Petroleum System Modeling Research Articles

The impact of the Messinian salinity crisis on the petroleum system of the Eastern Mediterranean: a critical assessment using 2D petroleum system modelling

The offshore Levant Basin demonstrates one of the most phenomenal natural examples of a working petroleum system associated with a relatively rapid unloading and loading cycle caused by the Messinian salinity crisis (MSC). In this study, 2D basin and petroleum systems modelling suggests that the geologically instantaneous water unloading of approximately 2070 m, and subsequent rapid salt deposition and refill, impact the subsurface pore pressure and temperature in the underlying sediments. The pressure drop is modelled to be instantaneous, whereas the impact on temperature is more of a transient response. This has important consequences for the shallow sub-Messinian biogenic petroleum system, which is assumed to have experienced fluid brecciation associated with massive fluid escape events. Deeper Oligo-Miocene sediments are far less affected, thus indicating a ‘preservation window’ for biogenic gas accumulations, which host the recent discoveries (Tamar, Leviathan, Aphrodite). Hydrocarbon accumulations of a ‘bubblepoint oil’ composition are modelled to have experienced cap expansion during the drawdown, with the pressure drop being the primary control. This study suggests that seal-limited traps are expected to have undergone a catastrophic seal failure, whereas the impact of the MSC is modelled to be less destructive for size-limited and, particularly, charge-limited traps.

Reservoir quality, gas accumulation and completion quality assessment of Silurian Longmaxi marine shale gas play in the Sichuan Basin, China

The Sichuan Basin in Southwest China holds the most potential for shale gas exploration and development in China. The assessment of reservoir quality, gas accumulation and completion quality of Silurian Longmaxi marine shale gas is conducted based on detailed mapping of depositional systems and shale properties, analyses of geochemical, mineralgical and petrophysical data, investigation on interactions between tectonics, reservoir quality, shale gas accumulation, completion quality, and production. The results show that the Lower Section of the Lower Silurian Longmaxi marine shale in the southern, southeastern, and eastern parts of the Sichuan Basin is good shale reservoir in terms of high TOC, high maturity, high brittle mineral content, and development of inter-particle and intra-organic matter pores and natural fractures. Petroleum system modeling calibrated by production data reveals shale gas tends to accumulate in broad syncline and anticline in tectonically stable area. Tectonic setting and stress field analyses and hydraulic fracturing simulation and practice imply that the siliceous Longmaxi shale interval in the areas with small far-field horizontal stress are more favorable for hydraulic fracturing to form complex fracture network. The best prospects are likely located in broad syncline and anticline in tectonically stable areas with good reservoir quality, shale gas accumulation and completion quality in the southern and southeastern areas inside the Sichuan Basin.

History of hydrocarbon generation, migration and accumulation in the Fula sub-basin, Muglad Basin, Sudan: Implications of a 2D basin modeling study

The Fula sub-basin is located in the northeastern part of the Muglad Basin. A 2D petroleum systems model of the Lower Cretaceous within the northern portion of the Fula Sub-basin was illustrated by integrating geological, geophysical and geochemical data. Timing of hydrocarbon generation, migration, and accumulation in the Fula Sub-basin are predicted from the model results. Based on reservoir distributions and common petroleum system events, the Fula Sub-basin petroleum system is considered to have three subsystems.In this petroleum system, deep lacustrine mudstones and shales in the Lower Cretaceous Abu Formation were known to be very good source rocks that possess more than 2.0 wt % TOC. Deltaic and turbidite sandstones within the Abu Gabra Formation and the thick fluvial sandstones of the upper Bentiu and fan-delta sandstones within the Aradeiba Formation are good reservoir bearing intervals. The mudstone in the Darfur Group acts as the regional seal. The petroleum system is considered to be effective and significant proportions of both oil and gas in these reservoirs can be preserved. The Abu Gabra Formation is considered to have entered the oil window approximately 120 Ma ago. Late oil generation continued for approximately 55 Ma. Gas generation took place in the mid-Eocene and probably continues to present-day. The results also show that the generated hydrocarbon is mainly oil with minor gas shows. In the main kitchen area, the migration and accumulation of hydrocarbon began at about 90 Ma. Migration is shown to be associated mainly with fault patterns controlling migration direction. Some migrated hydrocarbons escaped through the faults.

남해 대륙붕 소라분지의 석유시스템 모델링

남해 대륙붕 소라분지의 석유시스템 모델링

Assessing shale gas resources of Wufeng-Longmaxi shale (O3w-S1l) in Jiaoshiba area, SE Sichuan (China) using Petromod II: Gas generation and adsorption

ABSTRACTTaking Well JY4 as example, the authors present petroleum system modeling with PetroMod software for shale gas resource assessment of Wufeng-Longmaxi shale in Jiaoshiba area, which takes account of hydrocarbon adsorption process within source rocks. On the basis of burial and thermal modeling, source rocks adsorption parameters obtained from isothermal adsorption of gas measurements were defined. The results show that the total gas content of Wufeng-Longmaxi shale is estimated in rang of 4.6–10.5 * 106 kg/km2, and the proportion of absorbed gas content is around 22–50% in Jiaoshiba area.

Effect of sedimentary heterogeneities on hydrocarbon accumulations in the Permian Shanxi Formation, Ordos Basin, China: Insight from an integrated stratigraphic forward and petroleum system modelling

Sedimentary heterogeneities are ubiquitous in nature and occur over a range of scales from core, reservoir to basin scales. They may thus exert significant influences on hydrocarbon generation, migration and accumulation. The sedimentary heterogeneities of the Permian Shanxi Formation in the Ordos Basin, China were modelled using Sedsim, a stratigraphic forward modelling program. The simulation results were then used to construct a 3D petroleum system model using PetroMod. The effects of sedimentary heterogeneities on hydrocarbon accumulations were evaluated by comparing the integrated Sedsim-PetroMod model with the classic 3D basin model. The Sedsim simulation shows that considerable sedimentary heterogeneities are present within the Shanxi Formation, as a result of the interplay of the initial topography, tectonic subsidence, base level change and sediment inputs. A variety of lithologies were developed both laterally and vertically within the Shanxi Formation at kilometre and metre scales, respectively, with mudstones mainly developed in the depositional centre, while sandstones developed in the southern and northern margin areas. A typical source-ward retrogradation is well developed within the Lower Shanxi Formation.A base-case classic 3D basin model was constructed to quantify the Permian petroleum system in the Ordos Basin. The geological and thermal models were calibrated using Vr and borehole temperature data. The source rocks of the Upper Paleozoic became mature (Ro > 0.5%) and high mature (Ro > 1.2%) in the late Triassic and late Jurassic, respectively, in the central and southern areas. During the Early Cretaceous, a tectonically induced geothermal event occurred in the southern Ordos Basin. This caused the source rocks to reach over maturity (Ro > 2.0%) quite rapidly in the early Late Cretaceous in the central and southern areas. All the source rock transformation ratios (TR) at present are greater than 70% in the P1 coal and P1 mudstone layers with TR values approaching 100% in the central and southern areas. The transformation ratios of the P1 limestone are close to 100% over the entire interval.In the base-case model, a large amount of hydrocarbons appear to have been expelled and migrated into the Shanxi Formation, but only a minor amount was accumulated to form reservoirs. In the model, the Shanxi Formation sandstone layer was set to be homogeneous vertically and there was no regional seal rocks present at the top of the Shanxi Formation. Therefore hydrocarbons could not be trapped effectively with only minor accumulations in some local structural highs where hydrocarbons are trapped both at the top and in the up-dip direction by the adjacent mudstone facies. In contrast, the integrated Sedsim-PetroMod model takes into account of the internal lithological and sedimentary facies heterogeneities within the Shanxi Formation, forming complex contiguous sandstone-mudstone stacking patterns. Hydrocarbons were found to have accumulated in multiple intervals of lithological traps within the Shanxi Formation. The results indicate that lithological distinctions, controlled by sedimentary heterogeneities in three dimensions can provide effective sealing in both the top and up-dip directions for hydrocarbon accumulations, with gas being mainly accumulated near the depocentre where lithological traps usually formed due to frequent oscillations of the lake level.

Coupling stratigraphic and petroleum system modeling tools in complex tectonic domains: case study in the North Algerian Offshore

In the eastern Algerian offshore basin, 3D basin modeling applied for facies prediction and petroleum potential assessment shows that most favorable zones for reservoir development and hydrocarbon occurrence are located at a maximum distance of 60 km from the coastline. The lack of well data in this area is partly compensated by a large data set of geophysical and geological (GG they represent important constraints for 3D dynamic modeling. Facies distribution model is constrained by sequence and environment evolution through time that is defined from onshore outcrops. 2D structural reconstitution and thermal modeling were also undertaken with ArcTem software. The structural interpretations highlight the occurrence of north-verging ramps during the Quaternary which played an important role in HC generation and migration. Three source rocks have been considered for maturation modeling with Temis Flow software, Burdigalian, Langhian, and Tortonian. They are found to be in gas window in the deep areas and locally in oil window at shallower structured zones. The modeling results indicate that the main fluid discharge was focused toward the southern border of the offshore basin where recent thrust faults (parallel to the margin) are located. In order to test the role of these faults in terms of hydrocarbon migration and trapping, two scenarios are considered according to whether they were sealed or not. In both cases, the 2D/3D simulations depict overpressures (2,000–4,000 psi) in the pre-salt sedimentary package. However, the hydrocarbon charge is most efficient with the sealing faults for the lower Langhian and lower Messinian reservoirs. The hydrocarbon potential depends mostly on the lateral extension of seals, their sealing capacity and the organic carbon (TOC) content of potential source rocks. Besides, the sea drop of about 1,000 m during the Messinian salinity crisis has induced depressurization that caused oil and gas seepage from Miocene reservoirs.

BURIAL, TEMPERATURE AND MATURATION HISTORY OF THE AUSTRAL AND WESTERN MALVINAS BASINS, SOUTHERN ARGENTINA, BASED ON 3D BASIN MODELLING

This paper presents a numerical petroleum systems model for the Jurassic‐Tertiary Austral (Magallanes) Basin, southern Argentina, incorporating the western part of the nearby Malvinas Basin. The modelling is based on a recently published seismo‐stratigraphic interpretation and resulting depth and thickness maps. Measured vitrinite reflectance data from 25 wells in the Austral and Malvinas Basins were used for thermal model calibration; eight calibration data sets are presented for the Austral Basin and four for the Malvinas Basin. Burial history reconstruction allowed eroded thicknesses to be estimated and palaeo heat‐flow values to be determined. Six modelled burial, temperature and maturation histories are shown for well locations in the onshore Austral Basin and the western Malvinas Basin. These modelled histories, combined with kinetic data measured for a sample from the Lower Cretaceous Springhill Formation, were used to model hydrocarbon generation in the study area. Maps of thermal maturity and transformation ratio for the three main source rocks (the Springhill, Inoceramus and Lower Margas Verdes Formations) were compiled. The modelling results suggest that deepest burial occurred during the Miocene followed by a phase of uplift and erosion. However, an Eocene phase of deep burial leading to maximum temperatures cannot be excluded based on vitrinite reflectance and numerical modelling results. Relatively little post‐Miocene uplift and erosion (approx. 50–100 m) occurred in the Malvinas Basin.Based on the burial‐ and thermal histories, initial hydrocarbon generation is interpreted to have taken place in the Early Cretaceous in the Austral Basin and to have continued until the Miocene. A similar pattern is predicted for the western Malvinas Basin, with an early phase of hydrocarbon generation during the Late Cretaceous and a later phase during the Miocene. However, source rock maturity (as well as the transformation ratio) remained low in the Malvinas Basin, only just reaching the oil window. Higher maturities are modelled for the deeper parts of the Austral Basin, where greater subsidence and deeper burial occurred.

Gas hydrate distribution and hydrocarbon maturation north of the Knipovich Ridge, western Svalbard margin

AbstractA bottom‐simulating reflector (BSR) occurs west of Svalbard in water depths exceeding 600 m, indicating that gas hydrate occurrence in marine sediments is more widespread in this region than anywhere else on the eastern North Atlantic margin. Regional BSR mapping shows the presence of hydrate and free gas in several areas, with the largest area located north of the Knipovich Ridge, a slow spreading ridge segment of the Mid Atlantic Ridge system. Here heat flow is high (up to 330 mW m−2), increasing toward the ridge axis. The coinciding maxima in across‐margin BSR width and heat flow suggest that the Knipovich Ridge influenced methane generation in this area. This is supported by recent finds of thermogenic methane at cold seeps north of the ridge termination. To evaluate the source rock potential on the western Svalbard margin, we applied 1‐D petroleum system modeling at three sites. The modeling shows that temperature and burial conditions near the ridge were sufficient to produce hydrocarbons. The bulk petroleum mass produced since the Eocene is at least 5 kt and could be as high as ~0.2 Mt. Most likely, source rocks are Miocene organic‐rich sediments and a potential Eocene source rock that may exist in the area if early rifting created sufficiently deep depocenters. Thermogenic methane production could thus explain the more widespread presence of gas hydrates north of the Knipovich Ridge. The presence of microbial methane on the upper continental slope and shelf indicates that the origin of methane on the Svalbard margin varies spatially.

Cooper Basin source rock atlas

The Australian Petroleum Source Rocks Mapping project is a new study to improve understanding of the petroleum resource potential of Australia’s sedimentary basins. The Permian source rocks of the Cooper Basin, Australia’s premier onshore hydrocarbon-producing province, are the first to be assessed for this project. Quantifying the spatial distribution and petroleum generation potential of these source rocks is critical for understanding both the conventional and unconventional hydrocarbon prospectivity of the basin. Source rock occurrence, thickness, quality and maturity are mapped across the basin, and original source quality maps prior to the onset of generation are calculated. Source rock property mapping results and basin-specific kinetics are integrated with 1D thermal history models and a 3D basin model to create a regional multi-1D petroleum systems model for the basin. The modelling outputs quantify both the spatial distribution and total maximum hydrocarbon yield for 10 source rocks in the basin. Monte Carlo simulations are used to quantify the uncertainty associated with hydrocarbon yield and to highlight the sensitivity of results to each input parameter. The principal source rocks are the Permian coals and carbonaceous shales of the Gidgealpa Group, with highest potential yields from the Patchawarra Formation coals. The total generation potential of the Permian section highlights the significance of the basin as a world-class hydrocarbon province. The systematic workflow applied here demonstrates the importance of integrated geochemical and petroleum systems modelling studies as a predictive tool for understanding the petroleum resource potential of Australia’s sedimentary basins.

New insights into the petroleum prospectivity of the Browse Basin: the results of a multi-disciplinary study

The Browse Basin hosts large gas accumulations, some of which are being developed for conventional liquefied natural gas (LNG). Extensive appraisal drilling has been focused in the central Caswell Sub-basin at Ichthys and Prelude, and along the extended Brecknock-Scott Reef Trend; whereas elsewhere the basin remains underexplored. To provide a better understanding of regional hydrocarbon prospectivity, the sequence stratigraphy of the Cretaceous succession and structural framework were analysed to determine the spatial relationship of reservoir and seal pairs, and those areas of enhanced source rock development. The sequence stratigraphic interpretation is based upon a common North West Shelf stratigraphic framework that has been developed in conjunction with industry, and aligned with the international time scale. Sixty key wells and 2D and 3D seismic data have been interpreted to produce palaeogeographic maps and depositional models for the Cretaceous succession. Geochemical analyses have characterised the molecular and stable isotopic signatures of fluids and correlated them with potential source rocks. The resultant petroleum systems model provides a more detailed understanding of source rock maturity, organic richness and hydrocarbon-generation potential in the basin. The model reveals that many accumulations have a complex charge history, with the mixing of hydrocarbon fluids from multiple Mesozoic source rocks, including the Lower–Middle Jurassic J10–J20 supersequences (Plover Formation), Upper Jurassic–Lowermost Cretaceous J30–K10 supersequences (Vulcan Formation), and Lower Cretaceous K20–K30 supersequences (Echuca Shoals Formation). Burial history and hydrocarbon expulsion models, applied to these Jurassic and Cretaceous supersequences, suggest that numerous petroleum systems are effective within the basin. For example, hydrocarbons are interpreted to have been generated from several source pods within the southern Caswell Sub-basin with migration continuing onto the Yampi Shelf, an area of renewed exploration interest.

INTEGRATION OF BIODEGRADATION AND MIGRATION OF HYDROCARBONS IN A 2D PETROLEUM SYSTEMS MODEL: APPLICATION TO THE POTIGUAR BASIN, NE BRAZIL

Biodegradation is probably the most important in‐reservoir alteration process and is responsible for the majority of the known heavy oil accumulations. In the present study, biodegradation processes were integrated within a forward basin and petroleum systems model applied to the Potiguar Basin, NE Brazil. This basin was chosen because it has been studied in detail and data from previous investigations are publically available. In order to account for processes occurring during the biodegradation of hydrocarbons, the evolution of fluid properties was simulated through time. In the model, a new approach was developed in order to determine the intensity of microbial activity and the evolution of the oil‐water contact, the zone within which biodegradation is confined. The numerical results obtained by applying the forward simulator to a 2D model of the Potiguar Basin fit the observed data concerning the composition and quality of the oil in a series of oilfields. These accumulations are located along the NE‐SW oriented “Carnaubais trend” and show progressive biodegradation along the migration path from the offshore kitchen area. Our results show that the biodegradation trend observed along the cross‐section can in general be explained by the fact that reservoirs are successively filled as a result of spilling from previous reservoirs, with continuous hydrocarbon degradation occurring within the reservoirs. This charge history resulted in differences in the composition of oils transported from upstream to downstream reservoirs, and in the evolution over time of the ratio between biodegradation and reservoir filling rates. Thus, in addition to residence time in the biodegradation temperature window, the rate of reservoir infill, the rate of oil degradation and the migration pathways are key factors controlling biodegradation. This study also demonstrates how the approach developed within our petroleum system simulator, which integrates both migration and biodegradation, may improve the assessment of oil quantity, quality and migration timing.

The ISoS Modeling Framework for Infrastructure Systems Simulation

Strategic infrastructure design considers long-term and cross-sector objectives to meet societal needs. Designers rely on tools to mitigate limits on human perception and manage complex systems with high-performance requirements. This paper defines the infrastructure system-of-systems modeling framework for heterogeneous simulation models. It formally defines structural and behavioral templates and an interoperability interface using algebraic statements. Infrastructure elements are graph edges, which express functions via operational states. An interoperability interface defines requirements for resource exchanges across system model boundaries. An example application case demonstrates a model instance with 18 infrastructure elements in water, petroleum, electricity, and social system models. Results show flow validity constraint violations arise from acyclic and cyclic dependencies between models. Increasing the number of iterations per time step or shortening the time step reduces error at the cost of execution time.

Exploring the potential of deep targets in the South Adriatic Sea: insight from 2D basin modeling of Croatian offshore

The Croatian offshore hydrocarbon province is highly under-explored. From a total number of 128 exploration wells, 96 were drilled in the North Adriatic Sea, 27 in the Central Adriatic Sea and only 5 in the South Adriatic Sea. Most of exploration wells were drilled to test the Pliocene shallow sandstone biogenic gas play, which has been in production since the end of the twentieth century. However, the deep Mesozoic oil plays are still heavily under-explored. By interpreting regional studies, offshore well datasets and 2D seismic lines acquired by Spectrum in 2013, this study identified two new interesting explorative plays: Structural Karst play (Triassic/Jurassic); Slope Calciturbidites play (Cretaceous/Eocene). 2D petroleum system modeling was performed along a representative interpreted seismic section to define the potential and the exploration risk of the two plays. The results show that all critical elements for a working petroleum system are present for both plays. Several fluid-saturated traps are present in the Cretaceous and Jurassic reservoirs with an indicative total depth between 3500 and 5500 m and in water depth from 500 to 1200 m. For the Structural Karst play the main uncertainties are related to the quality and efficiency of the reservoir, while for the Slope Calciturbidites play the main uncertainty is related to the sealing efficiency.

Further de-risking source rock maturity in the Luderitz Basin using basin modelling to support the BSR-derived near-surface geotherm

The discovery of Kudu gas-condensate accumulation and recent wells drilled offshore in the Namibian margin have successfully de-risked source rock presence and maturity (Hodgson and Intawong, 2013). Both the acquisition of an extensive 2D seismic dataset in 2012 and a recently acquired cross-border survey 2015 off¬shore Namibia and South Africa have facilitated the evaluation of source rock maturity distribution for the Early Aptian and Cenomanian-Turonian source rocks along this margin (Figure 1). Conventionally, we have no tools to interrogate heat flow and geothermal gradient in an undrilled basin and have to rely on extrapolation from offset wells, imposing models on a structural interpretation of the basin margin. Near-surface geotherm estimation derived from seismic measurement of the thickness of a gas hydrate accumulation with respect to the water depth found in the Luderitz Basin has been employed as a preliminary approach for the initial evaluation of source rock maturity in this margin (Hodgson et al., 2014). The approach remains an under-utilised seismic method for initial evaluation of source rock maturity in undrilled basins. Public domain heatflow data (Davies, 2013), knowledge of subsurface thermal conductivity and crustal heat production can be used to predict geotherms and thus temperature spatially away from control points. Petroleum system modelling is the most efficient way of systematically investigating the thermal maturity of sedimentary basins. This can be tailored to available constraints, which in the case of the deepwater Luderitz Basin include shallow temperature data derived from BSR (60°C/km in the upper 500 mbsf) and heatflow measurements (40-60 mW/m2; Davies 2013). The uppermost sediments have a thermal conductivity of < 1 W/m/K, which is 2-3 times lower than deeper (compacted) clastic sediments. That would provide an average geothermal gradient of 30°C/km as previously proposed by Hodgson et al. (2014).

SOME THOUGHTS ON THE INFLUENCE OF PRESSURE AND THERMAL HISTORY ASSUMPTIONS ON PETROLEUM SYSTEMS MODELLING

The use of petroleum systems modelling (PSM) requires the integration of the geological sciences with petroleum engineering, physics and chemistry. In a recent paper in JPG (October 2014, vo. 37, pp 329–348), Mahanjane et al. (2014) applied a 1‐D petroleum systems model to the study of maturation and petroleum generation in northern Mozambique. However, PSM cannot divorce itself from the fundamental laws of mechanics and thermodynamics when attempting to derive a thermal history to be used for the modelling of maturation and petroleum generation. As will be shown in this brief Comment, the application of mechanics and thermodynamics to the derivation of the thermal history may require some radical changes to the methods currently used in PSM. Mechanics and thermodynamics require a reducing heat flow during subsidence, but require an increased heat flow during inversion. The failure to apply mechanics and thermodynamics during thermal history derivation in PSM arises from a failure to incorporate the effects of pressure into the kinetic models used for predicting maturation and petroleum generation. Pressure increases the activation energy of endothermic reactions including maturation and petroleum generation in the kinetic model used to predict the reaction rate, and results in higher temperatures being required to produce the same transformation ratio as would be required for the current temperature – time kinetic models. Incorporating pressure should enable the same thermal history obtained from tectonic history‐mechanic‐thermodynamic models to be used as those used to calibrate the thermal history using maturity parameters such as vitrinite reflectance.

New insight on petroleum system modeling of Ghadames basin, Libya

Underdown and Redfern (2008) performed a detailed petroleum system modeling of the Ghadames basin along an E–W section. However, hydrocarbon generation, migration and accumulation changes significantly across the basin due to complex geological history. Therefore, a single section can't be considered representative for the whole basin. This study aims at bridging this gap by performing petroleum system modeling along a N–S section and provides new insights on source rock maturation, generation and migration of the hydrocarbons using 2D basin modeling. This study in conjunction with earlier work provides a 3D context of petroleum system modeling in the Ghadames basin.Hydrocarbon generation from the lower Silurian Tanezzuft formation and the Upper Devonian Aouinet Ouenine started during the late Carboniferous. However, high subsidence rate during middle to late Cretaceous and elevated heat flow in Cenozoic had maximum impact on source rock transformation and hydrocarbon generation whereas large-scale uplift and erosion during Alpine orogeny has significant impact on migration and accumulation. Visible migration observed along faults, which reactivated during Austrian unconformity. Peak hydrocarbon expulsion reached during Oligocene for both the Tanezzuft and the Aouinet Ouenine source rocks. Based on modeling results, capillary entry pressure driven downward expulsion of hydrocarbons from the lower Silurian Tanezzuft formation to the underlying Bir Tlacsin formation observed during middle Cretaceous.Kinetic modeling has helped to model hydrocarbon composition and distribution of generated hydrocarbons from both the source rocks. Application of source to reservoir tracking technology suggest some accumulations at shallow stratigraphic level has received hydrocarbons from both the Tanezzuft and Aouinet Ouenine source rocks, implying charge mixing. Five petroleum systems identified based on source to reservoir correlation technology in Petromod*. This Study builds upon the original work of Underdown and Redfern, 2008 and offers new insights and interpretation of the data.

Combined Petroleum System Modeling and Comprehensive Two-Dimensional Gas Chromatography To Improve Understanding of the Crude Oil Chemistry in the Llanos Basin, Colombia

Important properties of a crude oil, such as viscosity, are determined by the crude oil’s chemical constituents. In particular, viscosity is highly dependent on the asphaltene content. Various processes that act on reservoir crude oils can alter chemical composition, such as aspahltene content, and therefore impact important crude oil properties. In many basins, such as the Llanos basin in Colombia, processes such as biodegradation, water washing, and multiple charging can contribute to asphaltene and viscosity variations. The considerable complexity of the problem requires a multidisciplinary workflow to understand the main factors that influence the quality of reservoir crude oils and their gradients. Here, we perform comprehensive two-dimensional gas chromatography with flame ionization detection and with mass spectrometry on samples of known provenance, combined with petroleum system modeling, to develop an understanding of the primary factors controlling asphaltene content and viscosity in a reservoi...

Petroleum system modeling in the Eastern Cordillera of Colombia using geochemistry and timing of thrusting and deformation

In the present study, stratigraphic data from cores and outcrop sections are integrated with data on thermal maturity, organic facies, and thermochronometric information to reconstruct the tectonic and associated petroleum system evolution of the eastern foothills thrust belt along the Colombian Eastern Cordillera, one of the most prolific hydrocarbon provinces in northern South America. Sedimentary and tectonic burial of the foreland autochthon caused maturation of the Coniacian to Santonian shallow marine Chipaque Formation, resulting in successive and diachronous episodes of hydrocarbon migration and trapping. One-dimensional and two-dimensional maturation modeling indicates that oil generation from the Chipaque Formation began at the Paleocene-Eocene boundary (55 Ma) in the southern parts of what is now the Eastern Cordillera and progressed to the north. By the late Oligocene, tectonic inversion of the Eastern Cordillera exhumed most of these kitchens, terminating the oil generation from the Chipaque Formation. Kitchens migrated northward and eastward during the Oligocene and early Miocene. Because of the absence or subsequent erosion of traps, it is likely that the southernmost source rocks expelled most of their oil without any appreciable accumulation. Our modeling indicates that there were two important kitchens during the Cenozoic. The larger of the two was located in the present-day Eastern Cordillera, and it was most productive in the late Eocene–early Oligocene. The second kitchen, which generated oil throughout the Neogene, was located in the foredeep of the Llanos basin, adjacent to the mountain front. Considerable amounts of oil from this recent pulse have accumulated in both deep and shallow reservoirs along the eastern foothills. The modeled reservoir charge history also explains the substantial biodegradation of oils in reservoirs that are today much too deep to support the process. Biodegradation must have occurred when the reservoirs were shallower and at cooler temperatures, and they remained active until the reservoirs were buried to depths where temperatures were high enough to prevent further bacterial activity.

Kinematic restoration of contractional basement structures using thermokinematic models: A key tool for petroleum system modeling

In this paper, we demonstrate a workflow for constructing kinematic restorations in complex foothill areas devoid of growth strata and other indicators for the chronology of deformation. Our initial reconstructions utilize thermochronometric data, a well-documented structural geometry, and a first-order conversion of exhumation rates into tectonic rates. We then utilize models obtained from the new in-house–developed software FetKin to build a first version of the thermokinematic restoration. The FetKin approach is geared primarily toward testing and further calibration and refinement of the kinematic restoration, based on the extent to which the model result agrees with thermochronometric data from the study area in the form of both discrete ages and inverse-modeled time–temperature envelopes. This analysis also provides rates of shortening and time–temperature paths throughout the model space that can be used to make first-order predictions of when different source rocks entered the oil window. These capabilities are demonstrated in a pilot case study along a cross section in the Colombian Eastern Cordillera. The improved confidence in the reconstruction that this technique provides allows us to show increasing shortening rates in this part of the Andes during the Neogene reaching up to 5 mm/yr (0.20 in./yr) by the Pliocene, and constrain the timing of generation from the most important oil kitchens for the Eastern Cordillera-Llanos basin petroleum system. This approach, therefore, proves to be a useful method for creating high-resolution and high-fidelity kinematic restorations.