Basin Modeling Study Research Articles

Source Rock Presence and Maturity Along the Northwest African (MSGBC) Margin: Results from a Seep Sample and Basin Modelling Study

Source Rock Presence and Maturity Along the Northwest African (MSGBC) Margin: Results from a Seep Sample and Basin Modelling Study

Hydrocarbon generation and expulsion of Campanian Galhak shale, Rawat Central sub-basin, Sudan: implications from 1D basin modelling study

Hydrocarbon generation and expulsion of Campanian Galhak shale, Rawat Central sub-basin, Sudan: implications from 1D basin modelling study

Radioactive heat production variations in the Faroe–Shetland Basin: key new heat production, geological and geochronological data for regional and local basin modelling

This study presents the results of a joint Chemostrat–APT study that aimed to produce a suite of radioactive heat production data for basement rocks in the Faroe Shetland Basin to enable more accurate basin modelling to be undertaken. To enable regional studies to be undertaken, the basement has been split into four zones based on similarities. Zone A is formed of high grade metamorphic basement from the Rockall trough (quads 154 & 164) SW of the Laxfordian front. Zone B comprises granodioritic, tonalitic and dioritic Neoarchean aged (2700–2830 Ma) high grade metamorphic basement from the SW of the Rona Ridge and Basin (wells 202/08-1, 204/15-2, 205/161, 205/21-1A, 206/7a-2, 206/08-2, 206/09-2 and 206/12-1) and NE of the Laxfordian front. Zone C contains Neoarchean aged high grade metamorphic basement of a predominantly granitic and quartz rich granitoid composition from the NE of the Rona Ridge (wells 207/01-3, 207/02-1, 208/23-1 and 208/26-1). Zone D differs from the rest of the material in this study in that it is Caledonian ( c. 460 Ma) granitic plutonic basement from Quads 209 (Ereland volcanic centre). Radioactive heat production values were derived from potassium, thorium and uranium data produced from the analysis of eighty-four basement samples by ICP-OES and ICP-MS analysis. Each mapped basement zone was then assigned a mean radioactive heat production value for use in future basin modelling studies; Zone A = 0.21 µWm 3 , Zone B, 0.64 µWm 3 , zone C = 0.88 µWm 3 and zone D = 2.1 µWm 3 . Supplementary material: Tables containing full mineralogical (SI 1) and U-Pb geochronological analytical (SI 2) data at https://doi.org/10.6084/m9.figshare.c.6771540 Thematic collection: This article is part of the New learning from exploration and development in the UKCS Atlantic Margin collection available at: https://www.lyellcollection.org/topic/collections/new-learning-from-exploration-and-development-in-the-ukcs-atlantic-margin

An integrated geochemical analysis, basin modeling, and palynofacies analysis for characterizing mixed organic-rich carbonate and shale rocks in Mesopotamian Basin, Iraq: Insights for multisource rocks evaluation

Shales and carbonate-rich sediments are crucial in characterizing the geological history of petroleum as source rocks. This emphasizes the global significance of carbonate source rocks, and it has sparked research interests and exploration of these strata as unconventional resources. This study presents inclusive organic geochemical characteristics, palynofacies analysis, and basin modeling of the carbonate source rocks in the Ajeel oilfield, Mesopotamian Basin, Iraq. This study used traditional and advanced geochemical techniques, as well as microscopic examination and basin modeling. A total of 109 core and cutting samples from the Middle Jurassic–lowermost Early Cretaceous succession were studied via geochemical and palynological methods to evaluate their thermal maturation, depositional conditions, and hydrocarbon (HC) generation potential by combining one-dimensional (1D) modeling of the burial/thermal history and the generation/expulsion timing in the Mesopotamian Basin, Iraq. The results of total organic carbon/Rock-Eval pyrolysis revealed that the Middle Jurassic–lowermost Early Cretaceous interval predominantly comprised carbonate-rich sediments with Type-II and mixed Type-II/III kerogen. Furthermore, the results showed that these potential source rocks were of fair to excellent quality (oil window) and were deposited mainly in an anoxic marine environment. Geochemical and palynological investigation suggested that the carbonate-rich source rocks were deposited mainly under a distal suboxic–anoxic condition and contained Type-II kerogen (oil prone), except for part of the Chia Gara Formation, which displayed distal dysoxic–oxic shelf depositional conditions. The 1D basin modeling results of the burial/thermal maturation history and the generation/expulsion timing showed that these sediments reached their peak generation potential (main oil window) during the Early Miocene, and this has continued until the present day. Subsequently, the Middle Jurassic–lowermost Early Cretaceous succession represents the main source of petroleum in the Mesopotamian Basin, Iraq.This work shows how an integrated palynofacies analysis, basin modeling, and geochemical study can be used for the precise assessment of multisource rock intervals of mixed organic-rich carbonate and shale rocks. These research findings will provide guidance for better resource exploitation in northern Iraq, which has higher source-rock quality in terms of organic richness and maturity than that in southern Iraq.

Petroleum system analysis of the Paleozoic series in the Fars Platform of Iran

The Paleozoic petroleum system of the Fars Platform of Iran is analyzed using 1D petroleum system models of 17 deep wells drilled in the study area. The main aim was to investigate the hitherto undocumented influence of salt tectonics on the essential elements and processes of this petroleum system. For the first time, a better understanding about the geohistory evolution of this prolific petroleum system is provided over the Fars Platform. Modeling results indicate that hydrocarbon generation from the Silurian source rock was associated with salt withdrawal synclines. Salt tectonics further controlled the entrapment styles and the geometric distribution of carrier/reservoir rocks and their overlying evaporitic seals. Our findings provide new insights for identifying the remaining exploration potential in the Paleozoic petroleum system of the Fars Platform and suggest that the role of salt tectonics should be considered in the future basin and petroleum system modeling studies in this area.

A 3D basin modeling study of the factors controlling gas hydrate accumulation in the Shenhu Area of the South China Sea

Great advancement has been made on natural gas hydrates exploration and test production in the northern South China Sea. However, there remains a lot of key questions yet to be resolved, particularly about the mechanisms and the controls of gas hydrates enrichment. Numerical simulaution would play signficant role in addressing these questions. This study focused on the gas hydrate exploration in the Shenhu Area, Northern South China Sea. Based on the newly obtained borehole and multichannel reflection seismic data, the authors conducted an integrated 3D basin modeling study on gas hydrate. The results indicate that the Shenhu Area has favorable conditions for gas hydrate accumulation, such as temperature, pressure, hydrocarbon source, and tectonic setting. Gas hydrates are most concentrated in the Late Miocene strata, particularly in the structual highs between the Baiyun Sag and the Liwan Sag, and area to the south of it . It also proved the existence of overpressure in the main sag of source rocks, which was subject to compaction disequilibrium and hydrocarbon generation. It also shown that the regional fault activity is not conducive to gas hydrate accumulation due to excess gas seepage. The authors conjecture that fault activity may slightly weaken overpressure for the positive effect of hydrocarbon expulsion and areas lacking regional fault activity have better potential.

Nature of the Cuvier Abyssal Plain crust, offshore NW Australia

Magnetic stripes have long been assumed to be indicative of oceanic crust. However, continental crust heavily intruded by magma can also record magnetic stripes. We re-evaluate the nature of the Cuvier Abyssal Plain (CAP), offshore NW Australia, which hosts magnetic stripes and has previously been defined as oceanic crust. We show that chemical data from a basalt within the CAP, previously described as an enriched mid-ocean ridge basalt, could equally be interpreted to contain evidence of contamination by continental material. We also recognize seaward-dipping reflector sequences in seismic reflection data across the CAP. Borehole data from overlying sedimentary rocks suggests that these seaward-dipping reflectors were emplaced in a shallow water (<200 m depth) or subaerial environment. Our results indicate that the CAP may not be unambiguous oceanic crust, but may instead consist of a spectrum of heavily intruded continental crust through to fully oceanic crust. If the CAP represents such a continent–ocean transition zone, then the adjacent unambiguous oceanic crust would be located >500 km further offshore NW Australia than currently thought. This would impact plate tectonic reconstructions, as well as heat flow and basin modelling studies. Our work also supports the growing consensus that magnetic stripes cannot, by themselves, be used to determine crustal affinity. Supplementary material: Enlarged and uninterpreted versions of the magnetic data and seismic reflection lines are available at https://doi.org/10.6084/m9.figshare.c.5332172

Source rock maturity evaluation and its implications for regional petroleum charge, Sirt Basin, Libya: Insights from regional geochemical assessments and modelling study

Six marine and lacustrine source rocks were studied to define their thermal maturation levels in the largest, youngest, and most productive petroliferous sedimentary basin in Libya (Sirt Basin). From the oldest to the youngest, the studied source rock formations were: 1) Middle Nubian; 2) Etel; 3) Rachmat; 4) Sirte; 5) Kalash; and 6) Hagfa. The calibrated basin modelling studies (1D, 2D, and 3D) were used to generate regional maturation maps for each source rock in the basin. Thermal maturity calibration was carried out at different levels utilising measured and simulated vitrinite reflectance (VRo), pyrolysis Tmax data, and 39 typical wells for burial history modelling and geochemical screening. Corrected bottom hole temperature data were used to obtain the geothermal gradient and heat flow throughout the basin. The thermal gradient and heat flow analyses results indicated that the Sirt Basin has an average geothermal gradient of approximately 1.58 °F/100 ft and an average heat flow of 72 m.W.m−2 with a systematic heat flow increase toward the basin platforms and a decrease toward the basin troughs. The conducted assessments in the Sirt Basin presented different levels of source rocks thermal maturity due to variable burial depths, with an average VRo range of 0.35%–2%. The lower Cretaceous source rocks were subjected to higher degrees of diagenesis of organic matter (i.e. mid-to over-mature rocks), with an average VRo of 0.9%–2%. In contrast, the Upper Cretaceous source rocks demonstrated a wide range of thermal maturity (from marginally to late mature) in the deepest part of the Sirt Basin (Ajdabiya trough), whereas the late Palaeocene source rocks entered the mid-to late-maturity levels in the Wadayet trough (North Ajdabiya trough).

Overpressure evolution controlled by spatial and temporal changes in the sedimentation rate: Insights from a basin modelling study in offshore Suriname

AbstractThis study investigates overpressure evolution and its relationship to the spatial and temporal changes in the sedimentation rate in the passive continental margin of offshore Suriname. We analysed well data to estimate pore pressure at the well locations and to interpret relevant overpressure‐generating mechanisms. Three‐dimensional basin modelling was performed to reconstruct overpressure evolution in the area. The well data indicated disequilibrium compaction as the main overpressure‐forming mechanism. The results of the modelling indicated a temporal variation in the sedimentation rate caused cycles of overpressure formation in the region. Periods of high sedimentation lead to overpressure formation, and this overpressure dissipates during periods of quiescent sedimentation. The latest overpressure development since the Middle–Late Miocene was triggered by a notable increase in the siliciclastic supply to the basin, which reflects the Andean uplift and reorganization of the drainage system. Spatial changes in the sedimentation rate resulted in a lateral variation in the amount of overpressure. Disequilibrium compaction generated large overpressure in the area with a high‐sedimentation rate because of the fast increasing rate of overburden load. In addition, the high‐temperature condition beneath the rapid sedimentation area could cause additional mechanisms for overpressure formation in the deeper part of the basin. This study reveals that the complex overpressure history and its lateral variation in offshore Suriname were mainly caused by a single controlling factor (i.e. the sedimentation rate). This article gives an insight into overpressure evolution in sedimentary basins by considering the perspective of the spatio‐temporal variation in the sedimentation rate and its connection with hinterland evolution.

Core versus cuttings samples for geochemical and petrophysical analysis of unconventional reservoir rocks

Core samples from petroleum wells are costly to obtain, hence drill cuttings are commonly used as an alternative source of rock measurements for reservoir, basin modelling, and sedimentology studies. However, serious issues such as contamination from drilling mud, geological representativeness, and physical alteration can cast uncertainty on the results of studies based on cuttings samples. This paper provides a unique comparative study of core and cuttings samples obtained from both vertical and horizontal sections of a petroleum well drilled in the Canadian Montney tight gas siltstone reservoir to investigate the suitability of cuttings for a wide range of geochemical and petrophysical analyses. The results show that, on average, the bulk quantity of kerogen or solid bitumen measured in cuttings is comparable to that of the core samples. However, total organic carbon (TOC) measurements are influenced by oil-based drilling mud (OBM) contamination. Solvent-cleaning of cuttings has been shown to effectively remove OBM contamination in light, medium, and heavy range hydrocarbons and to produce similar kerogen/solid bitumen measurements to that of core samples. Similarly, pyrolysis methods provide an alternative to the solvent-cleaning procedure for analysis of kerogen/solid bitumen in as-received cuttings. Microscopic study substantiates the presence of significant contamination by OBM and caved organic and inorganic matter in the cuttings, which potentially influence the bulk geochemistry of the samples. Furthermore, minerals in the cuttings display induced micro-fractures due to physical impacts of the drilling process. These drilling-induced micro-fractures affect petrophysical properties by artificially enhancing the measured porosity and permeability.

Miocene Biogas Generation System in the Carpathian Foredeep (SE Poland): A Basin Modeling Study to Assess the Potential of Unconventional Mudstone Reservoirs

This paper presents the results of a research project aimed at evaluating the unconventional natural gas potential of the autochthonous Miocene sediments in the Polish part of the Carpathian Foredeep. The primary objective of the study was to re-evaluate the biogenic gas generation system within Miocene sediments, paying special attention to unconventional gas resources accumulated in tight mudstone formations. The four-dimensional (4D) petroleum system modeling method (PetroMod software) was used to reconstruct the basin geometry and three-dimensional (3D) evolution through a geological timescale, in particular the progress of gas generation, migration, and accumulation processes, as well as their consequences for gas exploration and development. Special attention was paid to the dynamics of gas generation processes and the advancement of sediment compaction and their time dependence, as well as to the progress and outcomes of gas migration and accumulation processes. The results indicate significant potential for unconventional gas accumulations in mudstone reservoirs. However, part of the biogenic gas resources occurs in a dispersed form. Analysis of the dynamics of biogenic gas generation and accumulation conducted on a basin scale and within particular sedimentary complexes and depth intervals allowed an indication of the premises regarding the most favorable zones for mudstone–claystone reservoir exploration.

Vertical effective stress and temperature as controls of quartz cementation in sandstones: Evidence from North Sea Fulmar and Gulf of Mexico Wilcox sandstones

Abstract We present quantitative petrographic data, high spatial resolution oxygen isotope analyses of quartz cement, basin modelling and a kinetic model for quartz precipitation for two Paleocene-Eocene Wilcox Group sandstones from Texas and two Jurassic Fulmar Formation sandstones from the Central North Sea. At each location, one sandstone has been buried to ca. 145 °C and one to ca. 185 °C. A key difference between the Wilcox and Fulmar burial histories is that the Wilcox sandstones are currently at higher vertical effective stresses and, from basin modelling studies, have been subjected to generally higher vertical effective stresses through their burial history. The amounts of quartz cement in the Wilcox sandstones are between 12 and 18%, and between 2 and 6% in the Fulmar sandstones. High-spatial-resolution oxygen isotope data obtained from the quartz cements suggest temperature ranges for quartz precipitation from 60 to 80 °C to values approaching maximum burial temperature. Factors such as grain coatings or the timing of petroleum emplacement cannot explain the differences in the amounts of quartz cement. Petrographic data show that most of the silica for quartz cement can be derived from intergranular pressure dissolution. Although the sample set is small, we interpret the results to suggest that the differences in quartz cementation in Fulmar and Wilcox sandstones can be explained better by differences in their vertical effective stress history than their temperature history; in this case, the supply of silica rather than the precipitation of quartz becomes an important control on the rate and extent of cementation.

An Assessment of Stress States in Passive Margin Sediments: Iterative Hydro-Mechanical Simulations on Basin Models and Implications for Rock Failure Predictions

Capturing the past and present hydro-mechanical behavior of passive margin sediments raises noticeable interest, notably in geo-hazard risk assessment and hydrocarbon exploration. In this work, we aim at assessing the stress states undergone by these sedimentary deposits through geological time. To do so, we use an iterative coupling between a basin simulator and a finite element mechanical solver. This method conciliates a computation of the full stress tensors with a dynamic and geologically detailed modelling of the sedimentation. It is carried out on a dedicated set of 2D synthetic basin models, designed to be representative of siliciclastic deposition in passive margins and integrating variations in their geological history. Contrary to common assumptions in operational basin modelling studies, our results imply that passive margin sedimentary wedges are multidimensional mechanical systems, which endure significant non-vertical stress without external tectonic input. Our results also highlight the variability of the stress states through space and time, with a strong control from the geometry and lithological heterogeneities of the deposits. Lastly, we used the simulation results to predict a location and timing for the development of weakness zones in the sedimentary stacks, as privileged areas for rock failure. The outcome underlines the influence of the basal tilt angle, with a slight tilt impacting the wedges stability to a similar extent as a substantial increase in sedimentation rate. Altogether, this study emphasizes the need for careful consideration of non-vertical stresses in basin simulations, including in passive tectonic contexts. It also suggests that the iterative coupling method employed is a promising way to match industrial needs in this regard.

Quantification of thermal conductivity uncertainty for basin modeling

Thermal conductivity is a major influencing factor on subsurface conductive heat transport and resulting temperature distribution, which in turn is a key parameter in basin modeling. Basin modeling studies commonly use representative literature values of thermal conductivity despite their impact on modeling results. We introduce a workflow for quantifying the effect of uncertain thermal conductivity on subsurface temperature distribution and thus on basin modeling results and test this workflow on a two-dimensional generic model from the Nordkapp Basin; a prior ensemble of possible models is conditioned according to Bayes’ theorem to incorporate prior knowledge of temperature data. This conditional probability yields a posterior ensemble of temperature fields with a significantly reduced standard deviation. To verify our approach, we use five characteristic scenarios from the posterior ensemble for transient petroleum systems modeling. How considering uncertain thermal conductivity affects variance in hydrocarbon generation is assessed by modeling corresponding vitrinite reflectances (Ro). Temperature uncertainty increases with depth. It also increases with increasing offset from the salt diapirs, which can be associated with a large lateral heat-flow component in the complex tectonic environment of the Nordkapp Basin. The introduced workflow can reduce temperature uncertainty significantly, especially in regions with high prior uncertainty. The Ro is very sensitive to changes in thermal conductivity because the onset depth of the gas window in the Nordkapp Basin may vary by up to 800 m (2600 ft) within the 95% confidence interval. This demonstrates the importance of quantification of the uncertainty in thermal conductivity on thermal basin modeling.

Lower Palaeozoic petroleum systems of the Baltic Basin in northern Poland: A 3D basin modeling study of selected areas (onshore and offshore)

We have developed a Lower Palaeozoic petroleum systems analysis in the selected zones of the Polish section of the Baltic Basin (onshore and offshore), which we carried out to assess the potential of shale rock formations as unconventional reservoirs. The areas of the Baltic Basin, which we analyzed represent a diversity of shale formations burial depths and thus different advancement of sediments compaction and organic matter transformation. Methods of dynamic petroleum systems modeling were applied with a 3D modeling workflow (PetroMod suite software). We considered an extensive array of data, including results of geochemical and petrophysical laboratory measurements, geophysical borehole data and, in selected locations — 3D seismic data. Five potentially perspective shale rock intervals (Silurian [2], Ordovician [2], and Upper Cambrian [1]) are identified and interpreted in terms of their geochemical and petrophysical properties. We calibrated the petroleum system models in terms of proper reproduction of diagenetic processes (pore pressure and porosity), thermal conditions (vitrinite reflectance, temperature), and kerogen kinetic model (organic matter transformation ratio, types of hydrocarbons generated). The results of the petroleum system simulations reveal that for the predominant part of the analyzed area, the achieved level of kerogen thermal maturity determines the generation of liquid hydrocarbons, which results in the present-day saturation of shale formations mainly with crude oil. We concluded that the highest generation yields as well as present-day hydrocarbons in place are observed for Ordovician Sasino Formation (onshore and offshore), Silurian/Llandovery Jantar member (onshore), and Upper Cambrian (alum shales) formation. Furthermore, a significant variation in the mass/volumes of accumulated hydrocarbons is observed within each of the shale formations being considered.

Simulating the timing of petroleum generation and expulsion from deltaic source rocks: Implications for Late Cretaceous petroleum system in the offshore Jiza-Qamar Basin, Eastern Yemen

The Mukalla Formation is one of the important petroleum source rocks in the Jiza-Qamar Basin, Eastern Yemen. In this study, coal, coaly shale and shale samples from three wells (Al-Fatak-1, 16/G-1 and 16/E-1) in the offshore Jiza-Qamar Basin were studied. The organic matter richness, kerogen type, thermal maturity, and petroleum generation potential of the Mukalla organic-rich samples were investigated.The analysed Mukalla source rock samples are potentially rich in organic matter of 1.01–84.40% TOC, ranging from good to excellent source rocks. The Mukalla source rocks primarily contain Types II, II–III and III kerogen, anticipating generating mainly oil and gas. This is generally consistent with the pyrolysis–gas chromatography results and further indicates that the Mukalla source rocks can produce high wax oil and condensate/gas. The thermal maturity parameters reveal the Mukalla source rocks are in mature to late-mature and are capable of generating oil and wet gas at the present time. In addition, this study was integrated the geochemical, geo-thermal and geological data in term of basin modeling study to simulate the timing of hydrocarbon generation and expulsion from the Mukalla deltaic source rocks.The basin model results indicate that the oil generation commenced during the late Eocene to late Oligocene, with a conversion ratio of 10–50 TR%. Furthermore, based on TRs of more than 50%, the most of oil was expelled along the micro-fracturing of the Mukalla source rocks and then trapped in the Mukalla Formation itself during the latest Oligocene and continued to present-day.

The variability of rock thermal properties in sedimentary basins and the impact on temperature modelling – A Danish example

Detailed knowledge of in situ formation thermal properties is a prerequisite for accurate temperature predictions from geothermal models of sedimentary basins. The value and regional variability of such formation thermal properties generally receive little attention: very few attention in petrophysical and even less in modelling studies. Consequently, the spatial variability of formation thermal properties is typically not considered, for neither the a priori model parameterisation nor the posteriori model calibration.This basin study determines how the thermal properties of geological formations vary spatially and how this affects the quality of modelling results compared to the results of measured temperatures in the Danish Basin. Formation petrophysical properties (thermal conductivity, radiogenic heat production, thermal diffusivity, specific heat capacity, density, and porosity) and their spatial variability in the Danish Basin are exemplarily and systematically studied by well-log interpretation techniques. Therefore, the initial computations of the mean formation well-log values (and their variability) are presented for thermal diffusivity and specific heat capacity.The analysis reveals that all the formation thermal properties display a larger variability than previously applied in geothermal or basin modelling studies. The observed maximum variability of the mean thermal formation values is up to approximately 50% (mean: 23 ± 11%) for thermal conductivity, up to approximately 65% (mean: 34 ± 16%) for thermal diffusivity, up to approximately 30% (mean: 16 ± 8%) for specific heat capacity, and up to more than 100% (mean: 64 ± 24%) for the radiogenic heat production.A strong regional thermal-conductivity variability impact was quantified by the comparison of subsequently modelled geotherms with measured borehole temperatures. When basin-wide mean formation conductivities (representing the usual assumption of constant formation values in geothermal models) are applied to such models, the misfit between the predicted and measured temperatures at the maximum borehole depth of approximately 4 km is large and averages approximately 20% (range: −21 to 22 °C). Application of the observed but less representative formation conductivities in terms of the ‘true’ overall basin average yields maximum derivations between 27 and 66% (range: −38 to 90 °C). The application of local formation conductivities, in contrast, yields minimum deviations generally less than <5 °C, depending on consideration of regional or location-specific heat-flow values.Statistical data on the mean formation variability presented here can serve as guidelines to define reasonable variation ranges for the input or the post-processing calibration procedures for geothermal models of sedimentary basins with similar lithologies and genesis to the Danish Basin. In general, knowledge of the variability of formation thermal properties will lead to a significantly lower uncertainty in the temperature calculations, in particular but not exclusively for areas and depths where temperature observations are unavailable.

Burial and thermal history reconstruction of the Mukalla-Sayhut Basin in the Gulf of Aden, Yemen: Implications for hydrocarbon generation from Paleocene potential source rock

In this study, four exploratory wells from the Mukalla-Sayhut Basin, Gulf of Aden are used for basin modeling study in order to simulate the petroleum generation and expulsion history of the Umm Er Radhuma Formation.The basin models illustrate that the Gulf of Aden is an extensional rift basin and initially developed during Oligocene as indicated by paleo-heat flow values. The heat flow reached peak heat-flow values of approximately 120–160 mW/m2 at Early to Middle Oligocene time. This high paleo-heat flow had a considerable effect on the Paleocene Umm Er Radhuma source rock and cooking of the organic matter. The basin models also indicate that the Umm Er Radhuma Formation source rock had passed the peak-oil generation window during the late Oligocene (Chattian) age. Onset of oil-generation began during late Rupelian age (∼29 Ma), whereas the main oil was generated during the Chattian age (27-24 Ma). The models also show that the petroleum was expelled from the Umm Er Radhuma source rock since latest Oligocene (late Chattian, < 24Ma) time, with transformation ratio of more than 50%. These basin models suggest that the Umm Er Radhuma Formation is an effective source rock where significant amount of petroleum is expected to be generated and expelled to any nearby potential reservoir rocks within the Mukalla-Sayhut Basin.

Disequilibrium compaction overpressure in shales of the Bavarian Foreland Molasse Basin: Results and geographical distribution from velocity-based analyses

Abstract Shale velocity data from sonic logs and vertical seismic profiles, drilling data and in situ pressure measurements from a total of 116 wells have been analyzed to gain an improved understanding of the lateral and vertical distribution and formation of overpressure in the Bavarian Foreland Molasse Basin. Pore pressure from sonic and vertical seismic profile velocities has been analyzed by establishing a normal compaction trend for Cenozoic and Mesozoic shales combined with a classical Eaton approach. The study demonstrates that a single shale normal compaction trend for the Bavarian Foreland Molasse Basin is sufficient to estimate pore pressure and thus overpressure from sonic and vertical seismic profile velocity. Maximum overpressure develops at depths between 1500 and 2500 m and increases with depth at a constant effective stress of 20 MPa. The strong dependency of overpressure on burial depth, constant effective stress and restriction to shale units that are overlain by sequences with very high sedimentation rates indicates that disequilibrium compaction is the main cause for overpressure. Also, variable presence of Cretaceous shales is a key control of overpressure occurrence in Oligocene shales in the Bavarian Foreland Molasse Basin, since Cretaceous shales likely act as a “pressure buffer” to underpressured Mesozoic carbonates. Successful detection and prediction of overpressure from vertical seismic profile data is encouraging for future pre-drill prediction of overpressure from velocity data of seismic surveys in the Bavarian Foreland Molasse Basin, resulting in improved well planning, reliable calculation of project costs, and improved safety during drilling activities in the Bavarian Foreland Molasse Basin. The presented overpressure distributions will be a key input for future geomechanical, basin and reservoir modelling studies in the Bavarian Foreland Molasse Basin.

Generation and expulsion history of oil-source rock (Middle Jurassic Sargelu Formation) in the Kurdistan of north Iraq, Zagros folded belt: Implications from 1D basin modeling study

Middle Jurassic Sargelu Formation is an important oil-source rock in the Iraqi Kurdistan oilfields, northern Zagros Fold Belt. The Sargelu source rock is characterised by high organic matter and sulphur content with Type II-S kerogen, which can be expected to generate oil at low maturity stages.A 1D basin modelling was performed by integrating geological and geochemical data of the Sargelu source rock from six wells in the Kurdistan region, north Iraq. The basin modelling results was used to reconstruct the burial and thermal history and to simulate and predict the timing of petroleum generation and expulsion for the Middle Jurassic Sargelu source rock. Burial/thermal history models indicate that the Sargelu source rock had passed the peak-oil generation window during the Late Eocene to Late Miocene. Onset of oil-generation began during the Middle Eocene - Late Miocene (51-11 Ma), whereas the maximum rates of oil with limited gas were generated during the Late Eocene to Late Miocene (52-10 Ma). The models also show that the oil was expelled from the Sargelu source rock since Late Eocene to present-day (44-0 Ma), with transformation ratio higher than 50%. The subsequent high transformation ratio higher than 80% suggests that the generated oil was cracked to gas during the Early Oligocene and continued to present day. These basin modeling results also suggest that the Sargelu Formation acts as an effective oil-source where significant amount of petroleum is expected to be generated and expelled to any nearby prospect reservoir rocks in the Kurdistan region.