3D Basin Modeling Research Articles

Petroleum system analysis of Fujairah basin, eastern offshore of the United Arab Emirates

The Fujairah basin, located on the eastern margin of the United Arab Emirates, forms part of the hinterland basin of the Oman-UAE mountains. Despite its geological significance, the hydrocarbon potential of this basin remains unexplored. This study aims to address this knowledge gap by using 2D seismic reflection data, three exploration wells, geochemical data from one well, a 2D velocity section, and two pseudo-wells. The study began with the interpretation of the seismic profiles and then proceeded to create depth maps for the most significant units. We used Rock-Eval pyrolysis plots to identify the primary source rocks and to classify their kerogen types. The seismic interpretation formed a basis for the 1D and 2D basin modeling techniques that are used to determine the petroleum system of the basin. Our results identify the Pliocene, Miocene, and Eocene sequences as potential source rocks in the basin with TOC values less than 1 wt% and low expulsion efficiencies. The Pliocene and Miocene source rocks are mainly type-II kerogen, whereas most Eocene samples are characterized as type-III kerogen. The Pliocene and Miocene source rocks are immature in the basin. The Eocene is mature depending on the burial within the sub-basins. The Eocene started expelling hydrocarbons during the Burdigalian, which was linked to the collision of the Arabian and Central Iran plates along the Zagros suture zone. Structural and stratigraphic traps may have entrapped the generated hydrocarbons. The three drilled wells in the basin lack good reservoir rocks. However, low-velocity anomalies and bright spots indicate possible hydrocarbon accumulations in the basin.

Organic geochemistry and 1D-basin modeling in the Taranaki Basin, New Zealand: Implications for deltaic-source rocks of the cenozoic oil and condensate reservoirs

The Taranaki Basin in New Zealand is an area of active exploration for oil and condensate. This research focuses on integrating geochemical characteristics and 1-D basin modeling to Late Cretaceous to Miocene source rock systems, along with oil and condensate data from fifty-seven wells in the Taranaki Basin. The geochemical study reveals that the oil and condensate samples were generated from clay-rich source rocks, containing mixed organic matter, with large amounts of terrestrial organic matter input. These source rocks were deposited in fluvial to fluvio-deltaic environments under oxic conditions. The presence of oleanane in both oil and condensate samples suggests that the source rocks had a significant terrestrial component and deposited during the Late Cretaceous to Cenozoic. Using various biomarker proxies, oil-source rock correlation along with 1-D basin modeling revealed that the oil and condensate were mainly derived from the Late Cretaceous Rakopi and Paleocene Farewell formations at different maturity stages. The oils were generated within the peak-mature oil window, while the condensates primarily resulted from the secondary cracking of oil taking place in the source rock within the gas generation window. This finding is consistent with the 1-D basin modeling results. The model shows that the Paleocene Farewell source rock has achieved the primary stage of oil generation (0.55–0.95 Easy %Ro), contributing to most of the discovered oils in the Cenozoic reservoir rocks. Meanwhile, the Late Cretaceous Rakopi source rock reached the gas window with a higher vitrinite reflectance of more than 1.30 Easy %Ro, indicating greater gas generation potential.

Geochemical characterization of Upper Cretaceous organic-rich deposits: Insights from the Azraq Basin in Jordan

Cretaceous sedimentary successions in Jordan are among the most promising unconventional global petroleum resources. The Upper Cretaceous deposits in the Azraq Basin in Jordan were analyzed using Rock-Eval pyrolysis, stable carbon isotopes, vitrinite reflectance, and biomarkers, as well as 1D basin modeling. This study aims to evaluate source input, depositional environment, burial history and potential for hydrocarbon generation of the Upper Cretaceous organic-rich deposits in Jordan. The Upper Cretaceous samples exhibit variable source rock potential. Maastrichtian samples are very good, primarily oil-prone, while Campanian and Cenomanian samples range from fair to poor, with Turonian samples showing good petroleum generation potential. Thermal maturity analysis of Cretaceous samples reveals higher maturity in Turonian and Cenomanian samples compared to the thermally immature Maastrichtian and Campanian samples based on the maximum temperature of pyrolytic hydrocarbons generation, vitrinite reflectance, production index and biomarker indicators. The molecular fossils data suggest that the organic matter of these source rocks was primarily of marine phytoplankton origin, with considerable contributions from microbial biomass, and deposited under oxygen-depleted bottom water conditions. Additionally, the resemblance in molecular composition between Cretaceous source rocks and crude oil samples suggests a common origin for the hydrocarbons. The highest contents of organic matter have been recorded at the top of the Maastrichtian and at the bottom of the Turonian sections. These findings correspond with Maastrichtian upwelling deposits in North Africa and the Middle East, as well as with deposits from the Cenomanian-Turonian Oceanic Anoxic Event (OAE2).

Hydrocarbon migration and accumulation in buried hills based on quantitative fluorescence techniques, fluid inclusion, and 1D basin modeling: Shulu sag, Bohai Bay basin, NE China

Interpreting the hydrocarbon generation, migration, and accumulation process is significant for understanding hydrocarbon evolution and finding exploration targets. The buried hills of Shulu Sag exhibit great potential for hydrocarbon exploration. However, the variations observed in different oil reservoirs highlight the complexity of hydrocarbon migration and accumulation in this region. In this study, 1D basin modeling, fluid inclusion analysis, and quantitative fluorescence techniques were used to investigate the thermal maturation history of the source rock, the timing of hydrocarbon charging, the pathway of hydrocarbon migration, and the oil-water contact. Hydrocarbons in the buried hills in the Western Slope and Paleo-uplift are derived from the source rocks at the edge and center of the sag, respectively, which have different thermal maturation histories. The source rocks in the center of the sag mainly supply hydrocarbons to the Paleo-uplift through faults, while the hydrocarbons generated from the source rocks in the edge of the sag can be rapidly transported to the Western Slope through clast-supported terrigenous carbonate rudstone. Differences in oil sources result in different hydrocarbon charging histories for the Western Slope and Paleo-uplift. The Western Slope experienced a single low-mature oil charging event at 5-0 Ma, while the Paleo-uplift encountered two hydrocarbon charging events, including low-mature oil charging at 35-25 Ma and high-mature oil charging at 5-0 Ma. As a result of secondary changes controlled by the hydrological environment, the oil reservoirs in the Western Slope have undergone varying degrees of adjustment or even destruction, resulting in variations in the oil quality of different buried hills. The results provide a detailed understanding of hydrocarbon migration and accumulation in the study area, which can be used as a reference for hydrocarbon exploration.

Source Rock Assessment of the Permian to Jurassic Strata in the Northern Highlands, Northwestern Jordan: Insights from Organic Geochemistry and 1D Basin Modeling

The present study focused on the Permian to Jurassic sequence in the Northern Highlands area, NW Jordan. The Permian to Jurassic sequence in this area is thick and deeply buried, consisting mainly of carbonate intercalated with clastic shale. This study integrated various datasets, including total organic carbon (TOC, wt%), Rock-Eval pyrolysis, visual kerogen examination, gross composition, lipid biomarkers, vitrinite reflectance (VRo%), and bottom-hole temperature measurements. The main aim was to investigate the source rock characteristics of these strata regarding organic richness, kerogen type, depositional setting, thermal maturity, and hydrocarbon generation timing. The Permian strata are poor to fair source rocks, primarily containing kerogen type (KT) III. They are immature in the AJ-1 well and over-mature in the NH-2 well. The Upper Triassic strata are poor source rocks in the NH-1 well and fair to marginally good source rocks in the NH-2 well, containing highly mature terrestrial KT III. These strata are immature to early mature in the AJ-1 well and at the peak oil window stage in the NH-2 well. The Jurassic strata are poor source rocks, dominated by KT III and KT II-III. They are immature to early mature in the AJ-1 well and have reached the oil window in the NH-2 well. Biomarker-related ratios indicate that the Upper Triassic oils and Jurassic samples are source rocks that received mainly terrestrial organic input accumulated in shallow marine environments under highly reducing conditions. These strata are composed mostly of clay-rich lithologies with evidence of deposition in hypersaline and/or stratified water columns. 1D basin models revealed that the Upper Triassic strata reached the peak oil window from the Early Cretaceous (~80 Ma) to the present day in the NH-1 well and from ~130 Ma (Early Cretaceous) to ~90 Ma (Late Cretaceous) in the NH-2 well, with the late stage of hydrocarbon generation continuing from ~90 Ma to the present time. The present-day transformation ratio equals 77% in the Upper Triassic source rocks, suggesting that these rocks have expelled substantial volumes of hydrocarbons in the NH-2 well. To achieve future successful hydrocarbon discoveries in NW Jordan, accurate seismic studies and further geochemical analyses are recommended to precisely define the migration pathways.

Petroleum system assessment of the Beni Suef Basin, Western Desert, Egypt

Within the northwestern Desert of Egypt, the Beni Suef Basin is one of the most significant hydrocarbon basins. After over 50 years of exploration and production, the main challenge today is to locate new areas that are prolific to oil and gas production. The study aims to identify potential drilling locations by integrating geochemical methods, 1D and 2D basin modelling, well log analysis, seismic interpretation, and hydrocarbon migration pathways. Results show that the Lower Kharita shale contain both oil and gas generating kerogen with generating potential that ranges from fair to very good. The source rocks within the Lower Kharita are mature (main oil window) and have a transformation ratio of up to 60% based on 1D basin modeling. The modelled 2D vitrinite reflectance map showed that hydrocarbon generation occurred at depths greater than 10850 ft (3306 m) with vitrinite reflectance values greater than 0.65% in both the northern and southern parts of the Beni Suef Field. Two main reservoirs were studied. The lower Bahariya and upper Kharita reservoirs are composed of well to moderately sorted sandstone. The subsurface structural maps, reservoirs, source, and charge modeling maps have been constructed to show the migration pathways and accumulation areas. There are three accumulation areas identified. The first accumulation area is located in the high structure up-dip section of the major normal fault, and migration direction is from northwest. The second and third accumulation areas are located in the low structure and down-dip from the normal fault, with migration of hydrocarbons from southeast. The latter two areas should be tested by drilling in the future.

Petroleum system analysis of the komombo basin, southern Egypt: Insights from basin modeling and hydrocarbon geochemistry

Komombo Basin is the only hydrocarbon-producing basin in southern Egypt. However, its petroleum system is still poorly understood, leaving numerous geological questions unanswered. This study integrates seismic, borehole, and geochemical data, coupled with 1D and 2D basin models, to evaluate the hydrocarbon potential and analyze the petroleum system within the Komombo Basin. Geochemical data reveal four main source rocks: the B member of Six Hills, upper Maghrabi, Quseir, and Dakhla. The B member is interpreted as a very good source rock, characterized by Kerogen type II to II/III. The upper Maghrabi and Quseir are considered good to very good source rocks with organic matter type III and II/III, respectively. Conversely, the Dakhla Formation is recognized as a source rock of good to excellent quality with a mixed kerogen type of II/III. Temperature models highlight two heat anomalies during the Early and Late Cretaceous, aligning with the identified rift phases in the basin. The present-day thermal maturity model indicates that the B member is the only mature source rock that has entered the main oil window. However, in the deepest part of the basin, it reaches the gas window. Although the hydrocarbon generation from the B member began in the Early Turonian, most of the kerogen transformed into hydrocarbons during the middle Santonian-early Maastrichtian. Three migration scenarios were tested, however, the first scenario with the invasion percolation migration method aligns more with known hydrocarbon accumulations in the basin. The predicted accumulation zones are found within several sand units, including the A member, C member, sandy intervals within D-G members of Six Hills, and Sabaya-Maghrabi reservoirs. These zones are predominantly situated within structural traps. Comparative analysis using gas chromatograms between recovered oils from the reservoirs and an extracted bitumen sample from the B member source rock reveals a strong correlation among them.

Session 19. Oral Presentation for: Beetaloo gas, hydrogen and geothermal resources – insights from 3D basin modelling

Session 19. Oral Presentation for: Beetaloo gas, hydrogen and geothermal resources – insights from 3D basin modelling

Crustal Structure, Deformational History, and Tectonic Origin of the Bahamas Carbonate Platform

AbstractThe 2–10‐km‐thick, mainly carbonate cap of the 14,000 km2 Bahamas carbonate platform (BCP) has impeded imaging of its underlying crustal structure. The deeper structure of the BCP records both its Mesozoic rift and hotspot history and its later deformation related to its Paleogene collision with the Great Arc of the Caribbean (GAC). We use regional gravity data to model the crustal structure, type, and deformational processes of the BCP by: (a) integrating publicly available seismic data; (b) inverting the Moho along 2D regional gravity transects across the collisional zone; (c) modeling flexural uplift of a forebulge that reflects the attempted subduction of the BCP beneath the GAC; and (d) using downhole temperatures and radiogenic heat production in 1D basin models to differentiate crustal types related to the Mesozoic rift history. We interpret three crustal domains underlying the BCP: (a) 27–12‐km‐thick, rifted, and thinned continental crust of the northern Bahamas between the Blake Plateau and Exuma Sound; (b) 24–12‐km‐thick, volcanically‐thickened oceanic crust related to the Triassic‐Jurassic Bahamas hotspot in the central Bahamas southeast of Long Island; and (c) 20–12‐km‐thick, thickened oceanic crust north of Hispaniola. We propose that these crustal types reflect northwest‐southeastward, Triassic‐Jurassic rifting of the Bahamas region during the breakup of Pangea and accompanying magmatic activity related to the Triassic‐Jurassic Bahamas hotspot and early oceanic spreading. Growth of the BCP during the Cretaceous in this area was followed by Late Cretaceous‐Paleogene subduction‐related flexure and terminal Paleogene collision between the GAC and the BCP.

Geochemical evaluation and basin modelling of the Cretaceous succession in the Azhar Oil field, West Beni Suef Basin, Egypt

Geochemical analysis was performed on the Cretaceous sequence of the Azhar‐A‐2 well in the West Beni Suef Basin (WBSB), Western Desert, Egypt, utilizing data on total organic carbon (TOC), kerogen composition, vitrinite reflectance (Ro%) and Rock‐Eval pyrolysis. In addition, a 1D basin model was built to investigate the burial and temperature history of the study area. The most important Cretaceous source rocks are predominantly reported within the Albian Kharita Formation and Late Cenomanian‐Santonian Abu Roash (AR) Formation. Based on visual kerogen tests and Rock‐Eval pyrolysis, AR Formation (A, E, F, and G) are mixed oil‐ and gas‐prone source rocks with kerogens ranging from type II to type III, where A/R ‘A and F’ Members show dominant oil‐prone kerogen with the highest generative potential, while A/R ‘E and G’ Members are more gas‐prone kerogen. Most samples of the lower Kh Formation were interpreted as gas‐prone kerogen type III with low generative potential. On the other hand, the high amount of liptinite in the visual kerogen macerals is a strong indicator that the lower Petroleum Formation is an oil‐prone rather than gas‐prone source rock. The thermal maturity of the studied members increases consistently with depth, ranging from immature at the top of the AR Formation to the main/peak oil window at the base of the Lower Kharita Formation, which served as an active source rock for the hydrocarbons generated in the WBSB. The high value of the heat flow in the Beni Suef Basin (57 and 60 mW/m2) is a good indicator for the shallowing of the active source rock depth limit depth. From the study of the basin modeling, the main mature zone reached between 9811 and 11,090 ft in the middle of the Late Cretaceous (84.3–82.5 Ma) is through the L. Kharita Formation with three phases of hydrocarbon generation according to transformation ratio, where the second phase is the main stage in which TR is 5%–50%, showing the beginning of oil expulsion (Ro: 0.73%–0.78%, possibly 0.81%).

Beetaloo gas, hydrogen and geothermal resources – insights from 3D basin modelling

The Beetaloo Sub-basin hosts a large proven shale gas resource, and this study demonstrates the opportunities for other low-emission energy sources including geothermal energy and natural hydrogen. CSIRO has developed a 3D basin model that predicts reservoir rock properties, pore pressure, composition of hydrocarbons and gas capacity of the Velkerri and Kyalla shales. Kinetic modelling also demonstrates that where Velkerri shale is overmature for hydrocarbons it potentially generated significant amounts of free molecular hydrogen. However, the proportion of this hydrogen currently preserved in the basin is unknown. The model also reveals considerable temperature anomalies around specific structural domains with heat flow up to 100 mW/m−2, and these are likely associated with radiogenic basement lithologies. These thermal domains are targets to further investigate geothermal and natural hydrogen resource potential in the Beetaloo Sub-basin.

Building a carbon dioxide storage portfolio for the Barrow-Dampier sub-basins through regional screening – an integrated geoscience approach

Safe geological carbon dioxide (CO2) storage (GCS) requires rocks with suitable injectivity, capacity and sealing properties to ensure secure long-term containment of injected CO2. A regional understanding of the subsurface is essential to determine the potential for GCS of a basin and to select target sites. This is best addressed by integrating the basin’s tectono-stratigraphic evolution, its gross depositional environment, and its hydrodynamic, thermal and stress regimes. A basin-scale GCS assessment for the Barrow-Dampier sub-basins was conducted by Geoscience Australia and SLB. The objective of the study is to high-grade geological intervals and sites for potential GCS and to understand potential storage capacity and key risk factors. Stratigraphic and structural mapping of key storage intervals was performed using the reprocessed seismic volume and well database associated with the project. Analysis of critically stressed faults was used to estimate the likelihood of reactivation based on the far-field regional stress field and fault mechanical properties. Pressure, temperature, porosity, permeability, and water geochemistry data have been screened for >500 wells for assessing the storage unit intervals and predicting the hydrodynamic regime. Calibrated 2D basin models provide information on the regional pressure-temperature regime, porosity/permeability distribution, and sealing effectiveness. Potentiometric surface maps for the aquifer systems inform the distribution of potential CO2 plume migration. Results of this integrated regional basin study are used to quantify the risk of identified storage containers and to map the chance of success for GCS at a regional scale. The project results are publicly available via NOPIMS.

Diagenesis and pressure evolution in Ediacaran carbonate rocks in the North Slope (Penglai area) of the central Sichuan Basin (SW China)

The Penglai area is an emerging giant gas field in the Sichuan Basin supporting the carbon neutrality goal. To accelerate the exploration, this study combines petrographic observations using optical and cold cathodoluminescence microscopy, fluid inclusion microthermometry, Raman spectroscopy, 1D basin modeling and fluid inclusion PVTX modeling techniques to reveal the paleo-fluid P-T evolution in the second member of the Dengying Formation (Ediacaran age). The results firstly showed a diagenetic sequence which includes three phases of dolomite (1–3), bitumen, quartz (core and overgrowth) and fluorite. Then, ten paleo-fluid episodes were identified based on microthermometric histograms of different mineral phases. Finally, by integrating the Raman results, the hydrostatic and lithostatic gradients calculated by the constructed 1D basin model, and the existing equation of states, the homogenization pressure of fluid inclusions from each fluid episode was determined. By assuming the system was saturated by CH4 as suggested by Raman results, the homogenization pressure equals to the trapping pressure. The P-T trajectory indicates that the second member of the Dengying Formation experienced two sever pressure accumulation stages. One is between fluid episode #3 and #4 recorded by dolomite 3, due to oil generation, and the other is from fluid episode #5 in dolomite 3 to episode #7 in quartz overgrowth to episode #8 in fluorite due to oil cracking to gas. Also, two pressure releasing periods were recorded by fluid episode #5 in dolomite 3 and #9 and #10 in fluorite, caused by both basin uplifting and fluid pressure reaching the lithostatic pressure. This study provides insights into fluid pressure evolution in deeply buried carbonate reservoirs. The understandings can support further geoenergy utilization and reduce exploration risks.

Prediction of hydrocarbon accumulations using 2D basin and petroleum system modeling: Case studies from Abu Zenima and October fields in the Gulf of Suez, Egypt

This work aims to elucidate the potential applications of 2D basin and petroleum system modeling (BPSM) software in the assessment of hydrocarbon accumulations. To demonstrate how much information can be inferred regarding the existence of hydrocarbons and their mechanisms of accumulation in the subsurface, 2D BPSM was applied to two seismic sections that were utilized as case studies. The faults and horizons were digitally represented throughout the modeling phase to create the 2D BPSM for both seismic sections. The 2D BPSM construction used the age and lithology of each layer of the model as inputs. The hybrid technique was used to simulate hydrocarbon migration paths. The simulation findings showed that when the depth decreases, the degree of maturity declines, as some parts are characterized by transformation ratios of up to 100%. For the Upper Cretaceous source rock in model ABZ88-18, the levels of vitrinite reflectance (Ro%) are in the maturity phase and provide oil with Ro% values ranging from 0.6% to 1.3%. Whereas, in model 370, the Ro% values range from 0.55% to 1.3%. Based on the results of the modeling, new prospective hydrocarbon accumulations were found. Model ABZ88-18's estimated total mass is 292.9 million bbl oil and 11.49 million m3 gas, compared to model 370's estimated total mass of 178.52 million bbl oil.

Geochemistry of Liquid Hydrocarbons and Natural Gases Combined with 1D Basin Modeling of the Oligocene Shale Source Rock System in the Offshore Nile Delta, Egypt.

The current study aims to integrate the geochemical characteristics of the Oligocene shale source rock system, oil, condensate, and natural gas samples in the Oligocene sandstone reservoirs from three exploration wells located in the offshore Nile Delta, East Mediterranean Sea, using organic geochemistry and a 1D basin modeling scheme. The Tineh shales exhibit total organic carbon values ranging between 0.90 and 1.89 wt %, along with hydrogen index values in the range of 54-240 mg hydrocarbon/g rock. The geochemical characterization suggests that the shale intervals of the Oligocene Tineh Formation contain type II-III and type III kerogens and, thereby, could be regarded as promising oil- and gas-prone source rocks with high contributions of gas generation potential. The study also reconstructs the 1D thermal and burial history models, showing that the Oligocene Tineh source rock system is in the main oil and wet gas generation phases from the late Miocene to the present time. The simulated basin models reveal the transformation (TR) of 10-50% kerogen to oil during the late Miocene-early Pliocene period and that the Oligocene Tineh source rock system has larger oil generation and expulsion competency, with a TR value of up to 65% during the early Pliocene-Pleistocene time period. The thermogenic gas was also formed during this time and continued to the present day. This study also investigated the presence of oil and condensate in the Oligocene sandstone reservoir samples and revealed that they were generated from mature source rock, ranging from moderately to highly mature stages. This source rock unit was deposited in fluvial to fluvial-deltaic environments under oxic mixed organic conditions and accumulated during the Tertiary time, as evidenced by the presence of the oleanane biomarker dating indicator. The molecular and isotope compositions of natural gases revealed that most of the natural gases in the Oligocene sandstone reservoir are mainly thermogenic methane gases that were generated from mainly mixed organic matter. The thermogenic methane gases were formed mainly from secondary cracking of oil and gas, with small contributions of primary kerogen cracking. The properties of natural gases together with oil and condensate in the Oligocene reservoir rocks suggest that most of the thermogenic methane gases and associated liquid hydrocarbons are derived primarily from the Oligocene shale source rock system and formed by primary kerogen cracking and secondary oil and oil/gas cracking in different thermal maturity stages. Therefore, the Oligocene Tineh Formation can be regarded as self-source generation and self-reservoir rock; hence, an intensive oil exploration and production program can be recommended whenever the Tineh source rock system is is well developed and deeply buried.

Basin analysis study of block 53 in the Masilla Basin, Yemen, using a 1D-backstripping method

Basin study of 1D-backstrripping analysis was performed on the sediments in in the four exploration wells (Bayoot S1, Bayoot Sw3, Sharyoof 2, and Sharyoof 9) from Block-53, Masilla Basin. 1D backstripping analysis resulted in many curves of the subsidence of the basement during the deposition of the stratigraphic units. The 1D basin models show that the Masilla basin exhibited a complex subsidence history over a period of about 155 Ma and includes three stages of subsidence. The first stage was occurred at 132-155 Ma and shows high subsidence rate about 6.2 cm per1000 years) and deposition rate about 6.13 cm per 1000 years in the southwest part of Block-53. This stage formed as a result of thinning in the curst during the lithospheric extension. The second stage of subsidence was occurred at 66-128Ma and shows decrease the subsidence rates in the range of 1.99- 1.11 cm/1000 years and deposition rates between 1.19 and 0.69 cm/1000 years during the post-rift deposits, which is represented by Qishn Clastic and Carbonate formations (.At the third stage, the subsidence and deposition rates are high in the southwest of block-53 and found to be about 9.3 cm/1000 years and 9.2 cm/1000 years, respectively . The rapid in the subsidence rates during this stage is primary related to the cooling of lithosphere and loading of the sediments

3D basin modeling of the Hils Syncline, Germany: reconstruction of burial and thermal history and implications for petrophysical properties of potential Mesozoic shale host rocks for nuclear waste storage

AbstractJurassic sedimentary sequences suitable for nuclear waste storage in northern Germany consist of organic-lean claystone and were uplifted to < 100 m depth in the Hils Syncline area (southern Lower Saxony Basin). This Hils Syncline, showcasing a northwestward increase in thermal maturity, facilitates the study of shale petrophysical properties influenced by burial history. This study introduces a 3D-thermally calibrated numerical model of the Hils Syncline area to analyze its geodynamic evolution and maturity variations. It provides new vitrinite reflectance and sonic velocity data for modeling calibration and erosion estimation. The Hils Syncline area has undergone continuous subsidence, interrupted by a Cretaceous uplift documented by an erosional unconformity. During the latest Early Cretaceous, Jurassic rocks underwent maximum burial reaching up to several thousand meters depth and temperatures up to 160 °C in the northwest. The Late Cretaceous inversion caused stronger erosion towards the northwest removing up to 3300 m of sediment compared to about 1300 m in the south, according to vitrinite reflectance-based estimations. Numerical modeling results along the study area indicate decreasing porosity and permeability northwestward with increasing thermal maturity. Porosity and vertical permeability decreased to 5–14% and 2.8 × 10–23 to 1.5 × 10–19 m2 [1 mD = 10−15 m2], respectively, while vertical thermal conductivity increased to 1.30–2.12 (W/m/K). These trends of porosity/permeability and thermal conductivity with burial align with sonic velocity and published experimental porosity data, except for the thermally most mature region (Haddessen). This anomaly is tentatively attributed here to localized overpressure generation in the Posidonia Shale during maximum burial, affecting both the underlying Pliensbachian and overlying Doggerian units. Graphical abstract 3D numerical model of the Hils Syncline and surrounding area revealing that a northwestward increase in maximum burial resulted in higher temperatures and varying maturity levels. While most locations align well with calibration data (i.e. measured vitrinite reflectance and porosity), discrepancies arise in the Haddessen/Bensen area. The mismatch between porosity, vitrinite reflectance, and sonic velocity response indicates local overpressure in the northernmost region mainly during the Cretaceous. It was likely caused by gas generation in the Posidonia Shale affecting nearby Lower and Middle Jurassic units.

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

Geochemical characterization and paleo-burial history modelling of unconventional resources: A case study from the Kimmeridge Clay Formation (KCF) in the UK North Sea

For several decades the UK North Sea has been a prolific oil and gas province, with numerous conventional oil and gas discoveries sourced predominantly by the Upper Jurassic to Lower Cretaceous Kimmeridge Clay Formation (KCF). In this study, we have combined the analysis of total organic carbon/pyrolysis and vitrinite reflectance geochemical data from KCF samples with 1D basin modelling to investigate the potential for shale oil and gas plays in the Outer Moray Firth region. The results of geochemical evaluation show that most of the samples have very good to excellent hydrocarbon generation potential and contain predominantly oil-prone Type-II kerogen. A few samples show a significant oil saturation index above 100 mgHC/gTOC, which indicate a good potential for producible shale oil. The modelling results suggest that vitrinite reflectance values for the KCF vary mainly between 0.51 and 1.15%Ro, with kerogen transformation of up to 86 %. This is indicative of early-oil to late-oil/early-gas maturity window at present day, and within the range reported for proven shale oil plays. The KCF shows good oil saturation in most of the modelled well locations of up to 6.4 mg/g rock, indicating potentially producible shale oil. Predictions from modelling support the interpretations from geochemical data.

Petroleum system of the fold-and-thrust belt of the United Arab Emirates: New insights based on 1D and 2D basin modeling

The hydrocarbon potential of the fold-and-thrust belt (FTB) in the United Arab Emirates (UAE)-Oman mountains has received limited attention to date, leading to a poor understanding of the petroleum systems in this region. Despite the existence of hydrocarbon fields within the FTB, the source rock potential has not been adequately studied. This study aims to address this knowledge gap using 1D and 2D basin modeling approaches to evaluate the petroleum system of the FTB. In addition, gas chromatographs are also used to correlate hydrocarbon occurrences with their source rock. This study's findings identify the Silurian, Upper Cretaceous, Paleocene–Eocene, and Oligocene formations as the primary source rocks in the study area. Silurian shales, encountered in a well in the northern UAE, are currently considered overmature. The Cenozoic source rocks exhibit a spectrum of Total Organic Carbon (TOC) content, ranging from less than 1 to as high as 2 wt%, leading to variable degrees of expulsion efficiency. The maturity of these rocks varies based on their position in relation to the FTB and foredeep, with increasing maturity towards the north. The Upper Cretaceous sequences display low TOC and Hydrogen Index, indicating very low expulsion efficiency. The present-day distribution of maturity is largely influenced by Late Cretaceous and Oligocene–Miocene compressional events that affected the northern and northeastern Arabian Plate. This analysis shows that hydrocarbon expulsion from the Silurian source rocks was initiated during the Middle-Late Jurassic. These hydrocarbons are presumed to have migrated through Upper Permian, Jurassic, and Lower and middle Cretaceous reservoirs. Westward hydrocarbon migration, towards a regional bulge, may have also occurred following compressional events that resulted in lithospheric flexure and formation of the foreland basin. Notably, certain exceptions to migration towards the bulge include structural entrapment of hydrocarbons beneath the main frontal thrust zone of FTB and some structural traps beneath the Lower Fiqa Formation.