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The formation of viscous oil and tar mats in oilfield reservoirs has substantial consequences in the production of oil. For example, aquifer sweep can be precluded in such an occurrence, impacting field development planning. Several processes can give rise to accumulations of heavy ends in reservoirs, namely, the asphaltenes and other high-molecular-weight polar compounds. Multiple, incompatible charge fluids can enter a reservoir, causing instability, migration, accumulation, and phase separation of heavy ends. Two adjacent reservoirs in Norway evidently exhibit different stages of tar formation from incompatible charge: in one reservoir, asphaltenes deposit as a result of an excess asphaltene concentration, and in the second reservoir, asphaltenes deposit from solution gas expulsion. Here, ultrahigh-resolution mass spectrometry is used to analyze heavy ends from both reservoirs in crude oils and rock core chips. The heavy ends or asphaltenes in crude oils and associated core deposits from each reservoir are analyzed and shown to be compositionally very similar. In addition, the two crude oils are examined by two-dimensional gas chromatography, confirming that the hydrocarbon liquid-phase components closely resemble one another. Importantly, there are only subtle chemical differences between heavy ends that underwent phase separation in the reservoir versus heavy ends that remained in the crude oil, a result that is consistent with heavy end chemical speciation and solvation characteristics. The combination of thermodynamic and compositional considerations proves to be very effective in elucidation of reservoir fluid geodynamic processes that have a significant impact on oil production.

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.

We present a case study of the application of Fluid Mapping While Drilling (FMWD) to acquired logging-while-drilling downhole fluid analysis (FMWD-DFA) in the development stage of a North Sea reservoir. An extensive Wireline DFA (WL-DFA) dataset and Reservoir Fluid Geodynamics (RFG) study helped characterize fluid variations in the exploration and appraisal stages of this field revealing a complex reservoir charge history that results in fluid variations throughout the field and furthermore revealing connections between reservoir quality/productivity and in-situ fluid properties. In the development stage, knowledge acquired in the previous field phases guided well placement decisions and FMWD-DFA was used actively in well construction to validate and enhance the fluid model in this field. FMWD pressure and DFA measurements were acquired in five development wells in the field: three horizontals and two high-angle pilots. DFA measurements provide fluid composition and optical density, which correlates directly with the asphaltene content of the oil. Asphaltene gradients are modeled to assess thermodynamic equilibrium conditions and investigate lateral and vertical connectivity. DFA and other data streams integrated by the RFG analysis provided the base model: a relatively recent secondary migration of light hydrocarbon into the reservoir that resulted in different realizations of the mixing process depending on distance from the charge plane and rate of mixing. Well trajectories were designed to target sweet spots based on appraisal data; however, some level of uncertainty remains when entering the development stage. FMWD-DFA was used to understand fluid property variations throughout the field that may be associated to geological factors or resulting from fluid mixing processes that may yield localized asphaltene instability. FMWD pressure and mobility measurements complement this model and enable an assessment of current levels of pressure depletion from production in a neighboring field in hydraulic communication through a shared aquifer. This field example shows integration of DFA technology from different acquisition platforms at different stages of the life of the field. It illustrates how this technology is used to improve the understanding of the complex fluid variations in this field and make development decisions such as optimizing well design by ensuring placement within reservoir sweet spots.

The Re-Os geochronometer constrains the timing of petroleum formation and provides an oil-source isotopic correlation tool for improved geologic knowledge and exploration success. However, the effects of secondary processes that may sometimes complicate interpretations are not well understood. This paper discusses Re-Os systematics in a petroleum system that experienced extensive asphaltene precipitation upon mixing of different oil phases. The Solveig oil field (formerly Luno II), Utsira high, Norwegian North Sea, comprises three structural compartments that capture different stages of the mixing process. In the central compartment, an Re-Os age of circa 40 Ma for whole-rock extracts sampling the residual (asphaltene-rich and biodegraded) oil below the oil–water contact is consistent with burial models for Paleocene–Miocene generation. A 10-m-thick, asphaltene-rich (65 wt. %) tar mat zone precipitated upon mixing of at least two components does not yield meaningful ages. The Re-Os isochrons for the free-flowing crude oil and whole-rock extracts from the oil leg above the tar mat zone indicate circa 10 to 0 Ma ages for the younger oil phase, supporting independent estimates for recent oil influx. Decreasing 187Os/188Os from maltenes to asphaltenes in oil from the southeastern compartment are highly unusual and provide geochemical evidence for recent mixing, consistent with the strong asphaltene-in-oil gradient. Very low and remarkably uniform Re/Os ratios for all petroleum phases, combined with relatively low and uniform 187Os/188Os ratios, strongly support isotopic overprint of the Re-Os system, likely during water–oil interaction. Despite this overprint, Re-Os ages retain information on primary events, whereas initial 187Os/188Os ratios are strongly affected.

Unlike the free biomarkers, which can be routinely recovered via solvent extraction, the bound biomarkers are covalently linked to the kerogen or asphaltene macrostructures and are more resistant to secondary alteration processes. Although similarities have been identified between these two types of biomarkers using different techniques, it remains unclear how the kerogen- and asphaltene-bound biomarkers are complicatedly corelated with their free counterparts, thus limiting the applications of bound biomarkers in geoscience research. In this study, the characteristics of free biomarkers recovered from shale samples, from 10 sedimentary basin around the world, and petroleum samples, from the North Sea, have been systematically compared with their kerogen- and asphaltene-bound biomarkers, which were released by the newly developed Microscale Sealed Vessel Catalytic Hydrogenation (MSSV-Hy) method. Although the kerogen-bound biomarkers are characterized by the absence of rearranged biomarkers (e.g., Ts and diasteranes) and elevated C29/C30 hopane ratios, many key source-related parameters show strong positive correlations between free and bound fractions, including the steranes/hopane, C27/C29 sterane, C30/C29 sterane, C29/C30 hopane (αβ + βα), C35/C34 homohopanes and C24 tetracyclic terpane/C26 tricyclic terpane ratios. These results suggest that bound biomarkers can reveal critical information about deposits and organic matter precursors of source rocks. Thermal maturity indicators, such as C29 sterane ββ/(αα + ββ), C29 sterane S/(S + R), C31 hopane S/R, and Tβ/Tm ratios, also display excellent correlations between the free and bound counterparts in the source rocks. Although the correlations are not 1:1, empirical formulae, which are based on the correlations between free and bound biomarkers, can be used to calibrate bound biomarkers into values that can be directly compared to routine free biomarkers. Importantly, asphaltene-bound biomarkers of North Sea samples exhibit similar characteristics to kerogen-bound biomarkers, and the conversion between free and bound biomarkers of the source rock and reservoir samples is the same. In summary, the bound biomarkers are found highly effective in determining the organic facies, lithology, and thermal maturity of the parent kerogen and/or asphaltene, and, thus, have a great potential to be widely used in geoscience research when information from free biomarkers is hampered by oil mixing, contamination or biodegradation.

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.

The radiometric dating of geological events was a crucial achievement leading to the establishment of the geological time scale. The dating of the timing of petroleum charge into, and the determination of petroleum residence times in a geological trap would also be significant, as it would remove ubiquitous speculation concerning the history of reservoir charging in any basin setting. A thorough review of prior strategies to estimate the residence time of petroleum fluids in subsurface reservoirs revealed that few if any methods currently used provide useful estimates of the residence age of fluids. This paper is focused on the age dating of petroleum residence time in reservoirs based on the compositional alterations of reservoired fluids caused by natural radiation. This preliminary paper sets out the geochemical landscape and constraints on radiation-based age dating proxies. We report results on the propagation of radiation through reservoir rocks, which indicate that gamma radiolysis is a primary route to crude oil alteration. Gamma ray radiolysis experiments on crude oils at both natural and elevated radiation doses have been completed and the changing crude oil composition observed using LC, GC-MS and NMR. Reservoir fluids are naturally immersed in radioactive subsurface media that cause systematic alteration to crude oil composition with time, but the chemical changes are small in most natural settings. The degree of radiolysis of individual petroleum compounds was found to depend on chemical class, molecular size, initial compound concentration and the nature of the oil matrix, indicating that a proxy system for dating of petroleum charge times and oil residence times in petroleum traps will likely depend on case-specific calibrations. We define the apparent gamma ray radiolysis susceptibility (kGy−1) of different compounds. Large alkanes, such as high molecular weight normal alkanes (>C22) or hopanes, have high radiolysis susceptibility and show the most rapid decrease in component concentration with increasing radiation dose. In contrast, condensed aromatic hydrocarbons and diamondoid hydrocarbons are more resistant to decomposition through radiolysis. While assessing the decrease in concentration of a compound through radiolysis is a practical objective, it is more difficult to assess the production of new, unique radiolysis products given the great diversity and low concentrations of individual compounds produced. However, monitoring the production of specific functional groups during radiolysis of crude oils, using NMR spectroscopy, was found to be a feasible proxy analytical target. Analysis of newly generated carbon-carbon double bonds in bulk crude oils may represent an optimal approach for development as a radiolysis proxy. We propose a route to assessing in-reservoir crude oil radiation dose.

Investigating hydrocarbon generation and expulsion by pyrolysis is limited by methodologies incapable of simulating conditions close to those prevailing in natural systems. Destructive sample preparation, inappropriate pressure regimes and pyrolysis in closed mode and/or in the absence of water caused results not representative for natural processes. We here present a new approach for a laboratory scaled simulation of generation, primary migration and expulsion under near-natural conditions, using the “Expulsinator” device. Near-natural conditions are realized by application of lithostatic pressure onto a source-rock disc with intact pore network and by pyrolysis at the presence of water, conducted in open flow through mode. This study will give a detailed technical description of the apparatus and the methodology to implement an Expulsinator experiment. An Expulsinator experiment generates a combined generation and expulsion profile, resulting in a detailed source rock characterization, incorporating yields for oil and gas, as well as rock deformation data on mm- and μm-scale. Thus, information is provided about timing and amplitude of generation and expulsion events. The apparatus uses a novel way of continuous sampling during the pyrolysis, enabling product removal from the reactor during the generation and expulsion process. Sampling in open flow-through mode is technically demanding and requires stimulation by a modifier for quantitative removal of the expelled products from the reactor. Test experiments demonstrate that the modifier has no impact onto the expulsion behavior of the source rock. Following the technical description, the generation and expulsion profile of one Expulsinator experiment is discussed. Beside information about timing of product generation and expulsion, the experiment shows the connection between rock expansion/compression and expulsion events. The efficiency of this new methodology is compared with conventional closed hydrous pyrolysis. The results exhibit the advantages of the apparatus: Liquid yields are increased, and hydrocarbon (HC) -gas generation reduced, due to a suppression of secondary reaction by the open setup. Furthermore, conventional pyrolysis achieved lower expulsion rates, due to the absence of lithostatic pressure. The Expulsinator shows high potential for further applications, in particular for implementation of lab-simulation data into numeric models.

Hydrocarbon reservoir fluids often undergo dynamic processes such as multiple hydrocarbon charges and biodegradation over geological time. These processes change the spatial distribution of hydrocarbon components in reservoirs and include diffusion, advection and phase change over geologic time. To better understand reservoir fluid geodynamics (RFG), a set of generalized diffusion-advection equations are proposed at isothermal conditions. The Maxwell-Stefan diffusivity in the gravitational field is integrated into the diffusion equations. Thermodynamic models are used to describe nonideality of reservoir fluids and phase separation. The generalized diffusion-advection equations are then simplified for a 1-D diffusion problem. The 1-D diffusion model is applied to the Lundin oilfield case study in Norway. The reservoir fluids are simply grouped into three pseudocomponents: gas (including solution gas), asphaltene and maltene. The Peng-Robinson equation of state is employed to estimate the parameters in the Flory-Huggins regular solution model. A ternary phase diagram including binodal and spinodal phase boundaries is computed based on the thermodynamic model. Asphaltenes are further treated as two forms: nanoaggregates and clusters in the gravitational diffusion term. The new RFG model captures the main physics of the reservoir fluid geodynamic process in the field case. Because gas (light hydrocarbon) charging from the top of the oil column leads to an increase in oil solution gas and a decrease in oil solvency capability to dissolve asphaltenes, asphaltenes are expelled downwards and accumulate at the base of the oil column. In addition, because asphaltene clusters have much bigger sizes than nanoaggregates, they increase the rate of asphaltenes accumulation at the base of the oil column over geological time. The resulting single RFG model is used to account for two adjacent reservoirs with very different fluid distributions. In fault block 1, there are large, disequilibrium gradients of solution gas and asphaltenes with little asphaltene deposition. In this fault block, the rate of diffusion is reduced by known reservoir baffles. In contrast, in fault block 2, the diffusion and asphaltene migration processes essentially went to completion yielding equilibrated solution gas and asphaltene gradients. In addition, after migration to the base of the oil column, the asphaltenes underwent phase separation with increasing solution gas. The same RFG model is used for both fault blocks but with different rates of diffusion associated with the known difference in reservoir baffling. This RFG model accounts for all measured fluid gradients and asphaltene phase separation in two fault blocks with very different distributions. In addition, the primary difference in the two adjacent reservoirs is the extent of reservoir baffling; this parameter created a factor of ten difference in production rates from these fault blocks. This new fluid modeling accounting for the reservoir fluid geodynamic processes in reservoirs is shown to impact major production concerns.

Background High primary productivity in the midst of high toxicity defines hydrocarbon seeps; this feature usually results in significantly higher biomass, but in lower diversity communities at seeps rather than in the surrounding non-seep benthos. Qualitative estimates indicate that this dichotomy does not necessarily hold true in high latitude regions with respect to megafauna. Instead, high latitude seeps appear to function as local hotspots of both megafaunal diversity and abundance, although quantitative studies do not exist. In this study, we tested this hypothesis quantitatively by comparing georeferenced seafloor mosaics of a seep in the southwestern Barents Sea with the adjacent non-seep seafloor. Methods Seafloor images of the Svanefjell seep site and the adjacent non seep-influenced background seabed in the southwestern Barents Sea were used to construct georeferenced mosaics. All megafauna were enumerated and mapped on these mosaics and comparisons of the communities at the seep site and the non-seep background site were compared. Sediment push cores were taken in order to assess the sediment geochemical environment. Results Taxonomic richness and abundance were both considerably higher at the seep site than the non-seep location. However, taxa were fewer at the seep site compared to other seeps in the Barents Sea or the Arctic, which is likely due to the Svanefjell seep site exhibiting relatively low seepage rates (and correspondingly less chemosynthesis based primary production). Crusts of seep carbonates account for the higher diversity of the seep site compared to the background site, since most animals were either colonizing crust surfaces or using them for shelter or coverage. Our results indicate that seeps in northern latitudes can enhance local benthic diversity and this effect can take place even with weak seepage. Since crusts of seep carbonates account for most of the aggregating effect of sites experiencing moderate/weak seepage such as the study site, this means that the ability of seep sites to attract benthic species extends well beyond the life cycle of the seep itself, which has important implications for the larger marine ecosystem and its management policies.

Asphaltenes can be dispersed in crude oils in 3 different forms; molecules, nanoaggregates (of molecules) or clusters (of nanoaggregates); these forms are codified in the Yen-Mullins model and relate to the extent of solvency of the asphaltenes in the crude oil. Many reservoir studies are used here to show the systematic behavior of the specific asphaltene species in crude oil and the corresponding magnitude of the asphaltene (and viscosity) gradients. In addition, the specific asphaltene species is related to the chemical origin controlling asphaltene onset pressure (AOP) and tar formation and depends on 1) the quality of the live crude oil solvent for asphaltenes and 2) the concentration of asphaltenes. Elevated quantities of solution gas of a reservoir crude oil significantly reduce the solvency of asphaltenes in crude oil. For low concentrations and/or good solvency, asphaltenes are dispersed in crude oils as molecules with small gradients (unless there are large GOR gradients). For moderate concentrations and/or moderate solubility, asphaltenes are dispersed as nanoaggregates with intermediate (gravity) gradients of asphaltenes. With large concentrations and/or poor solvency, asphaltenes are dispersed as clusters with very large gradients in reservoirs. These crude oils can also exhibit higher asphaltene onset pressures and/or phase separated bitumen or tar in the reservoir depending on the origin of asphaltene cluster formation. Secondary gas charge into oil reservoirs can yield tar and/or a high AOP. The effect of biodegradation on these factors is also discussed. The systematics presented here are helpful in understanding a variety of reservoir concerns associated with asphaltenes.

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.

Reservoir fluid geodynamics (RFG) has recently been launched as a formal technical arena that accounts for fluid redistributions and tar formation in reservoirs largely after trap filling. Elements of RFG, such as analysis of biodegradation, have long been in place; nevertheless, RFG is now strongly enabled by recent developments: 1) downhole fluid analysis (DFA) allows routine elucidation of reservoir fluid gradients, 2) the development of the first equation of state for asphaltene gradients allows identification of equilibrium vs. geodynamic processes of reservoir fluids and 3) RFG analyses of 35 oilfields systematize a multitude of RFG processes and show their direct impact on wide-ranging production concerns. Thermodynamic analyses identifying reservoir fluid geodynamic processes rely heavily on measurement of fluid gradients to avoid ambiguous interpretations. The unique role of asphaltene gradients and their integration with other data streams are the focus herein. RFG oilfield studies have repeatedly shown that analyses of asphaltene gradients are critical to proper evaluation of RFG processes. Naturally, any reservoir concern that directly involves asphaltenes such as heavy oil, viscosity gradients, asphaltene onset pressure, bitumen deposition, tar mat formation, and indirectly, GOR gradients are strongly dependent on asphaltene gradients. Moreover, as shown in numerous case studies herein, asphaltene gradients can be measured with accuracy and the corresponding thermodynamic analyses allow explicit identification of RFG processes not traditionally associated with asphaltenes, such as analysis of connectivity, fault block migration, baffling, spill-fill mechanisms and many others discussed below. In turn, these processes imply other corroborative reservoir and fluid properties that can then be confirmed. Crude oil chemical compositional data, such as ultrahigh resolution two-dimensional gas chromatography, combined with geochemical interpretation, is highly desirable for understanding RFG processes. Nevertheless, biomarkers and other fluid properties often exhibit small gradients relative to standard deviations (except with biodegradation) but often can still corroborate specific RFG processes. In general, integration of fluid gradient analysis with other data streams including petrophysics, core analysis, stratigraphy, geology and geophysics is critical; nevertheless, which integration is most needed depends on particular reservoir attributes and RFG processes that are in question. Examples of data integration are shown for ten reservoirs undergoing various fluid geodynamic processes. Asphaltene gradient analysis is relatively new, yet it is essential for characterization of RFG processes.

Is natural radioactivity a significant agent of hydrocarbon gas generation from sedimentary organic matter? Laboratory gamma radiation of dead crude oil (no solution gas) yields wet hydrocarbon gases depleted in 13C: δ13C CH4 (−75‰ to −65‰), δ13C C2H6 (−52‰ to −45‰), δ13C C3H8 (−42‰ to −37‰) and δ13C n-C4H10 (−35‰ to −32‰). Although laboratory irradiation dose rates are orders of magnitude higher than those in geological settings, radiolytic transformations occur at total radiation doses equivalent to those in natural geological settings over many millions of years. Radiolysis generates wet gases with isotopic signatures that might be interpreted as “biogenic” if only the methane carbon isotope ratio is considered. We examine situations where such gases may be quantitatively significant.

Petroleum system modeling provides the timing, type and volume of fluids entering a reservoir, among other things. However, there has been little modeling of the fluid processes that take place within the reservoir in geologic time, yet these processes have a dramatic impact on production. Modeling and understanding of the reservoir then reinitiates with simulation of production for optimization purposes. The new discipline "reservoir fluid geodynamics" (RFG) establishes the link between the petroleum system context or modeling and present day reservoir realizations. This new discipline has been enabled by scientific developments of the new asphaltene equation of state and by the technology of downhole fluid analysis (DFA). Gas-liquid equilibria are treated with the traditional cubic EoS. Crude oil fluid- asphaltene equilibria are treated with the Flory-Huggins-Zuo equation of state with its reliance on the Yen-Mullins model of asphaltenes. Thermodynamic treatment is essential in order to identify the extent of equilibrium in oil columns, thereby identifying fluid dynamics in geologic time. DFA is shown to be very effective for establishing asphaltene gradients vertically and laterally in reservoir fluids with great accuracy. In turn, this data tightly constrains the thermodynamic analyses. These methods have been applied to a large number of reservoir case studies over a period of ten years. For example, case studies are shown that indicate baffling and lower production for parts of the reservoir that have slower rates of fluid equilibration. In addition, the newly revealed lateral sweep in trap filling is established via RFG case studies. Underlying systematics, especially for gas charge into oil reservoirs, have been revealed for a large number of fluid and tar distributions that enable a unifying and simplified treatment for seemingly intractable complexities. A case study is presented that shows three very different reservoir realizations in adjacent fault blocks for the same petroleum system model, where RFG explains all these differences. This enables key reservoir properties to be projected away from wellbore in ways not previously possible. Finally, universal work flows are shown which enable broad application of these methods through all phases of reservoir exploration and production.

Deposition of organic solids high in asphaltene content (tar, bitumen) in reservoirs from natural processes is a routine occurrence around the world. Nevertheless, there is a bewildering array of deposition characteristics as shown in recent case studies. Sometimes this tar or bitumen (both are really the same material) is at or near the crest; sometimes it is on interlayers within a heterolithic sequence (baffles) or at the base of the reservoir which can be tens of kilometers away from the crest. Sometimes the bitumen deposition is such that the corresponding formation remains permeable; sometimes the tar zone is totally impermeable. Sometimes the tar at the base of the reservoir represents a more or less continuous increase in asphaltenes from the oil immediately above the tar; sometimes there is a sharp, discontinuous increase in asphaltene content from the oil to the tar. And particularly for upstructure bitumen, sometimes the bitumen is deposited throughout the entire producing interval (in a well); at other times the bitumen deposition is only at the base of the producing interval. This paper shows that ALL of these variable tar or bitumen characteristics can be understood within simple concepts that treat the dissolved asphaltene in crude oils and the deposited asphaltene within the same framework. This framework utilizes simple chemical solution characterisitcs that are formally expressed in the Flory-Huggins-Zuo Equation of State for asphaltene gradients with its reliance on the Yen-Mullins model of asphaltenes. Multiple charges of incompatible fluids lead to asphaltene deposition. The extent of slow, diffusive destabilization from density stacking charge fluids versus rapid destabilization from a secondary lateral fluid front controls much of the characteristics of deposited asphaltene. Consequently, the proximity of the well to reservoir charge points as well as petrophysical parameters of the formations are very important parameters. The ideas herein enable projection of the nature of asphaltene deposition away from a wellbore to other locations in the reservoir. This capability greatly assists the ability to understand the impact of asphaltene deposition on production.

In this reservoir study, three adjacent structures have been subject to largely the same fluid charge with an original oil charge and a very recent light hydrocarbon charge (all indicated by petreolum systems modeling and organic geochemical analyses). In addition, all wells have an oil-water contact (OWC) and two have a gas-oil contact (GOC), while the GOC in the third well is not far away. Thus, all depth-dependent in-reservoir fluid geodynamic processes are visible within each well; no extrapolation away from the wells is required. Moreover, the ~30 meter oil columns in evidently connected sands are amenable to simple dynamic modeling thereby aiding in understanding. All three structures are found to have very different reservoir realizations, particualry regarding the dispositions of asphaltenes in spite of nominally similar initiation conditions after the secondary charge. That is, different reservoir fluid geodynamic processes took place producing different constraints on production in each of the structures. One well showed a light oil underlain by a tar mat. A second well showed large, disequilibrium gradients of gas-oil ratio (GOR) and asphaltene content without phase separated asphaltenes in core. The third well showed a tar mat on a shale break in the oil column not far form the GOC. There were no asphaltenes in core above the shale break and tar mat. However, below the shale break there was asphaltene throughout the core while retaining permeability, but no tar mat on the OWC. These differences were not ascribed to any paleo-OWC nor are they related to differing biodegradation. In addition, these differences are not consistent with any depressurization expalanation. To resolve the differences, a variety of data streams were used including downhole fluid analysis coupled with thermodynamic analysis from the Flory-Huggins-Zuo Equation of State (FHZ EoS) and its reliance on the Yen-Mullins model of asphaltenes. In addition, well test results provide key production information and are corroborated by vertical intereference testing on wireline. Petroleum system modeling and organic geochemical analysis of oil and core extract samples have also been very useful. The differences seen in the different wells relate to several important parameters such as the different extent of baffling which impacts both production rates as well as equilibration rates of reservoir fluids. Another key parameter is the extent of density stacking versus a lateral fluid front for the secondary light hydrocarbon charge. Proximity to the charge point enhances the lateral nature of the charge yielding rapid asphaltene instability precluding tar mat formation in sections of the well. This information is very useful when projecting reservoir properties away form wellbore.

The Bakken Formation of the Williston Basin is a prime example of an unconventionally produced petroleum system, with a low-permeability reservoir that requires application of advanced technologies for commercial production. A three-dimensional model of the Williston Basin was constructed to integrate and assess the parameters that influence the generation and migration of hydrocarbons in the Bakken Formation. This study tests the applicability of available basin and petroleum system modeling technology on an unusually low-permeability petroleum system. The model is based on nine surfaces constructed from log tops of thousands of wells in the study area and additional depth and isopach maps of the Bakken Formation members. These were integrated with the established basin evolution in line with published research. Temperature and thermal maturity were calibrated during model construction from well temperature and geochemistry data. The resulting heat-flow map supports the existence of a heat-flow anomaly along longitude 103W, discussed controversially in the literature. Furthermore, the results indicate that the invasion-percolation migration approach best describes the distribution of petroleum accumulation and the saturated areas in the Bakken members. The volume of generated hydrocarbons was calculated, and the extent of the highly saturated accumulation beyond the area of the high-mature source was mapped. Furthermore, it was demonstrated that petroleum accumulations beyond the high-saturation zones have to be related to stratigraphic pinch-outs, lateral variability in permeability of the Bakken members, or smaller structural influences that were lost because of the resolution applied in the model.

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

Petroleum asphaltenes exhibit strong structural similarities to their parent kerogen. Thus, they can be used to help determine the source rock characteristics of active kitchen areas and to reconstruct the filling histories of reservoirs. The analysis of asphaltenes from compartmentalised reservoirs with complex charging and alteration histories presents a particularly difficult challenge because the in situ compositional variations are sometimes subtle. It is, therefore, of paramount importance that asphaltene separation methods be utilised which are highly reproducible and linear, thereby minimising experimental uncertainty and providing high resolution interpretative capability. The asphaltene separation method described here is built on many that have been proposed before. Different parameters for asphaltene separation were investigated, which influence the asphaltene amount and properties, with the main focus on reproducibility and linearity. Gravimetric and thermal analysis techniques were used to evaluate yield and quality. The developed asphaltene separation method described in detail has four sequential steps: (1) dissolution of the oil in dichloromethane/1 vol% methanol, (2) addition of an excess of n -hexane, (3) settling time and (4) filtration, purging and weighing; this sequence of steps is repeated three times. Results concerning the reproducibility depending on solvent type, solvent amount and aging time, as well as the linearity depending on sample amount, are presented.

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.

Biodegradation rates in oilfields have been assessed conservatively using whole oil-column minimum rate estimates, diffusion-controlled oil column compositional gradient modelling and mixed oil kinetic models. Biodegradation rate constants (first order) are around 10−6–10−7 yr−1 for hydrocarbons in the degradation zones these corresponding well with zero order field-wide minimum rate estimates of about 10−8 kg hydrocarbons/kg oil/year for the whole oil column. With biodegradation induction times of around 1–2 Ma to perturb an entire oil column for light oil reservoirs and 10–20 Ma for heavy oil reservoir degradation the results indicate that where we see continuous gradients in the oil columns, degradation must have been occurring episodically for many millions of years. To remove the n-alkanes from an oil (i.e. about 10% of an oil) around ca 15 Ma is needed for a heavy oil (ca 5 Ma for a light N. Sea oil). The timescales of oilfield degradation and filling are thus very similar and consequently the degree of biodegradation will be substantially controlled by oilfield charge history. Assessment of mixed degraded/non-degraded oil occurrence provides an independent confirmation that these rates are realistic and that timescales of degradation and field charging are similar. The maximum effective rate constant of degradation, ultimately controlled by the limiting effect of diffusion of alkanes to the oil water contact (OWC) (ca 10−4 yr−1 for a 130 m thick oil column first order rate constant) is well above the estimated rate constants indicating oil biodegradation rate is not limited by electron donor supply (i.e. hydrocarbons) but by supply of nutrients or oxidants. This suggests that diffusive transport of nutrients and electron acceptors in the aquifer to the site of biodegradation may be adequate to maintain the low rate biosphere.

Six years ago, the Upper Jurassic Haynesville Shale play was largely unknown as an unconventional shale play. US government and oil company resource assessments for such unconventional plays vary significantly. Here we attempt to estimate resource potential using a full mass balance approach based on data from more than 1600 recently drilled wells, integrated into a 3D petroleum systems model. Numerous iterations were conducted to simulate heat flow in the study area. The simulated heat flow calibrated to vitrinite reflectance data from 26 wells suggests that a slight increase in heat flow may have occurred with every uplift event over the Sabine Uplift area. Laboratory analysis of a number of Haynesville Shale samples taken from six wells reported an original total organic carbon (TOC) content, which is on average 3% for all samples. Additional Rock-Eval analysis revealed that all of the samples taken from the wells are overmature. Adsorption isotherms were determined on one representative sample and implemented in the modelling approach to calculate adsorbed gas volumes. After simulation, the accumulation calculations in the Haynesville Shale revealed a total amount of 2056tcf of adsorbed gas (79.15% Methane) and 1511tcf of free gas (87.12% Methane). These numbers seem to be very high, but considering a recovery factor of 5 or 10% the combined producibility of gas based on our model will be equal to 178 or 357tcf respectively. Most of the primary production of gas occurred during the Aptian-Albian, and secondary cracking produced most of the free gas during the Early-Eocene. The model also shows wide variability in pore pressure and the generation of abnormal pressures. This variation in pore pressure occurs in the Haynesville Shale and results from a combined effect derived from the overlying Cotton Valley/Bossier Formation and the underlying Smackover Formation. As a final observation, the critical moment of the Haynesville Shale petroleum systems has been dated to be at the Turonian and Early-Eocene. At this point all petroleum system elements and process have been satisfied for the conventional and the nonconventional play respectively.

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 (...

Regional seismic reflection and potential field data document the South Atlantic's break-up history, between 39°S and 19°S, from the Early Cretaceous onwards. Previous maps of distribution of volcanics along the margin showed volcanics along the whole African margin based on extrapolation of data. Based on previously unpublished marine geophysical data, we found the southernmost 460 km long margin segment to be lacking huge volumes of break-up related volcanic effusives. Northwards, break-up was accompanied by the emplacement of huge volumes of volcanic material, prominently featured in seismic sections as huge wedge-shaped seaward dipping reflectors (SDRs). Detailed mapping of offsets (left- and right-stepping) and variations in structural character of the volcanics reveal the segmentation along and the break-up history of the margin. Several superimposed SDR sequences, suggesting episodicity of volcanic emplacement (divided by periods of erosion and sedimentation), are distinct along southerly lines, losing prominence northwards. A main outcome of our study is that this passive margin is not continuously of the volcanic type and that the change from a non-volcanic to a volcanic margin occurs abruptly. We define four distinct First-order Segments along the 2400 km section of the southwestern African margin covered by our seismic data. From south to north these First-order Segments are: Magma-poor Segment I; Segment II with enormous SDRs volumes; decreasing SDRs volumes in Segment III; Segment IV again with enormous volcanic output, likely influenced by Walvis Ridge volcanism. Most important is that there is no systematic increase in the volumes of the effusives towards the Tristan da Cunha hot-spot. Rather there is an alternating pattern in the SDRs' volumes and widths. The boundary between the volcanic and magma-poor margin segments in the southernmost study area is sharp (10s of km), which we propose is reflected in magnetic anomaly data as well. We suggest that this variability along the margin is mainly due to a change in stretching/rifting character from oblique during the early stages of breakup to conventional seafloor spreading from Chron M4 (∼130 Ma) onwards.

The Upper Jurassic Haynesville Shale play covers an area extending through East Texas, northwest Louisiana and parts of southwest Arkansas. The true potential of this play as an unconventional play was largely unknown. Only after gas prices increased during the last decade oil companies started to see the Haynesville Shale as an economic shale gas play, despite its great depths of over 3000m. At present gas prices the Haynesville Shale is due to its depth once again of only marginal interest, however, in order to be prepared for renewed interest a fundamental understanding of the processes and timing controlling shale gas prospectivity is required. In order to understand the variables of this unconventional play, we have identified the heat flow history as a critical control. Heat flow values and evolution through time can impact the critical timing of gas generation, secondary cracking of oil to gas, and oil and gas generation critical moments. Using state of the art basin modeling software, a reconstruction of the heat flow history was performed. Predicted formation temperatures were calibrated against temperature data collected from 1644 wells drilled over the play. Paleo-temperature evolution was calibrated against vitrinite reflectance data collected from 26 wells. Laboratory Rock-Eval analyses were utilized to assist in this study over 6 wells. The area has been subjected to three major tectonic uplift events. After various simulation iterations we conclude that the heat flow increased slightly with each uplift event. This suggests that the uplift was accompanied by heat flow increase indicating a likely igneous control, which had a large impact on the heat flow history within the area. Such understanding proves to be vital in order to perform accurate hydrocarbon resource assessments.

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.

The glacially influenced southwestern Barents Sea is a promising area for petroleum exploration. The present study area, which is located in the Loppa High region, exhibits extensive pockmark fields covering an area of several square kilometers and containing thousands of pockmarks in high density. To investigate whether the pockmark formation was driven by petroleum leakage to the surface, acting thus as indicators for an active petroleum system, gravity cores from selected pockmark and reference sites were investigated using an organic geochemical approach. Various biomarkers indicative of thermogenic hydrocarbons such as short chain n-alkanes with a low carbon preference index, alkylcyclohexanes, αβ-hopanes, steranes and diasteranes mixed with biomarkers representing immature organic matter were detected in the pockmark, but also in reference cores outside of the pockmark and even from a non-pockmark area. The abundance and level of thermal maturity of the thermogenic hydrocarbons are comparable between the pockmark and reference sites. Additionally, their distribution with depth is quite similar to those of the immature biomarkers. These observations support the conclusion that the thermogenic hydrocarbon signal in the pockmarks is the result of reworked, eroded mature material mixed with immature organic matter distributed across the entire area, rather than the result of seepage events of thermogenic hydrocarbons through the pockmark system. The data show that in the Loppa High region the pure presence of petroleum-derived hydrocarbons in pockmark areas cannot be used to indicate the presence or leakage of deeper petroleum systems.

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.

Based on the analysis of the high-resolution 3D seismic data from the SW Barents Sea we study the hydrocarbon plumbing system above the Snohvit and Albatross gas field to investigate the geo-morphological manifestation and the dynamics of leakage from the reservoir. Fluid and gas escape to the seafloor is manifested in this area as mega-pockmarks 1–2 km-wide, large pockmarks (

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.

Multibeam bathymetry revealed the occurrence of numerous craterlike depressions, so-called pockmarks, on the sea floor of the Hammerfest Basin and the Loppa High, south-western Barents Sea. To investigate whether these pockmarks are related to ongoing gas seepage, microbial processes associated with methane metabolism were analyzed using geochemical, biogeochemical and microbiological techniques. Gravity cores were collected along transects crossing individual pockmarks, allowing a direct comparison between different locations inside (assumed activity center), on the rim, and outside of a pockmark (reference sites). Concentrations of hydrocarbons in the sediment, particularly methane, were measured as headspace (free) gas, and in the occluded and adsorbed gas fraction. Down to a depth of 2.6 m below sea floor (mbsf) sulfate reduction rates were quantified by radiotracer incubations. Concentrations of dissolved sulfate in the porewater were determined as well. Neither the sulfate profiles nor the gas measurements show any evidence of microbial activity or active fluid venting. Methane concentrations and sulfate reduction rates were extremely low or even below the detection limit. The results show that the observed sediment structures are most likely paleo-pockmarks, their formation probably occurred during the last deglaciation.

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.

We use a high resolution 3D seismic dataset covering 970 km2, over the Snohvit and Albatross gas fields of the Hammerfest Basin in the Barents Sea, in order to investigate the basin fault architecture and identify potential fluid pathways of deeper thermogenic gas and fluids. A polygonal fault (PF) interval not previously published is described in the three non-connected blocks within Campanian sequences, which could imply a permeable complex network of pathways that facilitate the vertical migration of hydrocarbons along the fault planes. The dominant orientation of the PFs is similar to the main regional tectonic fault trend (EW), suggesting a tectonic influence upon the development of polygonal faults, although some individual PFs locally seem to develop orthogonally to regional 1st order tectonic faults. A lithologic control on the occurrence of PF patterns is evident as none are observed within calcareous low clay sediments. The PF networks present three main orientations: dominant ENE/WSW, secondary NNE/SSW and a minor NE/SW. Paleocene–Early Eocene Faults (PEEFs) prevail above the PF networks, with coinciding ENE/WSW fault strikes, interpreted as preferential reactivation of the PF systems. Numerous amplitude anomalies, linked to the escape of thermogenic fluids from the Jurassic reservoir were identified. We present a conceptual model where the 1st order reactivated faults and PEEFs acted as pathways for fluids from the deeper hydrocarbon reservoirs. The PEEFs are partially sealing with a lateral migration component. Interplay between the PFs, PEEFs and the 1st order reactivated faults focuses the fluids vertically along the polygonal fault traces creating a wider diffuse zone which form large gas cloud anomalies in the seismic data.