth transition to a parallel program by incrementally parallelizing a serial code. The process of using OpenMP to parallelize PetroMod is outlined and performance results on a Sun Fire E2900 are reported.

Direct measurement of timing: Underpinning a reliable petroleum system model for the Mid-Continent rift system

The Amoco 1 Eischeid well (Sec. 6, T83N, R35W, Carroll County, Iowa) was the first significant well drilled along the flank of the Iowa horst, providing an opportunity to evaluate the stratigraphic and structural history of the enigmatic Mid-Continent rift system of the United States. New thermal-history data obtained from cutting and core samples show that three paleothermal events affected the drilled section at the Amoco 1 Eischeid well. Results show that three significant cooling events occurred sometime between 300 and 200, 70 and 50, and 35 and 10 Ma. The first of these events was associated with a high paleogeothermal gradient (35C/km), demonstrably greater than the present-day value (16C/km). These new results provide direct evidence of a significantly higher paleogeothermal gradient (and by inference, higher heat flow) during the Paleozoic. In addition, results show that maximum maturity of the rich Precambrian source, the Nonesuch Shale (equivalent), was reached during the 300–200-Ma event and not 600–700 m.y. earlier as previously proposed. Previous work has been significantly influenced by the view that the craton was relatively stable or behaved uniformly throughout the Phanerozoic. Previous models impose a Proterozoic time of generation and entrapment for any Precambrian source intervals. With recognition of significant Phanerozoic heating events, the opportunity for later generation emerges, thus reducing the preservation time and increasing the probability of entrapment and preservation needed for exploration success in the region. Furthermore, these events mapped at the Mid-Continent rift system may be of great regional extent and correlative in time to other well-known events along the North American plate margins (e.g., Alleghanian, Laramide, Ancestral Rockies orogenies), thus offering insights to new possible exploration targets within the rift, perhaps indicative of deep-seated processes in the mantle beneath the North American craton during the Phanerozoic.

Petroleum systems modeling in tectonically complex areas — A 2D migration study from the Neuquen Basin, Argentina

A roughly 30 km 2D section across the Faja Plegada y Corrida del Agrio in the Neuquen Basin, Argentina, is the basis for a petroleum systems study, including structural restoration through time, deposition and erosion, pressure, temperature and migration modeling. Integrating tectonic and petroleum systems modeling proved critical to properly evaluate sub-thrust plays. Multi-dimensional modeling of dynamic processes allows accurate assessment and prediction of the potential of petroleum systems in tectonically complex areas such as the Neuquen Basin.