Petroleum System Modeling Research Articles

Can hydrocarbons entrapped in seep carbonates serve as gas geochemistry recorder?

The geochemistry of seep gases is useful for an understanding of the local petroleum system. Here it was tested whether individual light hydrocarbons in seep gases are representatively entrapped in authigenic carbonates that formed near active seep sites. If applicable, it would be possible to extract geochemical information not only on the origin but also on the thermal maturity of the hydrocarbon source rocks from the gases entrapped in carbonates in the past. Respective data could be used for a better understanding of paleoenvironments and might directly serve as calibration point for, amongst others, petroleum system modeling. For this approach, (sub)-recent seep carbonates from the Black Sea (Paleodnjepr region and Batumi seep area), two sites of the Campeche Knoll region in the Gulf of Mexico, and the Venere mud volcano (Mediterranean Sea) were selected. These seep carbonates derive from sites for which geochemical data on the currently seeping gases exist. During treatment with phosphoric acid, methane and higher hydrocarbons were released from all carbonates, but in low concentrations. Compositional studies demonstrate that the ratio of methane to the sum of higher hydrocarbons (C1/(C2+C3)) is (partly strongly) positively biased in the entrapped gas fraction. δ13C values of C1 were determined for all samples and, for the samples from the Gulf of Mexico and the Mediterranean Sea, also of C2 and C3. The present dataset from six seep sites indicates that information on the seeped methane can be—although with a scatter of several permil—recorded in seep carbonate matrices, but other valuable information like the composition and δ13C of ethane and propane appears to be modified or lost during, for example, enclosure or at an early stage of diagenesis.

Petroleum system modeling of the Sabinas Basin, Northeastern Mexico; Part 2: geochemical implications in 2D integrated basin modeling

Petroleum system modeling of the Sabinas Basin, Northeastern Mexico; Part 2: geochemical implications in 2D integrated basin modeling

Three-dimensional petroleum systems modeling of the Mensa and Thunder Horse intraslope basins, northern deep-water Gulf of Mexico: A case study

The petroleum systems of two adjacent Miocene intraslope minibasins in the northern deep-water Gulf of Mexico are modeled to investigate why one of them produces primarily gas but the other produces oil. Specifically, the Mensa field produces gas from a faulted four-way closure that overlies a turtle structure, whereas the adjacent Thunder Horse field produces from a turtle structure with four-way structural closure. To resolve this issue, a three-dimensional petroleum-system model was constructed, whose results indicate that the Lower Cretaceous source interval, comprising type II kerogen, matured significantly earlier in the Mensa basin; the oil window was reached between 11.4 and 9.0 Ma, and the thermogenic gaswindowwas reached between 6.2 and 0.0Ma. By contrast, within the Thunder Horse basin, the source interval reached the oil window by 10.75 to 9.4Ma and largely remains in the oilwindow. TheThunderHorse trap had formed by 13.05Ma, which was before the end of the oil window. The Mensa trap (9.0-8.2Ma) was not in placewhen the source rock passed though the oil window. The primary control on the timing ofmaturation and charge is related to the original thickness of allochthonous salt that created the accommodation for the thick Miocene deep-water sediments. Originally, the Mensa minibasin contained thicker Cretaceous allochthonous salt than the Thunder Horse minibasin. Consequently, as the salt was loaded with sediment and completely evacuated, the turtle structure (trap) formed earlierin Thunder Horse field than in Mensa. By contrast, the source rocks matured earlier in Mensa, prior to the deposition of reservoir sands and the formation of the trap. The results indicate that turtle structures with similar appearances can have subtle differences in the timing of their petroleum systems, which ultimately control whether the feature is charged and with what fluid. These features must be modeled carefully in evaluating their exploration potential. Copyright © 2017 The American Association of Petroleum Geologists. All rights reserved.

Petroleum System Modeling of Jabal Kand Oil Field, Northern Iraq

The petroleum system of Jabal Kand Oil Field shows that the formations such as Tertiary Kolosh, Cretaceous Shiranish, and Jurassic Sargelu are immature and have not generated any oil Ro 0.55%. Other formations such as Gele Khana and other Triassic formations are with high maturity with Ro≥ 1.3% and are within wet and dry gas window while older formations are either within dry gas zone or completely generated hydrocarbon and depleted after hydrocarbon was expelled and migrated to reservoir rock of structure traps.

Kilometer-scale fault-related thermal anomalies in tight gas sandstones

Upper Carboniferous sandstones make one of the most important tight gas reservoirs in Central Europe. This study integrates a variety of geothermometers (chlorite thermometry, fluid inclusion microthermometry and vitrinite reflection measurements) to characterize a thermal anomaly in a reservoir outcrop analog (Piesberg quarry, Lower Saxony Basin), which is assumed responsible for high temperatures of circa 300 °C, deteriorating reservoir quality entirely. The tight gas siliciclastics were overprinted with temperatures approximately 90–120 °C higher compared to outcropping rocks of a similar stratigraphic position some 15 km to the west. The local temperature increase can be explained by circulating hydrothermal fluids along the fault damage zone of a large NNW-SSE striking fault with a displacement of up to 600 m in the east of the quarry, laterally heating up the entire exposed tight gas sandstones. The km-scale lateral extent of this fault-bound thermal anomaly is evidenced by vitrinite reflectance measurements of meta-anthracite coals (VRrot ∼ 4.66) and the temperature-related diagenetic overprint. Data suggest that this thermal event and the associated highest coalification was reached prior to peak subsidence during Late Jurassic rifting (162 Ma) based on K-Ar dating of the <2 μm fraction of the tight gas sandstones. Associated stable isotope data from fluid inclusions, hosted in a first fracture filling quartz generation (T ∼ 250 °C) close to lithostatic fluid pressure (P ∼ 1000 bars), together with authigenic chlorite growth in mineralized extension fractures, demonstrate that coalification was not subject to significant changes during ongoing burial. This is further evidenced by the biaxial reflectance anisotropy of meta-anthracite coals. A second event of quartz vein formation occurred at lower temperatures (T ∼ 180 °C) and lower (hydrostatic) pressure conditions (P ∼ 400 bars) and can be related to basin inversion. This second quartz generation might be associated with a second event of illite growth and K-Ar ages of 96.5–106.7 Ma derived from the <0.2 μm fraction of the tight gas sandstones.This study demonstrates the exploration risk of fault-bound thermal anomalies by deteriorating entirely the reservoir quality of tight gas sandstones with respect to porosity and permeability due to the cementation with temperature-related authigenic cements. It documents that peak temperatures are not necessarily associated with peak subsidence. Consequently, these phenomena need to be considered in petroleum system models to avoid, for example, overestimates of burial depth and reservoir quality.

Evaluation of shale gas potential in the Lower Cretaceous Sembar Formation, the Southern Indus Basin, Pakistan

The Lower Indus Basin of Pakistan is reported to contain significant recoverable resources of shale oil, but until now no detailed research has been done to estimate its shale gas potential. In this study, an integrated approach was proposed and applied, combining source rock screening (SRS), petroleum system modeling (PSM) and volumetric calculations to evaluate the shale gas potential of the Lower Cretaceous Sembar Formation, the Southern Indus Basin. The study was conducted based on the data from the public domain of petroleum industry in Pakistan, including vertical well sections, well logs, seismic sections, regional geological sections, base maps, and geochemical data. Results of source rock screening (SRS) found that the organic-rich shales of the Sembar Formation have %Ro (vitrinite reflectance) ranging from 0.76 to 3.79 (corresponding to TAI from 2.8 to 2.9), kerogen types ranging from type II to type III, and TOC (total organic carbon) values as high as 9.5%. Results of petroleum system modeling (PSM) indicated that shales of the Sembar Formation are in the thermal window for gas and oil generation. Hydrocarbon generation was found to have started in the Late Cretaceous with maximum burial in the Late Paleogene. Shales of the Sembar Formation are interpreted to be over-pressured at present. Finally, the volumetric calculation estimated that the volume of Retained Gas In Shale (RGIS) of the Sembar Formation is 359 Trillion Cubic feet (Tcf), out of which 43.1 Trillion Cubic feet (Tcf) is risked RGIS. The results of this study concluded that the Sembar Formation has momentous shale gas potential and the integrated approach employed in this study for shale gas potential evaluation is pertinent to evaluate source rocks in other sedimentary basins of Pakistan.

Role of Faults in Hydrocarbon Leakage in the Hammerfest Basin, SW Barents Sea: Insights from Seismic Data and Numerical Modelling

Hydrocarbon prospectivity in the Greater Barents Sea remains enigmatic as gas discoveries have dominated over oil in the past three decades. Numerous hydrocarbon-related fluid flow anomalies in the area indicate leakage and redistribution of petroleum in the subsurface. Many questions remain unanswered regarding the geological driving factors for leakage from the reservoirs and the response of deep petroleum reservoirs to the Cenozoic exhumation and the Pliocene-Pleistocene glaciations. Based on 2D and 3D seismic data interpretation, we constructed a basin-scale regional 3D petroleum systems model for the Hammerfest Basin (1 km × 1 km grid spacing). A higher resolution model (200 m × 200 m grid spacing) for the Snøhvit and Albatross fields was then nested in the regional model to further our understanding of the subsurface development over geological time. We tested the sensitivity of the modeled petroleum leakage by including and varying fault properties as a function of burial and erosion, namely fault capillary entry pressures and permeability during glacial cycles. In this study, we find that the greatest mass lost from the Jurassic reservoirs occurs during ice unloading, which accounts for a 60%–80% reduction of initial accumulated mass in the reservoirs. Subsequent leakage events show a stepwise decrease of 7%–25% of the remaining mass from the reservoirs. The latest episode of hydrocarbon leakage occurred following the Last Glacial Maximum (LGM) when differential loading of Quaternary strata resulted in reservoir tilt and spill. The first modeled hydrocarbon leakage event coincides with a major fluid venting episode at the time of a major Upper Regional angular Unconformity (URU, ~0.8 Ma), evidenced by an abundance of pockmarks at this stratigraphic interval. Our modelling results show that leakage along the faults bounding the reservoir is the dominant mechanism for hydrocarbon leakage and is in agreement with observed shallow gas leakage indicators of gas chimneys, pockmarks and fluid escape pipes. We propose a conceptual model where leaked thermogenic gases from the reservoir were also locked in gas hydrate deposits beneath the base of the glacier during glaciations of the Hammerfest Basin and decomposed rapidly during subsequent deglaciation, forming pockmarks and fluid escape pipes. This is the first study to our knowledge to integrate petroleum systems modelling with seismic mapping of hydrocarbon leakage indicators for a holistic numerical model of the subsurface geology, thus closing the gap between the seismic mapping of fluid flow events and the geological history of the area.

Novel basin modelling concept for simulating deformation from mechanical compaction using level sets

As sedimentation progresses in the formation and evolution of a depositional geologic basin, the rock strata are subject to various stresses. With increasing lithostatic pressure, compressional forces act to compact the porous rock matrix, leading to overpressure buildup, changes in the fluid pore pressure and fluid flow. In the context of petroleum systems modelling, the present study concerns the geometry changes that a compacting basin experiences subject to deposition. The purpose is to track the positions of the rock layer interfaces as compaction occurs. To handle the challenge of potentially large geometry deformations, a new modelling concept is proposed that couples the pore pressure equation with a level set method to determine the movement of lithostratigraphic interfaces. The level set method propagates an interface according to a prescribed speed. The coupling term for the pore pressure and level-set equations consists of this speed function, which is dependent on the compaction law. The two primary features of this approach are the simplicity of the grid and the flexibility of the speed function. A first evaluation of the model concept is presented based on an implementation for one spatial dimension accounting for vertical effective stress. Isothermal conditions with a constant fluid density and viscosity were assumed. The accuracy of the implemented numerical solution for the case of a single stratigraphic unit with a linear compaction law was compared to the available analytical solution [38]. The multi-layer setup and the nonlinear case were tested for plausibility.

3D basin and petroleum system modelling of the NW German North Sea (Entenschnabel)

Abstract 3D basin and petroleum system modelling covering the NW German North Sea (Entenschnabel) was performed to reconstruct the thermal history, maturity and petroleum generation of three potential source rocks, namely the Namurian–Visean coals, the Lower Jurassic Posidonia Shale and the Upper Jurassic Hot Shale. Modelling results indicate that the NW study area did not experience the Late Jurassic heat flow peak of rifting as in the Central Graben. Therefore, two distinct heat flow histories are needed since the Late Jurassic to achieve a match between measured and calculated vitrinite reflection data. The Namurian–Visean source rocks entered the early oil window during the Late Carboniferous, and reached an overmature state in the Central Graben during the Late Jurassic. The oil-prone Posidonia Shale entered the main oil window in the Central Graben during the Late Jurassic. The deepest part of the Posidonia Shale reached the gas window in the Early Cretaceous, showing maximum transformation ratios of 97% at the present day. The Hot Shale source rock exhibits transformation ratios of up to 78% within the NW Entenschnabel and up to 20% within the Central Graben area. The existing gas field (A6-A) and oil shows in Chalk sediments of the Central Graben can be explained by our model.

Petroleum systems modelling as an exploration tool: from surface seismic acquisition to basin modelling: a case study from a periplatform basin in Northern Adriatic

The Adriatic Sea hosts important historically explored hydrocarbon provinces. In the northern areas, the main sources of hydrocarbon productivity are from biogenic gas reservoirs located in Quaternary thick deltaic depositional systems related to the Apennine and Dinaric foreland domain. In addition, Mesozoic thermogenic oil plays were identified and exploited in the Southern areas. Herein, we use basin and petroleum systems modelling (BPSM) techniques to investigate the still unproved thermogenic hydrocarbon potential of deep Mesozoic basins in the North Adriatic Sea and to correlate the results with the sedimentary evolution of proven petroleum systems in the Central and South Adriatic, both in the Italian and Croatian offshore areas. We used the regional CROP-M16 marine seismic profile in the eastern segment of the study area, where it cuts the western margin of the Dinaric carbonate platform and reaches the pelagic domain of the Umbria-Marche basin intersecting the Barbara isolated platform (Figure 1). We reprocessed the 2D seismic data set to obtain the correct dips and depths of the geological structures from a depth-migrated profile. During the interpretation phase, we integrated the information from profile CROP-M16 with the orthogonal CROP-M17B and C profiles that are intersecting the Alessandra-001 exploration well. The interpretation allowed a detailed analysis of the main lithological discontinuities and of the fault system. We used the interpreted features together with the petrophysical parameters inferred by the available wells in the area and by literature, for 2D petroleum systems modelling. Our simulation integrated the available information to produce a set of possible scenarios of basin development, with the objective to understand the maturation and migration of hydrocarbons.

The thermal structure of the central Nova Scotia Slope (eastern Canada): seafloor heat flow and thermal maturation models

The thermal history and maturation potential of the central Scotian Slope is constrained using a combination of 47 recently acquired seafloor heat flow measurements, two-dimensional (2D) seismic reflection data, available well data, simple lithospheric rift models, and thermal and petroleum systems modelling. Consistent heat flow values of 41–46 mW·m−2 were measured seaward of the salt diapiric province and across the slope away from the influence of salt structures. Significant but highly variable increases in heat flow were measured for stations overlying salt diapiric structures, reaching values upwards of 72 mW·m−2. Simple models of conductive heat transfer with static salt geometries constrained from reflection profiles indicate that two of the four models fit the data, whereas two indicate much higher values suggestive of additional, convective effects. Dynamic 2D thermal models were developed to incorporate the effects of lithospheric rifting, crustal stretching, and radiogenic heat production in the sediment and basement. These models help constrain the hydrocarbon maturation potential of the central Scotian Slope, where deep borehole data are lacking. Our results suggest that a potential Late Jurassic source rock interval rests primarily within the late oil window and that salt structures act primarily to reduce maturation in the adjacent deep sediment layers.

Inversion of source rock hydrocarbon generation kinetics from Rock-Eval data

Basin and petroleum system modeling requires source rock kinetics as input for the reconstruction of hydrocarbon generation history. For less well-studied petroleum systems, there may be little information on petroleum generation kinetic parameters publically available; thus, an analog of representative source rock kinetics must be chosen from available kinetics databases. Recent studies suggest that source rock kinetics may vary considerably even when they contain the same type of kerogen. Thus, kinetic parameters from analog basins/source rocks may lead to erroneous results in petroleum generation history reconstruction. Rock-Eval data contain information about source rock kinetics, and can be used to improve the kinetic model in petroleum system modeling. However, the kinetic information in Rock-Eval data is not in the form of activation energies and frequency factors required to solve the temperature dependency of reaction rate in the Arrhenius equation. This article proposes a kinetic inversion method so that the analogous kinetic model chosen by the user can be improved based on Rock-Eval data of the targeted source rock. We demonstrate the method using a synthetic dataset in a case study for method validation and its application to real source rock evaluation for examples from the Devonian Duvernay Shale in the Western Canada Sedimentary Basin (WCSB).

Two-Dimensional Seismic Interpretation and Petroleum System Modelling in the Hammerfest Basin, SW Barents Sea

The Hammerfest Basin has undergone several structural and tectonic evolutions which affected its petroleum systems. Two-dimensional seismic interpretation and petroleum system modelling of the Hammerfest Basin was done in order to understand the petroleum system and effects of uplift and subsidence on hydrocarbon distribution, accumulations, maturity, migration and leakage. The central part of the Hammerfest Basin has been affected by Jurassic syn-rift faults forming a large graben structure in response to subsidence along the folded Asterias Fault Complex and Troms-Finnmark Fault Complex. The graben structure is characterized by gas chimney, bright spots and pockmarks. The modelling result shows that the Jurassic Hekkingen Formation is less mature (oil window) and that the Snadd and Kobbe Formations are mature to highly mature (gas window), respectively. The Sto and Tubaen reservoirs are enriched with oil and gas which migrated from the Snadd and Kobbe source rocks. The hydrocarbon accumulations show that the Sto Formation is the main reservoir in the Hammerfest Basin. Rapid burial during Permian and late Cretaceous was followed by uplift events. Three phases of erosion: the first two phases of erosion (75 to 60 Ma and 30 to 15 Ma) affected and eroded 200 m of Kveite Formation and 300 m of the Torsk Formation, respectively and the third phase of erosion (2.5 to 0.01 Ma) has eroded 100 m of Torsk Formation. The oil migration follows the deep seated faults along the Asterias Fault Complex, Troms-Finnmark Fault Complex and along the bounding faults of the graben structure at the center of the basin which leads to leakage. The migration of gas on the other hand, is vertically upward throughout the basin leaking out of the seal. The gas migration has been enhanced by the uplift and subsidence events which have been the main controlling factors of the hydrocarbon maturation and distribution within the Hammerfest Basin.

Integrated 3D basin and petroleum systems modelling of the Great Australian Bight

3D stratigraphic, structural, thermal and migration modelling has become an essential part of petroleum systems analysis for passive margins, especially if complex 3D facies patterns and extensive volcanic activity are observed. A better understanding of such underexplored offshore areas requires a refined 3D basin modelling approach, with the implementation of realistically sized volcanic intrusions, source rocks and reservoir intervals. In this study, an integrated modelling workflow based on a Great Australian Bight case study has been applied. The 244800-km2 3D model integrates well data, marine surveys, 3D stratigraphic forward modelling and 3D basin modelling to better predict the effects of 3D facies variations and heat flow anomalies on the determination of the source rock-enriched intervals, the source rock maturity history and the hydrocarbon migration pathways. Plausible sedimentary sequences have been estimated using a stratigraphic forward model constrained by the limited available well data, seismic interpretation and published tectonic basin history. We also took into account other datasets to produce a thermal history model, such as the location of known volcanic intrusion, volcanic seamounts, bottom hole temperature and surface heat flow measurements. Such basin modelling integrates multiple datatypes acquired in the same basin and provides an ideal platform for testing hypotheses on source rock richness or kinetics, as well as on hydrocarbon migration timing and pathways evolution. The model is flexible, can be easily refined around specific zones of interest and can be updated as new datasets, such as new seismic interpretations and data from new sampling campaigns and wells, are acquired.

Petroleum systems analysis of the northern Houtman Sub-basin

Interpretation of newly acquired seismic data in the northern Houtman Sub-basin (Perth Basin) suggests the region contains potential source rocks similar to those in the producing Abrolhos Sub-basin. The regionally extensive late Permian–Early Triassic Kockatea Shale has the potential to contain the oil-prone Hovea Member source interval. Large Permian syn-rift half-graben, up to 10 km thick, are likely to contain a range of gas-prone source rocks. Further potential source rocks may be found in the Jurassic–Early Cretaceous succession, including the Cattamarra Coal Measures, Cadda shales and mixed sources within the Yarragadee Formation. This study investigated the possible maturity and charge history of these different source rocks. A regional pseudo-3D petroleum systems model was constructed using new seismic interpretations. Heat flow was modelled using crustal structure and possible basement composition determined from potential field modelling, and subsidence analysis was used to investigate lithospheric extension through time. The model was calibrated using temperature and maturity data from nine wells in the Houtman and Abrolhos sub-basins. Source rock properties are assigned based on an extensive review of total organic carbon, Rock Eval and kinetic data for the offshore northern Perth Basin. Petroleum systems analysis results show that Permian, Triassic and Early Jurassic source rocks may have generated large cumulative volumes of hydrocarbons across the northern Houtman Sub-basin, whereas the Middle Jurassic–Cretaceous sources remain largely immature. However, the timing of hydrocarbon generation and expulsion with respect to trap formation and structural reactivation is critical for the successful development and preservation of hydrocarbon accumulations.

Modeling of microbial gas generation: application to the eastern Mediterranean “Biogenic Play”

Biogenic gas is becoming increasingly important as an exploration target in the petroleum industry because it occurs in geologically predictable circumstances and in large quantities at shallow depths as free gas or gas hydrates. As accumulations of biogenic gas result in a subtle synchronization between early generation and early trapping, we integrated a macroscopic model of microbial gas generation within a 3D basin and petroleum system forward simulator. The macroscopic model is based on a microscopic model, which consists in a 1D sedimentary column that accounts for sedimentation, compaction, Darcy flow and Diffusion flow. The organic carbon is the only non-soluble element considered in this version of the model. The dissolved elements are O2, SO4 2-, H2, CH3COOH, and CH4. Methane is dissolved in water or present as a free phase if its concentration exceeds its solubility at given pressure and temperature. In this microscopic model, the transformation of substrate into biomass is described through a set of logistic equations coupled with the transport equations (advection and diffusion). Based on the microscopic considerations we developed the macroscopic model of low maturity/biogenic gas generation in which hydrocarbons are generated through first order kinetic reactions at low maturity. This macroscopic model is adapted to petroleum system modeling at basin scale with TemisFlow®, which aims to understand and predict hydrocarbon generation, migration, and accumulation. It is composed of: i) A source rock criteria which allow defining the biogenic gas source rocks potential and ii) A kinetic model of methane generation. The previous model has been successfully applied on different basins such as the Carupano Basin from the offshore Venezuela, the Magdalena Delta (offshore Colombia) and the offshore Vietnam where direct observations of low-maturity gas were available. Furthermore, it has been applied in the offshore Lebanon in order to check the viability of a biogenic gas system

Quantifying the power of basin knowledge: the value and effects of petroleum systems information

The concept of value of information (VOI) was introduced to the oil and gas industry by Grayson (1960). Although the method is not limited to a specific kind of information, its thorough application is usually limited to seismic surveys, the most common source of geological and geophysical information in hydrocarbon exploration. According to Bratvold et al. (2009), 29 out of 30 reviewed VOI papers over 1962-2006 focused on valuing seismic information. A recent industry survey demonstrated that 10% of exploration wells fail due to a misinterpretation of a trapping structure; 15% fail due to lack of a reservoir or its poor effectiveness, 30% due to the lack of charge, and 45% due to absent or poor top or/and lateral seal (Laver et al., 2012). This means that analyzing the effects of information addressing the latter three geological risk factors should receive as much attention and study as VOI from seismic studies. We propose a new methodology to assess the value added to a prospect assessment through information provided by petroleum systems modeling (Hantschel and Kauerauf, 2009). The impact of a petroleum systems model (PSM) on a prospect assessment is usually more difficult to evaluate than the effect of a new 3D seismic survey because the information provided by a PSM has primarily a basin- or a play-wide extent.

Geochemical Characteristics and Modeling of Conventional Petroleum System of Majnoon Oil Field, South Iraq

Organic geochemical analysis and model set–up to simulate the genetic relationships among 18 crude oil samples recovered from different formations and various oil fields within Amara city South Iraq, with depths approximately begin from 2167 to 4430 m, ages of marine carbonates sourced from Middle Jurassic age (Sargelu Formation) according to geochemical similarities appointed previously for this period. The levels of maturation are relatively varied for each sample from low to moderate, MJ-1, MJ-18 (Hartha Formation), MJ-3, MJ-10 (Mishrif Formation), MJ-9 (Nahr Umr Formation), MJ-15 (ZubairFormation), MJ-2, MJ-19(Nahr Umr Formation MJ- 10,MJ-11(Zubair Formation) MJ-3 (Nahr Umr Formation), Mj-3 (Sulaiy Formation), MJ-12 (two samples) Sulaiy Formation MJ-11, MJ-2 (Nahr Umr Formation), MJ-2 (Zubair Formation), MJ-11 (Sulaiy Formation )of Amara city Oil fields.These samples suggest the ages and paleoenvironments of their source rocks. The samples were collected from Upper Jurassic to Cretaceous reservoirs of 18 developed oil fields where about 15 billion barrels of recoverable oil have been reserved.The oil density varies in rather wide range, between 12.2 and 39.2 API. Twelve oil samples are ˂25 API referring to heavy oil and only oil samples attained defiantly from 25 to 35API are medium oil. Canonial Variables (CV) range attain to (- 1.89 to – 3.99) of waxy oil. According to the Tissot and Welte’s classification (1984), most of the oils can be classified as ‘‘high sulfur’’ oils/indicate that these samples are of marine origin.Stable Carbon Isotope Composition C15+ Saturate and Aromatic is relatively approximate values giving good supporting evidences for the same family which is Middle Jurassic Age (sourced from Sargelu Formation), generated within the sedimentation of the bituminous calcareous shale and Limestone in Mesopotamian basin. This basin consider as one of the most formative, potential and promising basin in the Middle East according to the typical petroleum system elements. This family was generated by marine carbonate - intrashelf sub basin source rocks, occurring in Jurassic – Cretaceous – Neogene reservoir rocks of Mesopotamian basin which are geochemically similar to the extracts from Middle –Upper Jurassic age (Sargelu Formations), yielding the majority of petroleum oil and gas fields in north and south Iraq. Petroleum system modeling in one dimension (1-D Petro Mod) was performed using Petro Mod basin modeling software which developed by Integrated Exploration System (IES) to demonstrate burial thermal history hydrocarbon generation and expulsion for Majnoon oil field so that 1-D Petro Mod was applied to Nine wells (Mj-2, Mj-3, Mj-4, Mj-8, Mj-9, Mj-11, Mj-12, Mj-15, and Mj-19) following the procedure of Pitman et al 2004.

Generalized sensitivity analysis study in basin and petroleum system modeling, case study on Piceance Basin, Colorado

Basin and petroleum system modeling is an interdisciplinary endeavor, and utilizes integrated data to study sedimentary basins. Numerical models are constructed and simulated to quantitatively model the geodynamic processes in sedimentary basins. Often, the modeling process covers large spatial and temporal intervals with many uncertain input parameters. These can be continuous parameters characterized by certain statistical distribution, spatially distributed variables, or discrete parameters such as geological scenarios. Identifying sensitivities from these complex input model parameters and recognizing key uncertainties are crucial and challenging for basin modeling development and applications. The major contribution of this work is to introduce and implement efficient and accurate sensitivity analysis approach for basin and petroleum system modeling discipline.We investigated two types of sensitivity analysis methods and compared their performance for identifying the impact of uncertain parameters on both spatial and temporal model responses. The first approach utilizes the variance-based Sobol indices to quantify parameter sensitivities, while the second approach is a distance-based sensitivity analysis which utilizes the distance between model responses to determine sensitivities of different parameters. The sensitivity analysis approaches are illustrated through a basin modeling example involving the processes of sediment compaction, source rock maturation and hydrocarbon generation in the Piceance Basin, Colorado, US. Monte Carlo samples of the input uncertainties related to physical properties of the source rock, thermal boundary conditions, and geological setting scenarios are generated. Multiple basin models constructed using these uncertain input parameters are simulated across the geological time span, and time-varying model response (hydrocarbon generation from Lower Cretaceous to present-day) and spatial model response (pressure and porosity distribution at present-day) are obtained. Sensitive parameters that impact these spatio-temporal model responses are then analyzed.Results show that the distance-based sensitivity analysis approach could achieve similar results with fewer model runs compared to the variance-based Sobol method. Model responses in spatial and temporal domain are impacted by different uncertain input parameters. Subtle relationship between input parameters and model response could also be identified. In particular an unexpected link between chemical kinetics and porosity versus depth behavior was uncovered. The knowledge obtained from sensitivity studies enhance the understanding of the complex geological processes and can benefit the modeling development and forecast capability. Though the sensitivity results are case-specific, the approach and workflow are generally applicable to other basins and earth sciences modeling studies.

Basin modeling analysis and organic maturation for selected wells from different oil fields, Southern Iraq

One dimension petroleum system modeling was performed on selected wells located within four oil fields in Southern Iraq, these are: Rumila, Subba, Tuba and Ratawi. The geo history analysis was applied for the studied fields; and it shows that the stratigraphic section contains many periods which are different in the tectonic and sedimentary subsidence, burial history, sedimentary, and erosion rates. It was seen that the burial depth was greater in the Ratawi oil field than the other fields. There is a different period of subsidence, which ranges from high to moderate subsidence, occurred at upper Jurassic to Mid-Cretaceous. Also, special uplift occurred in the Miocene and moderate subsidence occurred during the Paleogene. Four unconformities took place during the geological history of the Mesopotamian basin. In general, there is similarity to the burial histories that indicates all formations were deposited in the same basin of the studied oil fields, which was effected by the tectonic and sedimentary subsidence. Heat flow is in range (27–70 mW/m2) which influence in the thermal maturity.