Petroleum System Elements Research Articles

US central Atlantic: new plays and petroleum prospectivity

Abstract During the complex evolution and transition of the United States (US) Central Atlantic from a rift system to a passive margin, five post-rift sedimentary depocentres developed along its approximately 1850 km length. Varying in size, shape and thickness of sediment fill, these depocentres are separated by interbasin arches and regions lacking major post-rift sedimentary depocentres. From 1976 until 1984, a single phase of exploratory drilling was carried out in three of these depocentres. Located primarily on the continental shelf, the tested play types resulted in a single, modest natural gas discovery. The drilling clarified the risks of various petroleum system elements and processes in the areas and plays tested. During 2010, a new resource inventory covering the area was completed by a team of Bureau of Ocean Energy Management geologists and engineers. The inventory incorporated and applied modern exploration concepts and key new learnings from NE-adjacent offshore Nova Scotia, conjugate NW Africa and the African transform margin. Nine new conceptual plays and a single proven high-risk play have been identified and their resources inventoried.

The geometric characteristics, genesis and petroleum significance of inversion structures

Abstract Inversion structures are now recognized in most orogenic belts and in many other tectonic settings, however, this has not always been the case. For many years the thin-skinned paradigm dominated the interpretation of thrust belts which resulted in many inversion structures being erroneously interpreted as thin-skinned thrusts. In rift basins, intra-cratonic basins and on passive margins inversion structures were often interpreted as having alternative origins, for example, strike-slip deformation. The classic paper of Bally described the geometric characteristics of inversion structures, in which he identified the extensional fault geometry and its subsequent compressional reactivation as essential requirements of an inversion structure. The increased recognition of inversion structures in a wide variety of tectonic settings is illustrated by four hydrocarbon exploration case studies. The geometric characteristics of inversion structures are remarkably consistent irrespective of the tectonic setting and by applying a few simple criteria they can easily be identified. The impact of inversion on hydrocarbon prospectivity is a function of the control on the petroleum system elements from the initial extensional tectonic history and of the later compressional tectonic history which commonly creates new, or modifies old trap configurations.

The search for a Carboniferous petroleum system beneath the Central North Sea

Abstract This paper integrates interpretations of modern long-offset seismic datasets with potential field anomalies derived from dense grids of 2D gravity and magnetic data to present a regional-scale synthesis of Devonian, Carboniferous and Early Permian basin development beneath the UK Central North Sea. The 95 000 km 2 study area has had little modern exploration for petroleum systems beneath the Upper Permian. Seismic interpretation and potential field modelling confirm that along the southern fringe of the Central North Sea, as in northern England, Lower Carboniferous basin development was strongly influenced by the disposition of granite-cored Lower Palaeozoic basement blocks – Farne Block, Dogger Block and Devil's Hole High. This study adds a previously unidentified WNW–ESE trending pre-Devonian basement block, the Auk–Flora Ridge, that exerted a profound control on Late Devonian to Mesozoic structural evolution of the south-Central North Sea. From the Flora Field, where it is overlain by relatively thick mid-Devonian to earliest Permian strata, the sub-Permian relief of this block becomes progressively shallower towards the NW. On its southern flank lies a parallel half-graben, akin to the Stainmore Trough in northern England, and interpreted as also containing several thousand feet of Lower Carboniferous strata. As indicated by the coal measures section in well 39/7-1, these strata are likely to include prolific source rocks, which have been modelled as being fully mature for oil generation in Quadrant 29. Potential field modelling extends this interpretation beyond the current seismic coverage, and suggests that Carboniferous to earliest Permian basin development in the Central North Sea was strongly influenced by an underlying Scottish–Norwegian SW–NE trending Caledonoid structural fabric. An earliest Permian, Lower Rotliegend unit thickens southwards towards the Auk–Flora Ridge, and rests unconformably on one or more undrilled NE–SW trending Carboniferous basins. Red-bed fluvial facies akin to those at Flora are likely to dominate the substantial post-Dinantian fill of these basins, but significant thicknesses of Westphalian coal-measure source rocks may also be present locally. As in central Scotland, the Dinantian strata underlying a widespread mid-Carboniferous unconformity in these basins are likely to contain further coal-measure intervals and local developments of oil-shale source rocks. These Westphalian and Dinantian source rocks are key elements of a Carboniferous petroleum system that remains largely untested across large areas of the Central North Sea.

Miocene facies associations and sedimentary evolution of the Southern Transylvanian Basin (Romania): Implications for hydrocarbon exploration

The Transylvanian Basin is a mature hydrocarbon province of Romania characterized by two petroleum systems: Mesozoic (thermogenic) and Miocene (biogenic). An extensive outcrop-based sedimentological and micropaleontological study correlated to seismic and well data discusses the elements of the Miocene petroleum system. The facies associations are indicative of alluvial, fandelta, shallow- and deep-marine settings. These are grouped into four different depositional systems (evaporite, mud-carbonate, sand-mud and sand-gravel). Their evolution in time and space shows large differences between various parts of the basin that have important consequences for exploration. The Transylvanian gas is formed by more than 99% methane of bacterial origin. This is sourced by low quality (<1% TOC) deep-marine shales. The shales contain Type II and Type III kerogen. The organic material is thermally immature. The best source rocks were deposited during major transgressions in the central-eastern parts of the basin. In general, reservoir quality is the best (porosity < 20%, permeability < 1 D) in the basin center, where reservoirs are deep-marine turbidite sandstones. Lower quality reservoirs are conglomerate-rich slope channels and various shallow-marine sandstones located near the basin margins. The seals are formed by shales that hold gas columns of up to 60 m. The most common structural traps are in 4-way dip closures related to salt-cored folds. Their timing is coeval with the late (post-Pannonian) exhumation of the basin and strongly linked to coeval salt tectonics. This requires a late charge and migration. The largest traps typically have multistory (up to 20) pay zones with a total of 100 BCF to 1 TCF reserves. Exploration to date has focused on structural traps, but most of the obvious structures have been drilled. It is argued that significant exploration potential lies in stratigraphic plays, including confined submarine fans, slope channels, detached lowstand prograding wedges, incised valleys, diapir flanks, salt-tectonics related unconformities and various sub-volcanic plays. Risks of the petroleum system elements associated to these plays in different areas of the basin are discussed.

Comparative petroleum systems analysis of the interior basins of Turkey: Implications for petroleum potential

The interior basins of Turkey remain effectively unexplored and their petroleum systems are poorly understood. This paper presents a comparative summary of the geological evolution, petroleum potential and prospectivity of the Central (Tuz Gölü, Sivas and Çankırı) and East Anatolian (Muş-Hınıs, Pasinler-Horasan and Tercan-Aşkale) basins using geological, seismic, geochemical and petrophysical data, and a series of quantitative basin models. The studied basins are ranked on the basis of source effectiveness, reservoir quality, seal efficiency, and the timing of hydrocarbon expulsion and migration relative to trap formation. A qualitative risk assessment, based on the elements of the petroleum system, is used to evaluate the likelihood of hydrocarbon discovery in each of the basins. This study shows that the chance of hydrocarbon discovery in the East Anatolian basins is unlikely-very unlikely and Tuz Gölü, Sivas and Çankırı basins are equally likely/unlikely-unlikely, likely and unlikely, respectively. Heavy oil and minor gas associated with two mature petroleum systems were discovered in the Tuz Gölü basin. Various trap forming mechanisms such as salt tectonics and Middle Eocene compression, accompanied by the effective sealing capacity of the Eocene evaporites favor the hydrocarbon exploration potential of the Tuz Gölü basin. The highest exploration risk in the Tuz Gölü basin arises from the poor quality sandstone reservoirs. The biggest risk factor in the Eastern Anatolian basins is insufficient thermal maturity, despite the presence of good quality source rocks. The Sivas basin is one of the most promising interior basins of Turkey due to the presence of multiple mature petroleum systems and high quality reservoirs. There is a high chance of accumulation of multi-phase hydrocarbons in the Eocene and Miocene traps. The major problem in the Sivas basin is the lack of an efficient seal rock. The Çankırı basin contains all of the necessary elements of an ideal petroleum system except the presence of an organic-rich source rock. Thus, the chance of hydrocarbon discovery in the Çankırı basin is low.

What can deep seismic reflection data tell us about hydrocarbon prospectivity in onshore

Now in its third year, Geoscience Australia’s Onshore Energy Security Program has acquired several suites of regional geological and geophysical data. The data includes several deep seismic reflection surveys that have been designed to image: basement provinces with high geothermal gradients that may contain uranium enrichments and are potential candidates for geothermal energy; geological terrane boundaries; and, sedimentary basins that are known to host petroleum system elements but are under-explored. Seismic signals are recorded down to 20 seconds two-way-time (TWT) which corresponds to 25–35 km depth depending on dominant lithologies. Basinal sections normally extend down to 6–8 sec TWT and the data is of such high quality that any section of the seismic profile can be enlarged without significant loss of resolution. Deep reflection surveys are able to image the relationship between crystalline basement and overlying basin sequences very clearly and also allow interpretations of structural styles as well as impacts of deformational processes on the basin-fill. A new basinal section was discovered beneath the Eromanga Basin suite of sediments. Named the Mullangera Basin,its structural style and basement relationship seem to indicate some affinity with the Georgina Basin, located further west. The succession is clearly composed of several sequences that contain both fine and coarse-grained sediments. If a geological relationship with the Georgina Basin can be ascertained, a new hydrocarbon prospective area could be delineated. Another new section was discovered beneath the Devonian section of the Darling Basin. Judging by the fast acoustic velocities, the entire basin-fill sequence appears to be very dense and therefore largely non-porous and of low permeability. While low poro-perm characteristics would normally be translated to low prospectivity for oil and gas, the potential for unconventional hydrocarbons such a tight-gas and shale-gas warrants further attention.

Classification of rifted sedimentary basins of the Pannonian Basin System according to the structural genesis, evolutionary history and hydrocarbon maturation zones

We apply the concept that sedimentary basins can be classified according to their structural genesis and evolutionary history to the Tertiary rifts of the Pannonian Basin of Eastern Europe. We have approached the classification by breaking the basins down into the cycles or stages that they comprise. This approach helps us to understand the basin evolution better and allows us to compare the basins more easily. The drivers that define the cycles of basin history are (1) basin-forming tectonics, (2) sedimentary processes, and (3) basin-modifying tectonics. We link common elements of petroleum systems and plays to these natural cycles or stages in basin evolution to improve the prediction of which plays could be expected to occur in a particular basin or region. This concept is constructed through several steps. These steps are (1) to identify standard evolutionary patterns related to geodynamic drivers, (2) to group the basins with similar tectono-stratigraphic evolution and correlate these with petroleum system development, (3) to relate basin trap types to basin history and (4) to calculate characteristic hydrocarbon maturation zones by thermal modeling. We present an application to the Pannonian Basin System of Eastern Europe, an area formed by Miocene back-arc extension and affected by compressional reactivation during its late-stage evolution. The sub-basins of the Pannonian Basin System appear to have experienced comparable magnitudes of deformation, to have developed similar trap types and to have experienced a characteristic hydrocarbon maturation history in a way that supports play prospectivity.

Exploration risk evaluation using object-based modeling, an example from the Tertiary fractured play, western Qaidam Basin of China

Geological risk evaluation reveals the uncertainty of converting an anticipated resource potential in an identified exploration target into an economic petroleum accumulation prior to drilling. Providing consistent and unbiased estimates of geological risk for all exploration targets in an area of interest is essential in risk evaluation. This paper discusses the potential use of an object-based stochastic procedure for geological risk evaluation at the play level. The object-based model of SuperSD, as a data integration tool, can integrate geological information of petroleum system elements that control occurrences of petroleum pools with the spatial correlation characteristics of the discoveries in a play. Other information, such as the estimated total play potential and size characteristics, from conventional resource assessments can be also incorporated into the model as geological constraints. The uncertainty associated with the data and domain knowledge in the predicted pool locations is expressed as a probability map, representing the geological exploration risk of the play. By incorporating all available information and checking the consistency of models with geological constraints, the object-based model improves predictions of petroleum occurrences, thus enhancing the associated risk evaluation. The proposed method was applied to the fractured petroleum play of the western Qaidam Basin in northwestern China in order to illustrate the use of the object-based method for risk evaluation.

Dynamic fault seal analysis and flow pathway modelling in three-dimensional basin models

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

APPROACHES TO PALAEOGEOGRAPHIC RECONSTRUCTIONS OF THE LATROBE GROUP, GIPPSLAND BASIN, SOUTHEASTERN AUSTRALIA

In the Gippsland Basin, the seaward extent of paralic coal occurrences can be mapped in successive time slices through the Paleocene and Eocene to provide a series of straight to gently arcuate surrogate palaeoshorelines within the petroliferous Latrobe Group. Palaeogeographic reconstructions that incorporate this information provide a unique perspective on the changes affecting a siliciclastic depositional system on a passive continental margin where basin development has been primarily controlled by thermal sag. In contrast, the absence of calcareous marine fossils and lack of extensive, widespread and thick fine-grained sediments on the marine shelf and continental slope, beyond the seaward limits of coal accumulation, have contributed to the false impression that the Latrobe Group accumulated in a largely non-marine basin. Based on the proposed model for palaeoshoreline delineation, seismic data, sequence analysis, petrography and palynology can be integrated to subdivide the main depositional environments into distinct facies associations that can be used to predict the distribution of petroleum systems elements in the basin. The application of such palaeogeographic models to the older section of the Latrobe Group can improve the identification of these petroleum systems elements in as yet unexplored parts of the Gippsland Basin. Given the recent attention paid to the basin as a CO2 storage province, palaeogeographic interpretations may be able to assist with the selection of appropriate injection sites.

A mass balance approach for assessing basin-centred gas prospects: integrating reservoir engineering, geochemistry and petrophysics

Abstract This paper presents a mass balance technique for evaluating the resource-in-place potential of basin-centred gas exploration prospects. As the name implies, the methodology is derived from the conservation of mass principle. Unlike conventional reservoir engineering techniques, the mass balance approach directly integrates dynamic elements of the total petroleum system with all static reservoir engineering, geological and petrophysical data to estimate the resource-in-place. This prospect evaluation technique not only provides an independent estimate of hydrocarbon resource-in-place for comparison with that computed from the conventional reservoir engineering approach, but also gives estimates of hydrocarbons lost from the petroleum system. Accordingly, this technique reduces the inherent uncertainty associated with conventional methods and provides more realistic estimates of resource-in-place.

Compositional grading in the oil column: advances from a mass balance and quantitative molecular analysis

Abstract The giant oil fields of the Val D’Agri region (Southern Apennines Internal Thrust Zone, Italy) may rank as the largest onshore accumulations in Europe, but these resources pose special technical challenges due to the secondary alteration process identified as compositional grading. This alteration process is attributed to petroleum system elements and processes that lead to the formation of an unstable oil column. These oil columns are studied within a mass balance perspective that allow identification of key molecular fractionations which can be used to properly diagnose this alteration mechanism in other oil accumulations. The molecular signature is defined in the organic sulphur fraction as well as different hydrocarbon classes, and is completely consistent with the engineering criteria for this reservoir process. This discovery is particularly critical to reservoir compartment studies as the failure to recognize this particular signal will invariably lead to the identification of false compartments.

Abstract: Key Petroleum System Elements of the Venezuelan Basins in an Improved Chronostratigraphic Framework

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ANALISE DE INCERTEZAS EM SISTEMAS PETROLÍFEROS

This paper discusses a model to evaluate uncertainties and success probabilities in petroleum exploration. In the model, assessment of undiscovered oil and gas potential can be made in a probability format, which is based on petroleum system analyses. The evaluated area is mapped in order to define the essential elements of petroleum systems, when the probabilities of occurrence of diagnostic factors are calculated using the presence and absence of guides in productive and dry areas. The study implies, organization of petroleum system oriented databases and statistical analysis of their component data sets. For the estimation of uncertainties a method of updating probabilities is presented in two steps: 1) description and modeling of potential petroleum systems in the evaluated area, based on the essential elements (generation, reservoir, charge, retention and efficiency) and 2) categorization of selected data in control-areas to calculate the necessity and sufficiency conditions of each variable, expressed as probabilities, according to the frequency of occurrence of diagnostic criteria in positive and negative drilled areas.

A PROCESS FOR ESTIMATING GEOLOGICAL RISK OF PETROLEUM EXPLORATION PROSPECTS

The concept of geological risk is critically important in petroleum exploration. It is distinct from both volumetric and commercia I risk. Geological risk is defined as the confidence that a proposed petroleum system is actually working at a particular prospect. Using knowledge-engineering techniques, BHP developed an improved scheme for assessing geological risk. The scheme expands the conventional breakdown of petroleum system elements to about fifty discrete factors, with individual confidence ratings being required for each. The ratings are combined into an overall geological risk using algorithms designed to emulate the typical judgements of experienced explorationists. In practice, application of the scheme also subjects each prospect to an extremely rigorous, detailed and objective review by a technical peer group, which has proved to be a valuable process in its own right. The methodology has improved the accuracy of pre-drill forecasting.

Hydrocarbon Generation and Migration Modeling, Eastern Venezuela Basin

The Eastern Venezuela Basin, with an area of approximately 180,000 km{sup 2}, contains important giant oil fields as well as large unexplored areas. In this region has been identified clearly all the elements of a huge Petroleum System which was kinematically modeled in time and space, following the Basin Modeling method. A passive margin originated during the Cretaceous and early Tertiary epochs, followed by emplacement of allochthonous thrust sheets coming from the west and development of a foreland basin. Therefore, thrusting, basin formation and structures are progressively younger (Oligocene to Middle Miocene) from west to east. Heat flow has increased during the Tertiary to Recent epochs from 40 to 100 mW/m{sup 2}, only in the north-central part of the basin, as interpreted from present maturity data. The first stage of oil generation occurred during late Eocene and Early Oligocene in the northernmost part of the basin. Most of oil migrated more than 150 km southernward up the undeformed homocline of the passive margin. Thus forming the Orinoco Oil Belt. Younger kitchens were later formed from north to south during Early Miocene to Recent. Oils from these kitchens were trapped by increasing tectonic deformation before reaching the southern border of themore » basin. Light and medium gravity oil fields were discovered in this tectonically complex area. This study has helped assess the hydrocarbon potential of as yet unexplored areas, by taking into account important quantitative factors previously not considered.« less