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The Colombian Eastern Cordillera constitutes a region with potential for finding hydrocarbon reserves that are still under-explored, despite the existence of oil and tar sand production. The intense tectonic deformation affects the petroleum systems and increases exploration challenges due to the different generation, maturation, and entrapment conditions that they produce. Diverse geochemical analysis conducted on strategic samples determines that these are likely generated by the same anoxic marine source rock type. Two source rock samples we investigated are characterized by very different biomarker signals as compared to the tar sands and oil samples. Both samples are dominated by hopanes as compared to tri- and tetracyclic terpanes, with very low (Tibasosa Formation) to no (Chipaque Formation) extended tricyclic terpanes. The Soapaga Thrust, along which the analyzed samples are located, has exercised first-rate regional structural control of the distribution of hydrocarbons in the studied area. The uplift of their Mesozoic hanging wall produces intense erosion with sediment transport towards the eastern footwall forming the present infill of the Arcabuco basin. The kitchen areas were connected with the shallower entrapment sectors where excellent reservoir levels such as the Picacho Formation before the Soapaga Thrust movement. The high degree of biodegradation observed in the Picacho Fm. tar sands support early charge before the Soapaga thrust movement, and severe biodegradation following the thrust movement when hydrocarbon supply from the kitchen was interrupted. This work aims to contribute to a better understanding of the geochemical characteristics of the petroleum systems due to the action of the Soapaga Thrust.

Petroleum systems are inherently complex, comprising multiple components and processes, which variably interact in space and time to form petroleum accumulations. Improved understanding of these complex systems requires a holistic approach of integrating diverse geological, geophysical and organic and inorganic geochemical data. Here, we present an applied and comprehensive Re-Os geochronological and geochemical study on the Brynhild petroleum system from the Norwegian North Sea. Essential components of this system include shale source rocks of the Mandal and Farsund Formations, reservoir sandstones of the Ula Formation and their bitumen extracts, and produced Brynhild crude oil. Rock-Eval, trace metal and Re-Os data reveal the excellent oil-generation potential of the shaley source rocks (high contents of organic matter containing large amounts of type I kerogens) and constrain their depositional conditions (anoxic bottom waters in a high-productivity regime driven by enhanced supply of land-derived nutrients). Seven Re-Os shale ages between ~146 and ~134 Ma are consistent with existing Volgian–Ryazanian age estimates and constrain the initial 187Os/188Os of the shales to ~0.52 in the lowermost Farsund Formation and ~0.75 in the uppermost Mandal Formation. Solvent-extracted reservoir rocks of the Ula Formation contain insoluble organic matter with type III–type IV kerogens likely supplied by erosion of older (a precise 179 Ma Re-Os age with unrealistically low initial 187Os/188Os) coal-bearing sediments or organic-rich shales. The Brynhild crude oil has relatively low 187Os/188Os and a generation age of ~44 Ma based on an asphaltene-only Re-Os isochron. Maltenes from the Brynhild crude oil are isotopically affected by interaction with organic-rich source rocks that represent the seal for the Brynhild oil field. Compared with the crude oil, bitumen from Ula Formation sandstones have contrasting Re-Os properties: high 187Os/188Os ratios and young generation ages between 8 and 0 Ma based on asphaltene-bitumen-maltene Re-Os triplets, asphaltene-only Re-Os regressions, and Re Os model ages for components with extremely high 187Re/188Os. The 44 Ma and 8–0 Ma Re-Os ages agree well with regional burial models that indicate oil generation from ~44 Ma to present day. A genetic link between crude oil and bitumen is indicated by their similar alkane patterns, V and Ni contents, and V/Ni and pristane/phytane ratios. Modeling of 187Os/188Os for individual organic components through time shows that shales of the Mandal Formation developed 187Os/188Os ratios that match those of the crude oil and bitumen at ~44 Ma and ~8 Ma, respectively, and therefore confirm the source for both hydrocarbon phases. We suggest that bitumen formed during in-reservoir mixing of a ~44 Ma old early mature, asphaltene-poor oil (Brynhild crude oil) with an ~8 Ma old asphaltene-rich oil.

A 3D petroleum systems model of the northern Bonaparte Basin indicates that the potential Nancar Trough source kitchen could be currently expelling hydrocarbons from numerous Jurassic source rocks into traps on the Laminaria High. Based on a range of kinetic models defined for such source rocks within the Plover, Laminaria and Frigate formations, two phases of hydrocarbon generation are predicted. Source rocks within the Lower Cretaceous Echuca Shoals Formation are immature for hydrocarbon generation in this region. Hydrocarbon generation in the Laminaria High commenced during the mid to late Cenozoic, and in the Nancar Trough during the Early Cretaceous, in response to elevated heat flow during the syn-rift phase. The second and main phase of hydrocarbon generation and expulsion started in the mid-Eocene and is ongoing. This phase was controlled by deposition of the thick Cenozoic carbonate shelf, which resulted in deep burial and continued heating of the Mesozoic source rocks. This second phase of expulsion coincided with the reactivation of fault-bounded traps, the consequence of which is that either some or all of the initially trapped hydrocarbons have escaped out of the charged structures. Thus, the most plausible explanation for the occurrence of under-filled and dry structures within the study area is that the faults bounding these traps remained permeable from the late Miocene to the present-day. Secondary alteration processes including water washing and phase fractionation are necessary to explain the bulk composition of Laminaria High and neighbouring under-saturated light oil accumulations.

This study uses a 3D petroleum system modelling approach to investigate the links between hydrocarbon generation and migration with observed gas chimneys and gas leakage features along the western margin of offshore South Africa. In addition we have investigated the impact and timing of mass failures and related sediment mass movement on the petroleum system and hydrocarbon maturation history within the southern Orange Basin. Our 3D-model covers this passive margin’s evolution from Early Cretaceous drift initiation to the establishment of a present day continental margin, extending from the shelf to the deep marine domain. The model is based on interpreted 2D seismic profiles and borehole data including sedimentological and geochemical analyses as well as heat flow data. The model includes a proven source rock of Aptian/Albian age, and a second assumed Cenomanian-Turonian source. Several heat flow and uplift-erosion scenarios have been tested with the model to assess consistency with calibration data and present day surface heat flow values. After calibration against known well temperatures and vitrinite reflectance hydrocarbon generation and migration have been modelled to investigate the initiation, duration and spatial distribution of petroleum accumulation and leakage within and throughout the sedimentary column. The main sedimentary depocentres of the Orange Basin developed from east to west, with a siliciclastic basin infill and aggradation during the Cretaceous and westward progradation during the Late Cenozoic. A Late Cretaceous episode of margin instability occurred in the north western part of the study area followed by a second phase of Late Cenozoic mass movement in the south-western part of the study area. At the location of the Cretaceous mass failure the increase in sediment load profoundly affected the underlying source rocks seen in modelled maturation and petroleum generation potential. Albian source rocks started hydrocarbon transformation 100 to 85 Ma ago (phases I to III) in the centre of the basin and between 75 to 65 Ma ago (phase IV and VI) towards the distal part of the basin. The highest generation rates occurred at 75 Ma, followed by a rapid decrease until 15 Ma and a slight increase in generation potential until present day (phase V) caused by enhanced Cenozoic sediment load west of the Cretaceous shelf break. This recent increase accounts for the location of present day gas generation, though it does not substantially affect the overall regional maturation history. Today’s gas leakage features that have been observed in the shelf area (

Using a 2D seismic dataset that covers part of the southern Orange Basin offshore South Africa, we reconstructed the geological evolution of the basin. This evolutionary model was then used to investigate the occurrence of natural gas within the sedimentary column and the distribution of gas leakage features in relation to the observed sedimentary and tectonic structures developed in the post-rift succession since the Early Cretaceous. The Cretaceous succession has been subdivided into five seismic units. The highest sedimentation rates occur within the Barremian/Aptian (unit C1) and the Turonian/Coniacian (unit C3). Two Cenozoic units (T1 and T2) have been distinguished. These show a sudden decrease in sedimentation rate for the whole of the Cenozoic. Three phases of gravitational tectonics, with two Late Cretaceous phases of mass movement in the northern study area and Cenozoic slumping in the southern study area, have been related to sedimentation rates, sea-level changes, paleoenvironmental evolution and regional tectonics. The occurrence of natural gas leakage follows a coast-parallel distribution within the study area. In the near shore part at water depths shallower than 400 m, massive gas chimneys penetrate through the sediment layers and reach the (near-) surface. Within an intermediate narrow band, between 300 and

The stratal architecture of the Mackenzie Basin was reconstructed based on seismic and well data and used to define a three-dimensional model to reconstruct the so-far poorly known thermal and maturation history of the basin. To correctly account for the complex tectonic history of the Mackenzie Basin, episodes of uplift and erosion were implemented based on interpretations of original depositional surfaces. Our results indicate that the combined effects of basin inversion and low surface temperatures inhibited maturation from the late Miocene forward in all except the most deeply buried parts of the basin. This explains why upper Eocene and younger deposits are mostly immature despite their burial to more than 5000 m (16,400 ft). The specific history of the basin is shown to control the time intervals of potential hydrocarbon generation. Predictions of transformation ratios using a variety of published kinetics to account for source rock kinetic variability indicate that potential generation from Paleocene and older strata occurred mainly before the late Oligocene. The generation from Eocene strata, however, occurred mainly during the Miocene and, therefore, is interpreted to be a source for Oligocene and younger gas-rich reservoirs. These findings contribute to a better understanding of hydrocarbon systems in the Mackenzie Basin and are the basis for future studies of hydrocarbon migration and accumulation.

Pyrolysis experiments (open and closed systems) and kinetic modelling of primary cracking of kerogen have been carried out to investigate hydrocarbon generation characteristics and source rock facies variability within the Upper Cretaceous to Paleogene Latrobe Group in the Gippsland Basin. On the basis of Rock-Eval data, the interbedded coals, coaly shales and carbonaceous shales contain different types of kerogen (Type III, Type II–III, Type II) with variable potential for both gas and liquid hydrocarbon generation. Open system pyrolysis–gas chromatography data indicate that the organically lean marginal marine shales of the Santonian–early Campanian Tricolporites apoxyexinus and Nothofagidites senectus biozones produce gas and condensate. However, coal and coaly to carbonaceous shales sampled from the Paleocene Lygistepollenites balmei , Maastrichtian Forcipites longus , late Campanian Tricolporites lilliei and Turonian Phyllocladidites mawsonii palynological biozones are heterogeneous with the capacity to generate both low and high wax paraffinic–naphthenic–aromatic (P–N–A) oils, and paraffinic oils with a high wax content. The main phase of petroleum formation from these later biozones, assuming a constant geological heating rate of 3.3 °C/Ma, is predicted to occur between 150–179 °C, indicating different orders of kinetic stability as a result of different types of organic matter and their state of preservation. The thermally immature shales have variable bulk kinetic characteristics, but the measured compositional kinetics and phase behaviour show that they have the potential to generate black oils at early stages of kerogen cracking, and either light oils or wet gases at higher levels of thermal stress. These findings suggest that upon thermal maturation, the interbedded shales of the Latrobe Group may have contributed significant volumes of hydrocarbons to the oil and gas accumulations in the Gippsland Basin. In addition, this study not only supports the premise that over-reliance on Rock-Eval/TOC data alone can be misleading for assessment of petroleum generation, but also represents a strategy for kerogen type and generative potential determination for fluvio-deltaic coals and subordinate lithologies.

Knowledge of the timing and location of petroleum formation is important in assessing the extent of available reserves in hydrocarbon-forming basins. This can be predicted from the thermal history of a basin and the kinetic parameters that characterize the thermal breakdown of kerogen in source rocks. At present, the kinetic parameters of kerogen breakdown are experimentally determined using immature rock samples from basin margins, but questions remain about the accuracy of this approach, especially when significant variability is observed within individual source units. Here we show that the kinetics of hydrocarbon generation from petroleum asphaltenes can be used to determine the temperature conditions of the actual source rock at the time of expulsion of the sampled petroleum. This relationship reflects the structural similarity of asphaltenes to the parent kerogen. We expect that our approach may be used as a comparatively simple alternative method for assessing the petroleum generation characteristics of a given basin, which will allow for better estimates of the available oil resources and the risks associated with their exploration.

A geochemical investigation was carried out on 61 core and cuttings samples from selected Mesozoic source rocks in the offshore Vulcan Sub-basin of the Bonaparte Basin, Australia. Rock-Eval pyrolysis data reveal that these source rock samples contain Type II, Type II/III and Type III kerogen, with variable potential for gas and liquid hydrocarbon generation. In the Vulcan Sub-basin, samples from the marine Lower Cretaceous Echuca Shoals Formation and Upper Jurassic–Lower Cretaceous upper Vulcan Formation have fair to moderate quality organic matter. The samples from these two formations are marginally mature, but where burial is sufficient to attain higher maturity, as in the Nancar Trough to the north of the Vulcan Sub-basin, these formations have potential to be additional sources for marine oil. Samples from the marine Middle–Upper Jurassic lower Vulcan and fluvio-deltaic Lower–Middle Jurassic Plover formations contain good to very good quality organic matter. Mixed oil- and gas-prone Type II/III kerogens in the lower Vulcan and Plover formations are mature for hydrocarbon generation and can be, depending on their location and depositional environment, source rocks for oil with terrigenous and/or marine geochemical signatures. Assuming a constant geological heating rate of 3.3 °C/Ma, the onset of hydrocarbon generation (10% transformation ratio (TR)) from the Echuca Shoals and upper Vulcan formations occurs at 120 °C compared to 120–160 °C for the lower Vulcan and Plover formations. Generally, low gas/oil ratios (GORs), comparable to those measured in the natural accumulations, were reproduced at 400 mg HC/g TOC) suggest the potential for high-wax PNA oil generation, in addition to wet gas.

Potential source rocks on the Laminaria High, a region of the northern Bonaparte Basin on the North West Shelf of Australia, occur within the Middle Jurassic to Lower Cretaceous early to post-rift sequences. Twenty-two representative immature source rock samples from the Jurassic to Lower Cretaceous (Plover, Laminaria, Frigate, Flamingo and Echuca Shoals) sequences were analysed to define the hydrocarbon products that analogous mature source rocks could have generated during thermal maturation and filled the petroleum reservoirs in the Laminaria High region. Rock-Eval pyrolysis data indicate that all the source rocks contain type II–III organic matter and vary in organic richness and quality. Open system pyrolysis-gas chromatography on extracted rock samples show a dominance of aliphatic components in the pyrolysates. The Plover source rocks are the exception which exhibit high phenolic contents due to their predominant land-plant contribution. Most of the kerogens have the potential to generate Paraffinic–Naphthenic–Aromatic oils with low wax contents. Bulk kinetic analyses reveal a relatively broad distribution of activation energies that are directly related to the heterogeneity in the kerogens. These kinetic parameters suggest different degrees of thermal stability, with the predicted commencement of petroleum generation under geological heating conditions covering a relatively broad temperature range from 95 to 135 °C for the Upper Jurassic−Lower Cretaceous source rocks. Both shales and coals of the Middle Jurassic Plover Formation have the potential to generate oil at relatively higher temperatures (140–145 °C) than those measured for crude oils in previous studies. Hence, the Frigate and the Flamingo formations are the main potential sources of oils reservoired in the Laminaria and Corallina fields. Apart from being a reservoir, the Laminaria Formation also contains organic-rich layers, with the potential to generate oil. For the majority of samples analysed, the compositional kinetic model predictions indicate that 80% of the hydrocarbons were generated as oil and 20% as gas. The exception is the Lower Cretaceous Echuca Shoals Formation which shows the potential to generate a greater proportion (40%) of gas despite its marine source affinity, due to inertinite dominating the maceral assemblage.

The upper Triassic Yanchang shale in Southeast Ordos Basin (SOB) is a main potential source rock for conventional petroleum fields and has been recently recognized as an important unconventional reservoir. Here, we report on the hydrocarbon potential of this lacustrine shale using bulk and quantitative pyrolysis techniques. The rock samples were taken from the Chang7 and Chang9 intervals of upper Triassic-aged cores. The analytical program included total organic carbon (TOC), Rock-Eval, pyrolysis gas chromatography (Py–GC), source rock analyzer (SRA), and microscale sealed vessel (MSSV) pyrolysis. Phase kinetic modeling was also employed on the basis of these data sets. The results were used to determine the petroleum-type organofacies, bulk hydrocarbon composition during maturation, bulk and compositional kinetics, and phase behavior of fluids generated in the Yanchang shales. The shales proved to contain type II2 kerogen with organic matter in high abundance and generate paraffinic–naphthenic–aromatic (...

We present a supra-regional comparative study of the major internal and external factors controlling source rock (SR) maturation and hydrocarbon (HC) generation and leakage in two pairs of conjugate margins across the South Atlantic: the Brazil (Campos Basin)–Angola (Lower Congo Basin) margins located in the “central segment”, and the Argentina (Colorado Basin)–South Africa (Orange Basin) in the “southern segment”. Our approach is based on the analysis and integration of borehole data, 1D numerical modeling, 2D seismic reflection data, and published reports. Coupling of modeling results, sedimentation rate calculation and seal-bypass system analysis reveal that: (1) oil window is reached by syn-rift SRs in the southern segment during the Early to Late Cretaceous when thermal subsidence is still active, while in the central segment they reach it in Late-Cretaceous–Neogene during a salt remobilization phase, and (2) early HC generation from post-rift SRs in the southern segment and from all SRs in the central segment appears to be controlled mainly by episodes of increased sedimentation rates. The latter seems to be associated with the Andes uplift history for the western South Atlantic basins (Campos and Colorado) and to a possibly climate-driven response for the eastern South Atlantic basins (Orange and Lower Congo). Additionally, we observe that the effect of volcanism on SR maturation in the southern segment is very local. The comparison of Cretaceous mass transport deposit (MTD) episodes with HC peak of generation and paleo-leakage indicators in the southern segment revealed the possible causal effect that HC generation and leakage have over MTD development. Interestingly, Paleogene leakage indicators, which were identified in the Argentina–South Africa conjugate margins, occur contemporaneously to low sedimentation rate periods. Nonetheless, present-day leakage indicators which were also identified in both pairs of conjugate margins might be related to seal failure events linked to eustatic sea-level drops.

3D basin modelling of the Hammerfest Basin (southwestern Barents Sea) was performed in order to address the masses of petroleum generated, accumulated and lost during the evolution of the basin. Calibration of the model, based on observed maturity (vitrinite reflectance) and present-day temperatures, took into account (1) two main erosion episodes: an Oligocene–Miocene event, due to tectonic uplift and a Plio-Pleistocene glacial erosion event, and (2) variable heat flow from Late Palaeozoic to Cenozoic. The maturity levels of the main source rocks (Kobbe, Snadd and Hekkingen formations) were reconstructed and show that the highest maturities have been reached in the western and northwestern margin of the basin. The beginning of petroleum generation in the Kobbe, Snadd and Hekkingen source rocks has been predicted to occur during Late Triassic, Early Cretaceous and Late Cretaceous, respectively. Our model reproduces satisfactorily the distribution of the main oil and gas fields and discoveries that have been found in the study area. Our results indicate that two events of hydrocarbons redistribution occurred in the basin. The first event resulted in the main oil redistribution episode, which took place during the Oligocene–Miocene associated with tectonic uplift and gas expansion, and the second was related to the main gas leakage events that occurred during the Pliocene–Pleistocene glacialinterglacial cycles in general and the episodes of glacial retreat in particular. Glacial loading and unloading cycles resulted in overpressure fluctuations in the subsurface reservoirs. Modelling results indicate that during these episodes a portion (at least 0.247 Gt) of thermogenic gas leaked from the main Sto Formation reservoirs reached the sediment interface and was released to the surface in the Hammerfest Basin.

Lower Cambrian shale in the Upper Yangtze Platform (UYP), South China, is an important source rock of many conventional petroleum fields and was recently recognized as a promising unconventional shale reservoir. In this paper, hydrocarbon generation kinetics and petroleum physical properties were investigated using the PhaseKinetics approach ( di Primio and Horsfield, 2006 ) and a Cambrian shale sample from the Georgina Basin, North Territory Australia (NTA), as similar paleogeological and sedimentary environments in Cambrian are found for the UYP and NTA. The source rock comprises type II kerogen and belongs to an organofacies generating Paraffinic–Naphthenic–Aromatic low wax oil. Bulk petroleum generation can be described by a single frequency factor A = 8.43E + 14 (1/s) and a dominant activation energy at 56 kcal/mol, which is characteristic for sulphur-poor organic matter deposited in an anoxic marine environment. Onset (transformation ratio TR = 10%) and end (TR = 90%) of bulk hydrocarbon generation was calculated to take place at 120 °C and 165 °C respectively for an assumed average geological heating rate of 1.5°C/Ma. Based on the thermal history of a local “model”-well, onset temperature was not reached until the Middle Triassic (241 ma) when sediments were buried more than 2000 m and basalt eruptions caused enhanced heat flows. The main generation stage of primary petroleum took place during the Middle–Late Triassic and ended in the Early Jurassic (187 ma) for burial depths exceeding 4000 m (TR 90%; 165 °C). Temperatures increased to more than 200 °C in the Middle–Late Jurassic leading to secondary cracking of primary products. Hydrocarbons formed at the onset (TR = 10%) of petroleum generation can be characterized by a gas-oil-ratio (GOR) of 63 Sm3/Sm3, a saturation pressure (Psat) of 101 bar, and a formation volume factor (Bo) of 1.2 m3/Sm3. Those parameters stay low during primary petroleum generation before 203 ma, at temperatures > 10,000 Sm3/Sm3, Psat > 250 bar and Bo > 2.0 m3/Sm3) during secondary cracking starting roughly at 200 ma, 152 °C and 3500 m burial. Assuming zero expulsion, the shale reservoir position within the sedimentary basin indicates that bubble point pressure was always below reservoir pressure, and fluids in the shale reservoir occurred only as a single, undersaturated phase throughout maturation history. Black oil and volatile oil phases dominated during the primary cracking period, whereas wet gas and dry gas phases dominated during the secondary cracking period.

A mathematical model is presented for the quantification of the effects of carbonate dissolution and volume reduction on the basis of mass balance-type comparisons between sediment volumes before and after effective carbonate redistribution due to pressure solution. Application of the model to a carbonate source rock formation from Italy allowed the quantification of the degree of organic matter enrichment in solution seams or stylolites and the extent of organic matter dilution in adjacent matrix layers. The diagenetic unmixing of carbonate versus non-carbonate materials has resulted in a heterogenous distribution of organic matter in this source rock formation. This effect needs to be considered in hydrocarbon exploration for assessment of source potential.

Based on detailed geochemical and petrographic studies of conventional cores of a Triassic age carbonate source rock formation from three well sites at increasing maturity stages, it is shown that the effects of carbonate diagenesis, especially pressure solution during relatively shallow burial stages, exercise major controls on the processes of petroleum generation and migration during deeper burial. Pressure solution leads to an internal redistribution of organic matter within this source rock formation in the form of local concentrations as solution seams and stylolites. They provide very favourable conditions for effective petroleum generation and migration due to their internal structure and composition (three-dimensional arrangement of kerogen surrounded by carbonate-cemented rims as tight seals). The geochemical and petrographic effects of petroleum generation and expulsion are documented, e.g. the expulsion of petroleum occurred as a separate phase fluid, at high efficiencies (60–80% for the normal and isoprenoid alkanes) and was facilitated by fractures presumably resulting from pore fluid overpressuring. A five-stage conceptual model is proposed to explain how the effects of pressure solution achieved during relatively shallow burial stages exercised controls on the extent and efficiency of petroleum generation and expulsion during deeper burial stages.

The detailed interpretation and seismic attribute analysis of 2D and 3D seismic reflection data sets revealed the presence of a distinct seismic horizon displaying circular and elongated depressions in early Eocene sediments along the northwestern slope of the Orange Basin on the southwest African margin. Their occurrence within a single seismic horizon indicates a contemporaneous formation process. We interpret the depressions as paleo-pockmarks, which occur as single pockmarks, predominantly NNE–SSW aligned pockmark trains, and coalescing elongated pockmarks. The paleo-pockmarked surface covers an area of 2800 km 2 and has been mapped by integrating the 3D dataset with industrial 2D seismic grids. The spatial and temporal occurrence of the paleo-pockmarks is associated to two episodes of rapid sedimentation during the late Maastrichtian to Paleocene, comprising fine-grained shelf-eroded material. We propose that they were formed during the early Eocene by the seepage of both (1) overpressured pore fluids from disequilibrium compaction of upper Maastrichtian sediments and (2) thermogenic gas from underlying Cretaceous mature source rocks. We show that the location of the pockmarks is controlled by the underlying faults system of the paleo-slope. The Paleocene–Eocene transition is known for its series of hyperthermal events characterized by negative excursions of the carbon isotope curve. The early Eocene widespread event of fluid and thermogenic gas escape identified in this work can be an example of the type of carbon-release processes occurring in hydrocarbon-prone sedimentary basins during this time.

The origin of the immense oil sand deposits in Lower Cretaceous reservoirs of the Western Canada sedimentary basin is still a matter of debate, specifically with respect to the original in-place volumes and contributing source rocks. In this study, the contributions from the main source rocks were addressed using a three-dimensional petroleum system model calibrated to well data. A sensitivity analysis of source rock definition was performed in the case of the two main contributors, which are the Lower Jurassic Gordondale Member of the Fernie Group and the Upper Devonian–Lower Mississippian Exshaw Formation. This sensitivity analysis included variations of assigned total organic carbon and hydrogen index for both source intervals, and in the case of the Exshaw Formation, variations of thickness in areas beneath the Rocky Mountains were also considered. All of the modeled source rocks reached the early or main oil generation stages by 60 Ma, before the onset of the Laramide orogeny. Reconstructed oil accumulations were initially modest because of limited trapping efficiency. This was improved by defining lateral stratigraphic seals within the carrier system. An additional sealing effect by biodegraded oil may have hindered the migration of petroleum in the northern areas, but not to the east of Athabasca. In the latter case, the main trapping controls are dominantly stratigraphic and structural. Our model, based on available data, identifies the Gordondale source rock as the contributor of more than 54% of the oil in the Athabasca and Peace River accumulations, followed by minor amounts from Exshaw (15%) and other Devonian to Lower Jurassic source rocks. The proposed strong contribution of petroleum from the Exshaw Formation source rock to the Athabasca oil sands is only reproduced by assuming 25 m (82 ft) of mature Exshaw in the kitchen areas, with original total organic carbon of 9% or more.

The stable carbon isotopic ratios (δ 13 C) of methane (CH 4 ) and carbon dioxide (CO 2 ) of gas-rich fluid inclusions hosted in fracture-fill mineralization from the southern part of the Lower Saxony Basin, Germany have been measured online using a crushing device interfaced to an isotopic ratio mass spectrometer (IRMS). The data reveal that CH 4 trapped in inclusions seems to be derived from different source rocks with different organic matter types. The δ 13 C values of CH 4 in inclusions in quartz hosted by Carboniferous rocks range between −25 and −19‰, suggesting high-maturity coals as the source of methane. Methane in fluid inclusions in minerals hosted by Mesozoic strata has more negative carbon isotope ratios (−45 to −31‰) and appears to represent primary cracking products from type II kerogens, i.e., marine shales. There is a positive correlation between increasing homogenization temperatures of aqueous fluid inclusions and less negative δ 13 C(CH 4 ) values of in co-genetic gas inclusions probably indicating different mtaturity of the potential source rocks at the time the fluids were released. The CO 2 isotopic composition of CH 4 –CO 2 -bearing inclusions shows slight negative or even positive δ 13 C values indicating an inorganic source (e.g., water–rock interaction and dissolution of detrital, marine calcite) for CO 2 in inclusions. We conclude that the δ 13 C isotopic ratios of CH 4 –CO 2 -bearing fluid inclusions can be used to trace migration pathways, sources of gases, and alteration processes. Furthermore, the δ 13 C values of methane can be used to estimate the maturity of the rocks from which it was sourced. Results presented here are further supported by organic geochemical analysis of surface bitumens which coexist with the gas inclusion-rich fracture-fill mineralization and confirm the isotopic interpretations with respect to fluid source, type and maturity.

Organic-rich “hot shales” of the Lower Silurian Tanezzuft formation are regarded as the principal source rocks for Palaeozoic oil fields in North Africa. Thus, the evolution of the petroleum system of the Murzuq basin, Southern Libya, is largely controlled by the lateral extension, thickness, organic geochemical characteristics and maturity of the Tanezzuft hot shale. In this context the petroleum generation potential of Tanezzuft hot shale samples from the Murzuq basin was studied by geochemical and petrological methods and a numerical modelling study was performed taking into account the structural evolution and thermal history of this basin[1]. Core and cutting samples of the Lower Silurian interval were selected from two wells of the northern and central part of Murzuq basin. High TOC contents and HI-values from Rock-Eval pyrolysis indicate organic-rich source rocks with moderately hydrogen-rich organic matter, classified as Type II kerogen, at different maturity levels. To enhance the geochemical source rock characterisation as well as to predict hydrocarbon phases and generation [2], bulk and phase kinetics were performed by open system- and closed system pyrolysis. The bulk kinetic analysis confirmed the early to mid mature level for the northern part and immature to early mature level for the central part of the basin. The activation energy distribution for the samples is characterised by a smooth bell-shaped, Gaussian-like distribution, typical of marine type II kerogen. Temperature and timing of petroleum generation were calculated using activation energies and frequency factors with a linear geological heating rate of 3.3 K/my [2]. The compositional kinetic analysis was performed to assess the composition of generated petroleum. The results show that 75 % of hydrocarbons is generated as oil and 25 % as gas fraction. The gas-oil ratio was calculated and found to increase with increasing the maturity. [1] Belaid, A., B. Krooss and R. Littke, 2009, Thermal history and source rock characterization of a Palaeozoic section in the Awbari Trough, Murzuq Basin, SW Libya, Marine and Petroleum Geology, doi: doi:10.1016/j.marpetgeo.2009.06.006. [2] di Primio, R., Horsfield, B., 2006, From petroleum type organofacies to hydrocarbon phase prediction. AAPG Bulletin, v. 90, no. 7, p.1031 - 1058

Combining compositional predicting PhaseKinetcs with state of the art migration methods such as mapbased ray-tracing, pressure driven Darcy-flow and capillary pressure driven invasion percolation, allows to take into account the influence of petroleum composition and its phase behavior even during hydrocarbon generation, migration and accumulation. In combination with these migration models different adsorption methods and different critical saturations as well as secondary cracking processes inside and outside the source rock and different API calculation methods are applied. The question is: which minor processes can be calibrated independently and can therefore be validated? Or is the system over-determined and minor processes are just helpful to calibrate and manipulate the system? In the present study area, the geochemical composition of the Egret source rock and the accumulated quantities in the Jeanne d’Arc basin are well known. Therefore, we can test and quantify the processes, which affect the fluids during primary and secondary migration. Chemical properties of the source rock have been investigated based on 38 samples and PhaseKinetics were determined. The first step was the evaluation of a heat-flow history through time, using different crustal- and stretching-models. The heat-flow maps were then calibrated based on available vitrinite reflectance, bottom hole temperature and apatite fission track data. In a second step different fluid flow simulators were combined with different types of kinetic data. Additionally, we tested the influence of different equations of states (EOS), namely Peng-Robinson and the Soave-Redlich-Kwong EOS, on the ensuing phase behavior and physical properties (e.g. API gravity) of the migrating fluids in the models. We demonstrate also that some other minor processes are not completely taken into account such as the real nature of the hysteresis effect of drainage and imbibition for capillary pressure vs. saturation and that real interfacial tension maps for both gas and oil should be used instead of two constant IFT values. However, defining all minor processes in detail does not always lead to more accurate results due to the generally high uncertainties in basin modeling, which causes also a very poor determination of losses during primary and secondary migration. However, to reproduce and calibrate the general pattern of generation, migration and accumulation these minor processes can be used very well.

International audience; The analysis of 2D deep-seismic-reflection profiles across the slope and abyssal plain of the Angola oceanic basin reveals the existence of a significant and formerly unknown depocentre beneath the giant Cenozoic Congo deep-sea fan, between 7000 m and 9000 m depth, deposited directly onto the Aptian oceanic crust. The unit, which is up to 2.5 km thick and extends for more than 200 km basinwards of the Continent-Ocean boundary, is probably aged Albian-Turonian. Its radial fan-shaped depocentre is centred on the present-day Congo River outlet and contains at least 0.2 Mio km(3) of sediments. These observations and the results from flexural modelling indicate that (1) the location of the Congo River's outlet has remained fairly stable since the Late Cretaceous, and (2) the basal unit was indeed sourced by a palaeo-Congo River probably located nearby the present-day one. Thus, the Atlantic sedimentary system related to the exoreism of the Congo River is much older than previously thought. Thermal modelling indicates that the maturation history of this upper-Cretaceous deposits is highly influenced by the interaction between the initial high heat flow of the young oceanic crust and further increase in sediment supply due to the progradation of the overlying Tertiary deep-sea fan during the Miocene. Hence, despite low present-day heat-flow values, should the unit have source rock potential, its basal section may be currently generating hydrocarbons.;All in all, the results from our models also suggest that the interplay between an initially high heat flow and the further high sediment supply in areas of major river input, may be a key factor for the thermal maturation of potential source rocks deposited onto a present-day "cold" oceanic crust.

The Mackenzie Basin in northwest arctic Canada has many characteristics of a typical terrestrial, gas-rich sedimentary basin, but the origins of this important hydrocarbon province are still not well known. The three-dimensional basin modeling approach employed here illustrates not only improved capabilities but also potential pitfalls in reproducing flow in complex stratal and structural basin architectures of present-day models. Listric fault structures especially are still inadequately reproduced in most migration models. By integrating individual styles of deformation and introducing a sequence-stratigraphic approach to reproduce the stratal architecture, we are able to identify temporal and spatial relationships between sources and reservoirs. Based on these considerations, three genetic groups of oils in the basin are proposed: a first group mainly related to a Paleocene source rock, a second group related almost exclusively to an early mature source in the Eocene Taglu formation, and a third group related to the Upper Cretaceous Smoking Hills and Boundary Creek formations. In contrast to oil accumulations, gas accumulations resulted mainly from a filling event in the late Miocene, which is interpreted to be related to a decrease in pressure during a late Miocene uplift and erosional event. The Mackenzie Basin is therefore an excellent example to show that the gas proneness of a mature petroleum system, especially if the organic matter is predominantly of terrestrial origin, is mainly a function of expulsion efficiency and timing and thus is directly linked to the structural history of the basin.

Asphaltenes extracted from crude oils are proposed to possess structural features of the related source rock kerogen. For the present study micro-scale sealed vessel pyrolysis (MSSV) and combustion isotope ratio mass spectrometry (GC–C–IRMS) were used to compare gas generation from a whole rock (type II-S kerogen) from southern Italy with that from related sulfur rich asphaltenes isolated from a low maturity heavy crude oil. The purpose of was to determine whether experimental pyrolysis of oil asphaltenes can be used to predict the timing and the chemical and isotopic composition of hydrocarbon gases generated from genetically related kerogen in the source rock during burial maturation. The results show that parameters such as (gas to oil ratio) GOR and oil and gas formation timing are very similar for these two sample types, whereas gas composition, product aromaticity and sulfur content are remarkably different. Slight differences in GOR are mainly due to differences in gas formation characteristics at very high levels of thermal alteration. Secondary gas formation from the whole rock covers a much broader temperature range under geological conditions than that from the asphaltene products. However, it is remarkable that both the onset and the maximum temperature are nearly identical under geological conditions. The observed differences in gas generation characteristics are supported by discrepancies in the carbon isotopic characteristics of the gas range compounds and indicate different precursors and/or mechanisms for gas generated from whole rock and asphaltenes.

An integrated approach to investigate the petroleum system of the southern Orange Basin, South Africa reveals that the principal controls on hydrocarbon generation and leakage are spatial and temporal variations in post-rift overburden deposition. The model predicts present day gas seepage at the sea floor and this is calibrated against observed seepage events. D basin modelling of an east-west trending transect across the Orange Basin passive margin was undertaken accounting for variations in stratigraphy, structural deformation, source rock distribution and characteristics and heat flow variations associated with continental break-up. Petroleum generation and migration modelling was performed using compositional kinetic schemes, and migration and leakage routes calibrated to signs of current-day active leakage collected during seismic interpretation. The use of seismic indicators of hydrocarbon leakage as calibration data for constraining migration predictions is essential for the reconstruction of hydrocarbon generation and migration scenarios, as they provide the validation of the model with respect both to the physical properties and distribution of the sedimentary sequences as well as the dynamics of oil and gas migration. Modelling results indicate that the main period of hydrocarbon generation occurred in the Late Cretaceous, the time of maximum burial on the shelf. Following an erosion event at the end of the Cretaceous, deposition shifted over the shelf break and significant sediment volumes prograded into the deep basin. This led to a second pronounced maturation event focussed specifically under the prograding Tertiary wedges. The model predicts that the kitchen area is active today and is also the source of hydrocarbons that are observed to be seeping at the present day sea floor.

The Northern Permian Basin is located in the offshore area SSW of Norway, NNW of Denmark and east of Scotland. This basin is filled mainly by Lower Permian aeolian desert sediments and volcanics, plus Upper Permian evaporitic sediments. The aeolian sandstone is an excellent reservoir rock and is generally capped by thick layers of salt that potentially form a tight cap rock. The highest risk in the petroleum exploration of the Palaeozoic Northern Permian Basin is linked to the presence of source rocks. Palaeozoic source-rock candidates in the Northern Permian Basin area may be present among Lower Palaeozoic marine sediments, within Devonian–Carboniferous lacustrine/deltaic pre- and syn-rift sediments and as Permian marine shales. This study investigates Lower Palaeozoic marine shales, lacustrine Devonian mudstones, Carboniferous mudstones and coals and marine Permian shales in order to assess the thermal maturity, source-rock potential and distribution of Palaeozoic sediments in the Northern Permian Basin region. The majority of the investigated samples were within the oil window in terms of thermal maturity. Lower Palaeozoic marine sediments may have generated both oil and gas, while Upper Palaeozoic coals and mudstones are dominantly gas-prone source rocks. Middle Permian marine shales (Kupferschiefer) are a good oil-prone source rock. Generation and expulsion of hydrocarbons from Lower Palaeozoic source rocks in the eastern parts of the Northern Permian Basin probably began in the Upper Silurian, with peak oil generation in Carboniferous times. Upper Palaeozoic rocks in the same area matured rapidly in Early Triassic times. The likely presence of multiple Palaeozoic source rocks suggests that hydrocarbons were generated in the Northern Permian Basin.