Basin Modeling Study Research Articles

Petroleum generation and migration in the Ghadames Basin, north Africa: A two-dimensional basin-modeling study

The Ghadames Basin contains important oil- and gas-producing reservoirs distributed across Algeria, Tunisia, and Libya. Regional two-dimensional (2-D) modeling, using data from more than 30 wells, has been undertaken to assess the timing and distribution of hydrocarbon generation in the basin. Four potential petroleum systems have been identified: (1) a Middle–Upper Devonian (Frasnian) and Triassic (Triassic Argilo Greseux Inferieur [TAG-I]) system in the central-western basin; (2) a Lower Silurian (Tannezuft) and Triassic (TAG-I) system to the far west; (3) a Lower Silurian (Tannezuft) and Upper Silurian (Acacus) system in the eastern and northeastern margins; and (4) a Lower Silurian (Tanezzuft) and Middle–Upper Devonian (Frasnian) system to the east-southeast. The Lower Silurian Tanezzuft source rock underwent two main phases of hydrocarbon generation. The first phase occurred during the Carboniferous, and the second started during the Cretaceous, generating most hydrocarbons in the eastern (Libyan) basin. The Frasnian shales underwent an initial, minor generative phase in the central depression during the Carboniferous. However, the main generation occurred during the Late Jurassic–Cenozoic in the western and central depression. The Frasnian shales are currently only marginally mature in the eastern part of the basin. Modeling indicates that the Alpine (Eocene) exhumation of the eastern (Libyan) basin margin had a significant control on the timing of hydrocarbon generation from the Lower Silurian source rock. The preferred burial-history model calibrates source rock maturity data by incorporating late exhumation and reduced subsidence prior to the Hercynian (Carboniferous) orogeny. As a result, the Tannezuft shales preserve their generative potential into the Mesozoic–Cenozoic, with renewed hydrocarbon generation during subsequent reburial, which can migrate to post-Hercynian (Carboniferous) traps, hence favoring the preservation of hydrocarbon accumulations.

Thermal history, hydrocarbon generation and migration in the Horn Graben in the Danish North Sea: a 2D basin modelling study

In this study a 2D basin model has been built along a transect crossing the Horn Graben in WNW-ESE direction. The aim of the investigation was to improve the understanding of the thermal evolution of the basin and its influence on possible petroleum systems. The 2D model of the subsurface is based on one seismic line and data from two exploration wells. Both wells TD’ed in Triassic sediments. The updoming of the Ringkobing-Fyn High began during Late Carboniferous–Early Permian. At the end of the Permian the Horn Graben became active due to regional extension. The subsequent sedimentation history from Triassic to date is well recorded by well reports. A matter of debate has been whether or not significant amounts of Pre-Permian sediments exist in this area of the North Sea. Since organic material rich Paleozoic sediments serve as source rocks in widespread areas of North Germany and the southern North Sea it would be of great importance to know whether the same deposits exist in the Horn Graben. Nielsen et al. (Bull Geol Soc Denmark Copenhagen 45:1–10, 1998) introduced a model, which shows Paleozoic sediments covering the basement at a maximum depth of 6.5 km. Assuming, Paleozoic sediments are underlying the Permian salt deposits there should be an active petroleum system present. The 2D model includes the Paleozoic source rock and tries to explain why two exploration wells have not found petroleum.

Petroleum generation and migration in the ‘Tight Gas’ area of the German Rotliegend natural gas play: a basin modelling study

The Northwest German Basin is an important hydrocarbon province with considerable reserves of natural gas accumulated at its centre. To unravel the thermal and maturation history of the Carboniferous source rocks, particularly gas generation and migration, a combined petrological–geochemical and numerical basin modelling study was performed. Generally two main phases of maturation can be assigned to the Triassic–Late Jurassic and latest Cretaceous–Present intervals. Maturity data reflect the latter event and are consistent with a variable heat flow of 60–63 mW m −2 during Cretaceous–Tertiary burial which accounts for considerable late gas generation. Vitrinite reflectance data and maturity modelling show the Top pre-Permian strata in the northern part of the basin to be in the gas window at present, with a rather uniform maturity of VR r = 1.5% to 2.0% (at 4600–5100 m). However, the important top coal marker is at different depth levels and reveals a more complex coalification pattern, suggesting a strong structural control on maturation of source rocks. This effect is influenced locally by the high thermal conductivity of large salt bodies in the overburden. A significant delay in gas generation from source rocks at elevated horst blocks can be observed. The generation and migration of pre-Westphalian gas started during Late Carboniferous times, when much of the gas was lost from the basin due to ineffective seals. With ongoing burial, gas migration from Westphalian source rocks started in Early Triassic times within Permian graben areas, but was actually delayed until the Late Cretaceous at highly elevated horst blocks. The gas from early migration phases was replaced almost entirely by successively younger Westphalian gas.

Geothermal history and petroleum generation in the Norwegian South Viking Graben revealed by pseudo-3D basin modelling

Hydrocarbon exploration in the Norwegian South Viking Graben (57°45′–60°15′N) began in the late 1960s and has now entered a mature phase. A map-based pseudo-three-dimensional (3D) basin modelling study is performed in order to unravel regional trends in hydrocarbon generation and expulsion and to evaluate the remaining potential of this mature petroleum province. Generation and expulsion from all major source rock horizons in the area, the Draupne, Heather, Hugin and Sleipner Formations, is simulated using a pseudo-3D model comprising 36 isochronous geological events. The map-based pseudo-3D model is built from 1D models, combined with subsurface and source rock quality maps. Hydrocarbon expulsion from the Middle and Upper Jurassic source rocks in the area occurred in two major phases. The first phase lasted from Palaeocene to Middle Miocene with peak oil and gas expulsion during the Early Miocene. The second, Quaternary, phase of expulsion, which supplied 11% and 13% of all oil and gas, respectively, is related to increased subsidence rates during this period. A total of 74×10 9 Sm 3 oil and 8.2×10 12 Sm 3 gas has been expelled in the area. The Frigg area in the north is with 2.9×10 12 Sm 3 gas expelled the most gas-prone area, and the Greater Balder area seems to be the most oil-prone area with 17×10 9 Sm 3 oil expelled. The lower, syn-rift section of the Upper Jurassic Draupne Formation dominated oil expulsion (54% of all expelled oil), whilst the Heather Formation dominated gas expulsion with 37% of all gas expelled. Model predictions were successfully applied to explain the fill and secondary alteration history of the Greater Balder Area, Norway. The modelling supports the Draupne Formation origin of the oils in the Greater Balder Area, as well as the presence of oils deriving from multiple charge phases found in correlation studies. Based on the modelled cumulative volumes expelled and estimates for in-place volumes in the area, generation–accumulation efficiencies (GAEs) of 1.01–1.05% for oil and 9.67–12.89% for gas have been estimated for the South Viking Graben. In light of comparisons with other petroleum systems and critical evaluation of the elements of the petroleum systems, the estimated GAEs should be regarded as encouraging for further exploration of the area.

PREDICTING THE TIMING AND CHARACTERISTICS OF PETROLEUM FORMATION USING TAR MATS AND PETROLEUM ASPHALTENES: A CASE STUDY FROM THE NORTHERN NORTH SEA

The Northern Viking Graben area in the Norwegian North Sea was studied in order to investigate the petroleum formation characteristics of the Upper Jurassic Draupne Formation. In this area, the organofacies of the Draupne Formation, and consequently its petroleum generation characteristics, show significant variations. These variations represent a major risk, particularly in the context of basin modelling studies. Therefore, tar-mat asphaltenes, oil asphaltenes and source-rock samples from this area were studied in order to evaluate the use of migrated asphaltenes from petroleum reservoirs and tar mats in basin modelling. The samples were studied using bulk kinetic analysis, open-system pyrolysis-gas chromatography and elemental analyses, and the results were integrated into a basin modelling study. The results from these different sample materials were compared both to each other and to natural petroleum, in order to assess their significance for future petroleum exploration activities. We show that in cumulative petroleum systems, the transformation characteristics of the asphaltenes incorporate those of the individual source rock intervals which have contributed to the relevant reservoir system. Thus, the petroleum formation window predicted by the use of asphaltene kinetics is broad, and covers the majority of the formation windows predicted from the individual source rock samples. In addition, the molecular characteristics of asphaltene-derived hydrocarbons show that compositional characteristics, such as aromaticity, correspond more closely to natural oils than to the respective source-rock products. Our results confirm that the heterogeneous nature of the Draupne Formation results in a significantly broader petroleum formation window than is conventionally assumed. We propose that oil and tar-mat asphaltenes from related reservoirs represent macromolecules which account for this heterogeneity in the source rock, since they represent mixtures of charges from the different organofacies. One conclusion is that the use of oil and tar-mat asphaltenes in kinetic studies and compositional predictions may significantly improve definitions of petroleum formation characteristics in basin modelling.

Sevier orogenesis and nonmarine basin filling: Implications of new stratigraphic correlations of Lower Cretaceous strata throughout Wyoming, USA

Lower Cretaceous nonmarine rocks throughout Wyoming have been used to date movements on major thrusts during the Sevier orogeny, evaluate the sedimentary response in the adjacent foreland basin, reconstruct subsidence histories, evaluate the driving mechanisms of that subsidence, and have been applied to basin modeling studies. However, detailed correlation and dating of these strata have been problematic for a century, making most detailed interpretations equivocal. New age data and correlations presented here have important implications for the evolution of the Sevier orogen and controls on basin fi lling. Lower Cretaceous strata in Wyoming show the former existence of a foreland basin fi ll that displays a thick foredeep depozone to the west (the Gannett Group), a thin forebulge depozone throughout central Wyoming (the Cloverly Formation), and thickening into a backbulge depozone in the Black Hills area to the east (the Lakota Formation). Basin subsidence is attributable not only to orogenic loading, but to dynamic loading as well. New data and correlations indicate that a thrust load was in place during the Neocomian (attributable to movement on the Paris-Willard thrust system) and that sediment supply was high (as represented by the upper Ephraim Formation). Subsequent deposition of the Peterson Limestone in the foredeep during the latest Neocomian and Aptian, and the development of a regional unconformity elsewhere, indicate a reduction in sediment supply that may have been caused by (1) a change to a drier climate, possibly related to progressive mountain-belt uplift and development or intensifi cation of an orographic rain shadow, or (2) a decrease in mountain-belt uplift rate and a reduction in mountain-belt relief. Unconformity development on the forebulge is consistent with the fi rst scenario. Subsequent deposition of the Bechler, upper Cloverly, and upper Lakota Formations during the Early to Middle Albian indicates increased sediment supply, progressive unroofi ng of the mountain belt, and movement on the Meade-LaketownParis-Willard thrust system. These events suggest renewed or accelerated mountainbelt uplift during the early to middle Albian. The Draney Limestone, which overlies the Bechler, correlates with an unconformity at the top of the Cloverly and Lakota Formations and is Albian in age. The Draney Limestone and the unconformity signify a return to conditions similar to those that existed during deposition of the Peterson Limestone. The results presented here differ from those of some researchers who contend that a foredeep did not exist during initial deposition of these strata, and that deposition was not coincident with thrusting during early stages of the Sevier orogeny.

Numerical simulation of petroleum generation and migration in the Qingshui sag, western depression of the Liaohe basin, northeast China

A two-dimensional basin-modeling study was employed to analyze the petroleum generation and migration history of the Qingshui sag in the western depression of the Liaohe basin, northeast China. The Eocene–Oligocene ES4 and ES3 members of the Shahejie Formation (ES) are the most important source rocks responsible for the major hydrocarbon accumulations. Two sandstone beds of fan-delta origin, the Dujiatai (DJT) and the Xinglongtai (XLT), are the primary reservoir rocks in the study area. The model indicates that two migration systems can be differentiated; they are separated by the thick shale beds of the middle ES3 and ES1, which acted as important regional seals for the lower and the upper systems, respectively. The DJT bed is the most important pathway for migrating hydrocarbons in the lower system, whereas the XLT bed is a significant factor in the upper system. Calibration of the model with thermal maturity data indicates that the geological evolution is consistent with typical heat-flow values for rift basins in the range between 85 and 48 mW/m2. All source units reached maturity during the major burial phase, which extended from the Oligocene to the Eocene. Simulation results further indicate that after a cooling period, renewed heating occurred, and additional hydrocarbons were generated during the last 5 m.y., particularly in the southern part of the basin. Sensitivity tests indicated that the faults, particularly the two main faults, served as important conduits for petroleum throughout most of the geological history. The main phase of migration occurred between the Eocene and Oligocene and was responsible for major accumulations in the west slope, the central anticline, and the central rise. Additional migration between 5 Ma and the present is significant in the southwestern area and may have brought about petroleum accumulation in the central depression and central rise.

Source rock heterogeneity of the Upper Jurassic Draupne Formation, North Viking Graben, and its relevance to petroleum generation studies

The Upper Jurassic Draupne Formation in the North Viking Graben, North Sea, has been studied to identify lateral and vertical variations in source rock characteristics and their effect on the timing of petroleum generation. Fourteen source rock samples from the western flank of the graben and five from the eastern flank were analysed using Rock-Eval analysis, microscopy, open system pyrolysis gas chromatography and kinetic experiments. Two major organic facies with different petroleum generation characteristics were identified: a stratigraphically higher, thermally less stable facies, corresponding to a type II kerogen with HI (Hydrogen index) values of >350 mg HC/g TOC; and a stratigraphically lower, more stable type II/III facies with HI values <350 mg HC/g TOC. Only the former is conventionally considered in basin modelling studies. Both organofacies are dominated by marine aliphatic-rich organic matter with variable contributions from transported terrestrial organic matter, resulting in the formation of paraffinic–naphthenic–aromatic petroleum with variable amounts of gas. Bulk kinetic experiments have shown that predicted petroleum formation temperatures are very different, with onset (TR 10%) temperatures of 126 °C (geological T max 144 °C) for the less stable facies and 153 °C (geological T max 170 °C) for the more stable. This corresponds to ∼400 m difference in burial depth or delayed onset of petroleum generation by ∼14 My. Based on a larger dataset from industry, the more stable facies may represent at least 40% of the Draupne Formation in our study areas. Our results imply that petroleum generation from the formation extends to greater depths than generally recognized and that the more stable Draupne organic facies also needs to be included in basin modelling studies to cover the full history of petroleum formation.

Numerical simulation of rifting in the northern Viking Graben: the mutual effect of modelling parameters

Numerous basin modelling studies have been performed on the Viking Graben in the northern North Sea during the past decades in order to understand the driving mechanisms for basin evolution and palaeo temperature estimations. In such modelling, it is important to include lithospheric flexure. The values derived for the lithospheric strength by these studies vary considerably (i.e. up to a factor of 30). In this study, which is based on new interpretation of a regional transect, we show that both the estimated value of the effective elastic thickness and the derived β-profile are dependent on the assumed value of the depth of necking. The use of models that implicitly set the level of necking at a depth of 0 km generally leads to an underestimation of the lithospheric strength, and an overestimation of the thinning factors. In the northern Viking Graben, a necking depth at intermediate crustal levels gives results comparable to the observations. Extension by faulting is modelled to be a significant factor. In conclusion, rifting in the northern Viking Graben can be explained with various models of effective elastic thicknesses (EET) varying from 1 km for a zero necking depth to the depth of the 450 °C isotherm for an intermediate level of necking. It is also shown that the development of the basin during the post-rift phase cannot be explained by pure shear/simple shear extension. Two mechanisms are proposed here to explain the post-rift subsidence pattern, namely intra-plate stress and phase boundary migration. The two extreme models for EET mentioned above (1 km for a zero necking depth to the depth of the 450 °C isotherm for an intermediate level of necking) give very different responses to compressional stress, the latter gives basically no response for realistic intra-plate stress.

Petroleum generation and migration in the Mesopotamian Basin and Zagros Fold Belt of Iraq: results from a basin-modeling study

ABSTRACT A regional 3-D total petroleum-system model was developed to evaluate petroleum generation and migration histories in the Mesopotamian Basin and Zagros fold belt in Iraq. The modeling was undertaken in conjunction with Middle East petroleum assessment studies conducted by the USGS. Regional structure maps, isopach and facies maps, and thermal maturity data were used as input to the model. The oil-generation potential of Jurassic source-rocks, the principal known source of the petroleum in Jurassic, Cretaceous, and Tertiary reservoirs in these regions, was modeled using hydrous pyrolysis (Type II-S) kerogen kinetics. Results showed that oil generation in source rocks commenced in the Late Cretaceous in intrashelf basins, peak expulsion took place in the late Miocene and Pliocene when these depocenters had expanded along the Zagros foredeep trend, and generation ended in the Holocene when deposition in the foredeep ceased. The model indicates that, at present, the majority of Jurassic source rocks in Iraq have reached or exceeded peak oil generation and most rocks have completed oil generation and expulsion. Flow-path simulations demonstrate that virtually all oil and gas fields in the Mesopotamian Basin and Zagros fold belt overlie mature Jurassic source rocks (vertical migration dominated) and are situated on, or close to, modeled migration pathways. Fields closest to modeled pathways associated with source rocks in local intrashelf basins were charged earliest from Late Cretaceous through the middle Miocene, and other fields filled later when compression-related traps were being formed. Model results confirm petroleum migration along major, northwest-trending folds and faults, and oil migration loss at the surface.

An integrated basin modelling study applying asphaltene kinetics from reservoired petroleum in the Snorre Area, northern North Sea

Abstract The evolution of the petroleum systems in the Tampen Spur area, with main focus on the filling directions of the northern part of Snorre field, was addressed through 2D basin modelling (Petromod V. 4.5 and 7.0). The geochemical classification of the petroleum populations in the area represented the framework for considering the different kitchen areas and migration systems. Results from the basin modelling support, in general terms, the previous geochemical classification and petroleum families in the region. However, a separate well-defined main kitchen area for the Snorre Field was deduced opposed to the multiple kitchen areas having contributed to the filling as proposed in the literature. Our conclusions are based on the quantitative evaluation of the different proposed kitchen areas and the timing and extent of petroleum generation. Modelling of petroleum generation was performed using asphaltene kinetics determined on petroleum asphaltenes from Snorre oils. This approach was chosen in order to avoid problems associated with the kinetic variability encountered in the Draupne formation. The petroleum asphaltene kinetics was used to delineate the extent of the kitchen area, which reached the time/temperature conditions necessary for the generation of the analysed oil phase. The results thus differ from conventional oil window approximations as we utilize kinetic source rock parameters in the migrated oil for tracing out the generative basin. Three 2D lines crossing the main kitchen areas were modelled in this study. The models were calibrated to data from eight wells, consisting of measured vitrinite reflectance, corrected well temperatures and pore pressure. Three main kitchen areas were considered; one to the west and northwest of Snorre field, one directly to the north (Møre basin) and one to the east of the field (34/5 kitchen). Modelling suggests that the kitchen area to the west and northwest of Snorre is largely immature and that the volume of potentially generated petroleum is too small to fill the Snorre structure. In the northern kitchen area, the seismic indicated very thin upper Jurassic deposits, which reaches oil window maturities only at a relatively large distance from the structure. The modelling also demonstrated problems related to the filling of the Snorre structure from the Møre Basin. The combined effect of a thin source rock, which implies a regionally large drainage area to fill the structure, and the large distance to the mature kitchen, lead to the conclusion that the Møre Basin did not contribute significant volumes of petroleum to the Snorre field. In contrast, the kitchen area east of Snorre Field (the 34/5 kitchen) proved in the modelling to be mature and volumetrically large enough to account for the entire filling of the Snorre Field.

Development of a compositional kinetic model for hydrocarbon generation and phase equilibria modelling: a case study from Snorre Field, Norwegian North Sea

Abstract The possibility to model petroleum composition during hydrocarbon generation as well as the PVT behaviour of the fluids during migration has only recently become available in modern basin modelling software packages. While various compositional kinetic models of petroleum generation have been published in the past few years, none of the studies presented have attempted to match the composition, physical properties and phase state of known petroleum accumulations. Using compositional data from closed-system non-isothermal pyrolysis experiments, we developed a compositional kinetic model of hydrocarbon generation for a marine Type II source rock, which uses 13 components to describe the generated fluid. The data format selected is compatible with the compositional resolution used in reservoir engineering, thus allowing a direct comparison of predicted compositions and phase behaviour with PVT data of natural fluids. Compositional predictions of the model were tuned to a well-documented maturity sequence from the Tampen Spur, Norway, and the calibrated model implemented in a 2D basin modelling study of the Snorre Field, Norway. The results of the modelling led to an excellent correlation between predicted and reported reservoir fluid properties (formation volume factor, GOR and saturation pressure) for the present-day situation. The results indicate that the Snorre reservoir has received a continuous charge since the late Cretaceous-early Tertiary and that it most likely contained a two-phase system prior to the latest Plio-Pleistocene burial and overpressuring event.

Unravelling the petroleum system by enhancing fluid migration paths in seismic data using a neural network based pattern recognition technique

AbstractUnderstanding the hydrocarbon migration system in the sub‐surface is a key aspect of oil and gas exploration. It is well known that conventional 3D seismic data contains information about hydrocarbon accumulations. Less known is the fact that 3D seismic data also contains information about hydrocarbon migration paths in the form of vertical noise trails. A method has been developed to highlight vertical noise trails in seismic data semi‐automatically, using assemblies of directive multi‐trace seismic attributes and neural network technology. The results of this detection method yield valuable information about the origin of hydrocarbons, about migration paths from source to prospect and about leakage or spillage from these prospects to shallow gas pockets or to the sea bed. Besides, the results reveal the sealing quality of faults, provide information on overpressure and whether prospects are charged or not. All these aspects are useful information for basin modelling studies and for an increased understanding of the petroleum system.

2D numerical modelling of hydrocarbon generation at an activecontinental margin—Costa Rica

The petroleum system of the subduction zone of Costa Rica was examined in a numerical basin modelling study. Threemodels with varying subduction velocities (30, 60, 90 mm/year) were calculated. The calculated temperature distribution shows that the temperature field is heavily disturbed in all models. The amount of subducted organic carbon is high due to the high-subduction velocity. Migration of oil and gas towards the sea floor does not occur due to the low migration velocities.

Tectonic subsidence modelling of the Polish Basin in the light of new data on crustal structure and magnitude of inversion

The Polish Basin (PB) is one of a set of basins developed on the Paleozoic platform of western Europe in the Late Paleozoic between the Variscan Orogen and the East European Craton (EEC). Its main depocentral axis (the Mid-Polish Trough—MPT) was active during most of the basin development as a maximum subsidence zone with almost uninterrupted sedimentation. The present base of the Permian in the MPT ranges in depth from ca. 3000 to 3500 m near the Baltic coast to up to 8000 m to the southeast. The MPT lies parallel and adjacent to the edge of the EEC and appears to be related to a distinct structural zone within the crust (the Tornquist–Teisseyre Zone—TTZ). Subsidence of the MPT can be explained in terms of crustal extension/transtension and related lithosphere cooling coupled with the structural predetermination of the underlying TTZ. Tectonic subsidence analysis of the preserved and reconstructed stratigraphic record suggests the occurrence of a Late Permian–Early Triassic “rifting” phase. However, there is a deficit of geologically observable extensional features (faulting) of this age, implying an important relationship between this phase of apparent basin subsidence and earlier post-Variscan, Late Carboniferous–Early Permian tectonism. The match between crustal structure implied by basin modelling studies and available deep seismic sounding (DDS) data is not always clear. This is probably related to the heterogeneous basement, which comprises the outer zone of the Variscan belt in the southwest, EEC crust in the northeast, and a complex of Caledonian/reworked Precambrian crustal blocks in the central part of the basin. Changes to crustal architecture as a result of Alpine tectonics may also play a role. Increased tectonic subsidence rates during Oxfordian–Kimmeridgian times (Late Jurassic) correlate with intensified rifting and wrench activity within the Arctic–North Atlantic rift system and along the northern Tethyan margin. In contrast, accelerating tectonic subsidence beginning in the Cenomanian is a precursor of compressional deformations in the basin that culminated in Alpine-related basin inversion during the latest Late Cretaceous and earliest Tertiary. Taking inversion into account, the maximum depth of the base Zechstein structural surface at the end of the Cretaceous is estimated to have been as much as 5000 m near the Baltic Sea to more than 10 000 m in the southeasternmost part of the basin. Because of the erosion of these sediments, however, constraints on Cretaceous subsidence and, in turn, the magnitude and exact timing of Late Cretaceous–Paleogene inversion are poor.

Petroleum generation and migration in the Putumayo Basin, Colombia: insights from an organic geochemistry and basin modeling study in the foothills

This paper discusses the results of 1D modeling and geochemical analyses of rock, oil and gas samples performed in the foothills of the Putumayo Basin, Colombia. A multivariate statistical assessment of biomarker data points to the existence of three oil groups, two of the them similar to oil families reported in previous studies and related to the Villeta Formation source rocks, and a novel one tentatively associated with the Caballos Formation source rocks. Geochemical data of oil and gas samples points to a complex reservoir filling history in the foothills, with at least two migration pulses with distinct maturity levels. Vitrinite reflectance data together with modeling results shows that the source rock is practically immature in the Putumayo foothills, even in the footwall of large thrust faults. The thermal and burial reconstruction of a pseudo well located in the present cordillera area suggests that the source rocks have started petroleum generation and expulsion during the Late Oligocene/Miocene. The oil and gas expelled during such a period have migrated over 80 km, reaching the present foreland area. Subsequent tectonic burial and/or higher heat flows related to the Late Miocene/Pliocene Andean Paroxysm is thought to account for a second pulse of migration of thermally evolved hydrocarbons limited to the foothills area.

ABSTRACT: Integrated stratigraphic and basin modeling study of a frontier offshore area :The Colorado basin, Argentina

ABSTRACT: Integrated stratigraphic and basin modeling study of a frontier offshore area :The Colorado basin, Argentina

Petroleum generation and accumulation in the Golfo San Jorge Basin, Argentina: a basin modeling study

The Golfo San Jorge Basin, located in Patagonia, is very important for the oil and gas production of Argentina. In spite of the long history of exploration and production, few geochemical studies were performed until now. For this study, a set of possible source rocks was analyzed by organic geochemical and petrographical methods. The samples of the Pozo D-129 Fm. range from mature to overmature, and contain from less than 0.5 to 2.45% TOC. There is some evidence indicating an algal origin of the more hydrogen-rich kerogen present in part of the basin. Almost all the samples of Pozo Anticlinal Aguada Bandera and Pozo Cerro Guadal Fm. are overmature. TOC values range from less than 0.5 to 2.5%. The maturation of source rocks and generation, expulsion and migration of hydrocarbons was evaluated by means of 1D and 2D basin models. The 1D models constructed for the western part of the basin and 2D models applied for the eastern part both indicate maximum burial in Miocene times. The thickness of the Tertiary at times of maximum burial ranged from 1000 to 1500 m and the generally small Tertiary thickness now present in the fold belt region is assumed to be the result of erosion. The main tectonic inversion took place in the Late Neogene. The models strongly suggest that a magmatic event between 20 and 30 Ma, combined with the maximum burial at Miocene times produced a very important pulse in hydrocarbon generation within the major part of the basin. Dated intrusive and extrusive magmatic rocks extended all over the basin account for this period of elevated heat flow. Migration pathways are extensively discussed for the 2D model. Probably, major faults acted as important conduits for petroleum.

Petroleum generation and accumulation in the Berkine basin, eastern Algeria

The Berkine (Ghadames) basin is regarded as an important hydrocarbon play in eastern Algeria. An evaluation of organic source facies, the application of petroleum geochemistry, and an extensive basin modeling study were carried out to improve the understanding of the petroleum charge of the basin. Geochemical data indicate that the Llandoverian-Wenlockian and the Frasnian hot shales are the most important oil-prone source rocks for the known hydrocarbon accumulations in the basin. Maturity data reflect the Late Cretaceous-Tertiary burial and are consistent with a 60-63 mW/m2 heat flow in the vicinity of the anticlines and 50 mW/m2 heat flow farther away from the folded area. A two-dimensional basin modeling study revealed the importance of poorly constrained parameters, such as the amount and rate of Hercynian erosion, on hydrocarbon generation and trapping efficiencies. The model shows that a Cretaceous-Tertiary petroleum generation and emplacement for both source rocks can better explain the different gas and oil fields than can an earlier, Hercynian event. The faults related to the Triassic-Jurassic rifting are most certainly permeable and can be considered as major migration pathways for petroleum. In contrast, the overpressure that developed along the El Biod-Hassi Messaoud axis in the Ordovician reservoirs was probably caused by the low permeability of the faults bounding the anticlines that therefore prohibited any lateral or vertical fluid movements. The model also indicates two petroleum systems that have Triassic reservoirs: (1) a Frasnian-sourced system that is confined to the central part of the basin and (2) a Llandoverian-Wenlockian-sourced system in the western part of the basin. Migration into Paleozoic reservoirs was followed by dismigration into overlying Triassic traps after the Cretaceous compressive movements.

Petroleum systems of Oman: Charge timing and risks

After 35 years of exploration, creaming of the conventional plays in Oman is nearly complete, and consequently, the search has commenced for new, less obvious plays. Many of the new opportunities occur beyond the known hydrocarbon provinces and are considered to have significant charge risks. To define these risks, extensive basin modeling studies have been conducted in recent years. Modeling and empirical data show that Mesozoic and Cenozoic kitchen areas are restricted to western north Oman, the only areas currently buried at their maximum temperature. Large parts of north and central Oman depend on lateral migration from these kitchens for their charge. Progressive uplift of the east flank and basin inversion since the middle Paleozoic provides favorable conditions for long-distance migration in the post-Carboniferous interval. In central Oman, geochemical tracer molecules (benzocarbazoles) suggest that a north-south-trending, reactivated basement grain has funneled charge up to 300 km southeastward. Charge risks increase in the deeper sequence, in which eastward migrating hydrocarbons have to traverse the Ghaba salt basin, a pronounced syncline at depths greater than 3 km. The south Oman salt basin is currently cool because of shallow depths and hydrodynamic fluid-flow activity. The shallow post-Cambrian reservoirs rely on storage of early (Cambrian-Ordovician) charge by the Ara salt (Cambrian) sequence, followed by release of hydrocarbons as the salt edge retreats through time. Basin modeling has outlined the extent of the different petroleum systems and provided us with risk maps to guide our next exploration phase. It has revitalized some of the mature plays, for instance the Gharif Formation, where oil exploration is now focused along Late Cretaceous and Tertiary migration paths. Deeper sections are envisaged to have significant scope for gas.