3D Basin Modeling Research Articles

The effects of uplift and erosion on the petroleum systems in the southwestern Barents Sea: Insights from seismic data and 2D petroleum systems modelling

In the past three decades, the hydrocarbon prospectivity has been enigmatic in the southwestern Barents Sea as gas discoveries have dominated over oil. However, more recent discoveries indicate oil potential, especially in the Polheim Platform and Hoop Complex areas. Cenozoic uplift and erosion episodes are critical because they control the duration and depth of maximum burial of source rocks and the reduction of porosity of reservoir rocks due to diagenetic processes at larger depth and increased temperatures. Modelling of interpreted horizons from the southwestern Barents Sea provide a best-fit realization of the basin-scale sedimentary filling from the post-rifting in the Jurassic until the Last Glacial Maximum. 2D basin modelling was performed across one regional seismic section crossing the southwestern Barents Sea. For calibration of the 2D model, 1D modelling was performed for a selected number of wells in the region by integrating different estimates of net apparent erosion (velocity inversion of wells, interpreted profiles and structure maps as well as from temperature and vitrinite reflectance data) in order to assess the burial, thermal and maturity history of the source rocks at various well locations as well as along the 2D profile. Simulation results show that the Upper Jurassic source rock is immature to marginal mature in the central and eastern parts of the Norwegian Barents Sea. The western part is characterised by high chargeability of traps associated with rich source kitchens and porous reservoir rocks. Although not proven by commercial discoveries, there are evidences that the Permian Ørret and the Lower-Middle Triassic basal Klappmyss and basal Kobbe shales may be important gas-prone source rocks in the eastern Norwegian Barents Sea. Consequently, the exploration must rely on the Triassic and/or Palaeozoic source rocks in the eastern area.

Fluid history of the lower Cambrian Longwangmiao Formation in the Anyue gas field (Sichuan Basin, SW China)

The Anyue gas field in China is an important source of natural gas supporting the country energy transition to the goal of carbon-neutrality. However, the fluid P–T history, which will provide a better insight into gas accumulation and probable leakage in the main reservoir (the Lower Cambrian Longwangmiao Formation) has still yet to be fully understood. This study combines detailed petrographic observations with transmitted light, ultraviolet light, reflected light and cold cathodoluminescence, fluid inclusion microthermometry, Raman spectrometry, 1D basin modeling and fluid P–T modeling techniques to reconstruct the fluid-involved basin evolution of the Longwangmiao Formation in the Anyue region. The results showed that the paragenesis of the Longwangmiao Formation includes dolomite matrix, dolomite 1, dolomite 2, dolomite 3 (saddle dolomite), dolomite 4, quartz and calcite. The first generation of bitumen occurs between dolomite 1 and dolomite 2, corresponding to the primary oil generation of the Lower Cambrian Qiongzhusi Formation at the burial maximal in the Silurian. The second generation of bitumen, corresponding to intense oil cracking into gas, has occurred between dolomite 4 and quartz at a geological period between the Middle Jurassic and Early Cretaceous (early Yanshanian movement). Fluid inclusions trapping pressure modeling explains that the trapping pressure increases from dolomite 4 to quartz due to burial and the oil cracking into gas, then stays constant from quartz to calcite due to the sealing of fractures. The open fractures formed after calcite partially reduced the overpressure condition of the Longwangmiao Formation. Collectively, this study will provide necessary information for a better understanding of deeply buried reservoirs to support more efficient development of such reservoirs in higher quality zones and reduce exploration risks and operational costs.

Regional source rock thermal stress modeling and map-based charge access modeling of the Port Isabel passive margin foldbelt, northwestern Gulf of Mexico

The Port Isabel passive margin foldbelt covers 17,000 km2 of the northwestern deepwater U.S. Gulf of Mexico. Seven oil exploration wells have been drilled in the area from 1996 to 2007, yielding a single uncommercial gas discovery. The 5–7 km thick Oligo-Miocene section prevents drilling from penetrating the underlying Paleogene and Mesozoic source rocks. Accommodation space for the Oligo-Miocene section is created by the collapse of a paleo-salt wall, leading to linked fault systems in the upper decollement to the east. We use 13 exploration wells to construct 1D and map-based 2D basin models to investigate the burial and thermal history of three inferred source rock horizons (Paleogene, Turonian, and Tithonian). We interpret a 2D seismic data grid tied to four wells to constrain stratigraphic depths and thicknesses of the younger and shallower Wilcox source rock horizons, and the Jurassic and Cretaceous source rock horizons. Our results indicate that vitrinite reflectance is a proxy for the thermal stress levels reached by the source rocks as supported by maps of hydrocarbon charge access. We conclude that all three source rock intervals have reached varying degrees of maturity, expelled hydrocarbons in late Paleogene to mid-Neogene, and likely continue expelling hydrocarbons to the present-day at a reduced rate. The deposition of the Oligocene and Middle Miocene sedimentary section has buried the underlying source intervals and likely brought them into the gas/condensate window in the present-day. Our mapping of the extensive seismic reflection grid reveals four-way structural closures, three-way stratigraphic traps, and salt truncation structures associated with amplitude anomalies which may support our predictions for maturity in the underlying source rocks. Our thermal stress maps predict that the modeled source rocks are mature and our charge access models for the available wells constrain migration patterns, although the timing of the early hydrocarbon charge and late trap formation remain significant risk factors.

The Upper Cretaceous petroleum system of the East Beni Suef Basin, Egypt: an integrated geological and 2D basin modelling approach

We integrated geological and 2D basin modelling to investigate the tectonostratigraphic evolution of the East Beni Suef Basin (EBSB) of north central Egypt and its implications for the Upper Cretaceous petroleum system. Two intersecting seismic sections and three exploration wells were used for this study. The geological model defines the structural and geometrical framework of the basin, which formed the basis for subsequent 2D basin modelling. The developed basin models were calibrated and fine-tuned using vitrinite reflectance and corrected temperature data. Modelling results indicate that the Abu Roash ‘F’ source-rock maturity ranges from the early oil window at the basin margins to the main oil window in the centre. The main phase of hydrocarbon generation occurred during the Eocene after trap formation in the Late Cretaceous. Generated hydrocarbons have migrated both laterally and vertically, most likely from the central part of the basin towards the basin margins, particularly eastwards to the structural traps. The model predicts low accumulation rates for the EBSB, which are caused by the ineffective sealing capacity of the overburden rocks and normal faults. In addition to the proven kitchen for the charging of the Abu Roash ‘E’ reservoirs, an additional kitchen area to the NW of the basin is suggested for the Abu Roash ‘G’ reservoirs.

1D basin modeling and hydrocarbon generation potential of the Late Carboniferous Limburg Group formations, Northwest European Basin, Netherlands

The Carboniferous rock samples of the Limburg Group formations were studied to investigate the source rock characteristics and the hydrocarbon generative potential. The source rock samples have been collected representing four rock units from three different wells. These samples were analyzed using Rock-Eval pyrolysis results and measured vitrinite reflectance values, and also by generating a one-dimensional basin model of K1 Field. The total organic carbon in these samples varies from 0.31 to 83.56% with a mean of 37.68%, suggesting that Limburg Group formations have excellent potential as a source of hydrocarbons. Kerogen in the Limburg Group formations is type II-III and type III, generate gas prominently. The outcomes of thermal maturation by Tmax and measured vitrinite reflectance reveal that the examined Limburg source rocks are located in the mature zone. The burial and thermal history models show irregular trend patterns due to uplift, erosion, and non-deposition events that took place in the K1 field (where the structural element is Cleaver Bank High). For the Maurits Formation, the oil generation took place at 2011 m at 230.1Ma ago and the top of the gas window was encountered 217.8Ma ago at 2535 m, whereas for the Hospital Ground Formation, the top of the oil window was encountered 186.8Ma ago at 2404 m and the gas generation took place at 2404 m at 161.9Ma ago.

Machine learning-supported seismic stratigraphy of the Paleozoic Nubia Formation (SW Gulf of Suez-rift): Implications for paleoenvironment−petroleum geology of a lacustrine-fan delta

-Steeply dipping prograding fan deltas possess high reservoir quality facies that could be excellent targets while exploring for hydrocarbons. Due to their complex stacking nature, and limited examples, delineating their architectural elements is still challenging. In this paper we mainly performed sedimentary facies analysis; applying various disciplines e.g. sequence stratigraphy, seismic stratigraphy, GR-log motifs, and seismic waveform segmentation; so as to adequately depict the reservoir heterogeneity and quality of the Paleozoic Nubia clastics in West Esh El Mallaha Concession (southwest Gulf of Suez rift). Organic maturity prediction, to confirm the hydrocarbon charging from source units to reservoir intervals, was also of most importance in this study. Accordingly, 1D basin model was established to define the past geologic events; subsidence, and thermal maturity; and their controls on sedimentary basin evolution and associated petroleum potential. We utilized several key-information scales; e.g. wireline logs, and seismic profiles. Linking different disciplines applied in this study points to a successful integrated reservoir characterization workflow capable of unfolding ancient environments and the associated hydrocarbon potential. The results show that Nubia Formation was built during the lowstand−transgressive phase of a 3rd order depositional sequence. It encompasses fluvio-lacustrine system with eight sedimentary facies associations; form source to sink. Fluvial channels and mouth bars, settled in subaerial and subaqueous settings respectively, represent the most significant reservoir facies in the area. Given best hydrocarbon-reservoir quality, the deltaic mouth bars ought to attract attention of further oilfield development plans and be considered while investigating similar settings. • Integrated facies analysis, and established depositional model, depicting reservoir architectural elements; heterogeneity. • TOC calculations and 1D-basin modeling confirming hydrocarbon charging from source-prone intervals to reservoir zones. • Lacustrine deltaic mouth bars representing best reservoir facies ought to be tested and considered in similar settings. • Combined facies analysis and basin modeling devoting to robust insight into environments and associated petroleum potential.

Oligocene source-rock characteristics and hydrocarbon generation modeling of the eastern Nile delta, Egypt

This study investigates Oligocene source rock development in the eastern Nile Delta, integrating TOC, Rock-Eval pyrolysis, as well as vitrinite reflectance (Ro%) measurements from over 9 onshore and offshore wells. 1D basin models, constructed for 2 wells onshore and 2 wells offshore, investigate the burial, thermal histories, and the stage and timing of hydrocarbon generation. The present-day data indicate that the Oligocene section encompasses Type III and rarely Type IV kerogen onshore, whereas offshore Type III and Type II-III kerogen dominate. The back-calculated original TOCo and HIo values indicate a significant hydrocarbon generation (i.e. effective to relic source rock) for Rupelian section in Tayifah Deep-1x and Satis-1 wells. The different maturity indicators used here show significant differences in some intervals. The variability may be attributed to natural impregnation of migrated hydrocarbon in permeable strata, in-situ expelled hydrocarbons where S2 contamination is rather likely for samples within the oil window, or retarded Ro% and/or Tmax caused by overpressure. Therefore, thermal and generation models are calibrated with measured bottomhole temperatures, which match quite well with δ13C values of gases C1-3, and indicate that the onshore Oligocene basal section comes in the early stage of hydrocarbon generation throughout the middle-late Miocene, and was in the main stage of hydrocarbon generation since the early Pliocene. The transformation ratio indicates an in-situ expulsion (25–50%) since the Pleistocene time. Offshore models indicate the basal Oligocene section entered the late phase of hydrocarbon generation during the early to middle-late Miocene, where its transformation ratio exceeds 50%. This indicates the main hydrocarbon expulsion from the late Oligocene to the early-middle Miocene time. Further integrated approaches to the Oligocene geochemical analysis after solvent extraction are vastly required. Higher resolution overpressure and maturity indices (Tmax and Ro) profiles for some deep sections are essential to strengthen concepts about the mechanism(s) and magnitude of their retardation/suppression.

Preparation techniques for microscopic observation of dispersed organic matter and their effect on vitrinite reflectance

Microscopic petrographic analysis of fine-grained sediments requires standardised, high-quality preparation of polished sections, generally conducted by water-involved grinding and polishing techniques following respective norms (ISO 7404-2, 2009; ASTM, 2021). However, vitrinite reflectance results show significant variations between different laboratories, partly caused by inconsistencies in sample preparation or poor sample preparation, e.g. due to the effect of swelling clays. This study evaluates the effect of alternative preparation techniques on the reliability and consistency of vitrinite reflectance data measured on shales containing dispersed organic matter (kerogen type III) using (1) an oil-based lubricant for traditional grinding and polishing and (2) BIB (broad-ion-beam) polishing. Different preparation techniques were applied on ten samples from two well sections (Hervest 5 and Prosper-Haniel) from the Ruhr Basin (Germany), covering the coal-bearing Pennsylvanian sedimentary successions of the Westphalian B and C with a maturity range of 0.56 to 0.78% and 0.73 to 0.92% vitrinite reflectance, followed by vitrinite reflectance measurements.Preparation under the use of oil-based lubricant led to similar reflectance values compared to traditional water-based grinding and polishing. Oil-based treatment improved the quality of two samples having the lowest thermal maturities, as indicated by increased vitrinite reflectance values by up to 0.1%. After BIB polishing, vitrinite reflectance systematically increased by up to 0.25% (relative increase of +29%), with the highest BIB-induced reflectance increase observed at a thermal maturity of 0.86% vitrinite reflectance (before BIB polishing). A practical geological approach was tested by calibrating 1D basin models using post-BIB vitrinite reflectance values. The data reveal a systematic trend in vitrinite reflectance between pre- and post-BIB polishing, suggesting that BIB-polishing might has future potential to be established as a routine for sample preparation for microscopic observation of organic material.

3D basin and petroleum system modelling of the early cretaceous play in the NW Persian Gulf

Petroleum systems analysis has become a key part of hydrocarbon resource exploration. Early Cretaceous petroleum system in the northwest of the Persian Gulf basin with prolific source rocks and reservoirs, is the main petroleum system in the region. Most Iranian offshore oils have been stored in this geological interval. Recent studies indicate that finding new resources is still possible. Therefore, for the first time, this study applied a 3D petroleum system modeling approach to predict new prospects based on available seismic and well data in ∼30,000 km2 area. Results showed that the Berriasian Garau, Albian Kazhdumi and Barremian upper Gadvan are the dominant source rocks. Most of the hydrocarbons have originated from the two Binak and Northern troughs as oil kitchens in the northern and northwest areas. Most anticlines formed in the Late Cretaceous before the critical moment of the source rocks. At first, traps adjacent to the Binak and Northern troughs oil kitchens were charged. Then, hydrocarbon migrated laterally to the far structures. The activity of normal faults has played an important role in vertical migration and reservoir oil mixing, especially in oilfields located above the Khafji-Norooz Arch. Albian Burgan sandstone distribution map from process-based forward stratigraphic modeling suggests low probability of stratigraphic traps. Nonetheless, the Burgan anticline reservoirs have the highest oil in place because they have broad drainage area. Finally, three new anticlinal traps with significant oil reserves were identified in the Yamama, Burgan, and Khalij formations in the northwest of the study area. Results of this study help to better understand Early Cretaceous petroleum system performance and identify new hydrocarbon prospects in the study area.

Neogene subsidence rates of the southern Peri Pannonian realm (1D basin modeling): Constraints on the extensional geodynamic drivers of the asymmetric Toplica basin (central-southern Serbia)

With the objective to quantify the Neogene extensional geodynamic drivers of the Peri Pannonian Realm s.l., a series of 1D basin models were carried out by integrating the available geological and geochemical data extracted from the landlocked Toplica Basin (central-southern Serbia; Serbo-Macedonian Unit). The modeling was conducted on four wells located immediately south of Jastrebac Mt., in the area of the Toplica Basin. The investigated southernmost point of the Peri Pannonian Ream s.l. (areas surrounding the basin, to the south of rivers Danube and Sava) underwent intense tectonically-driven subsidence episodes, which lasted from the Lower Miocene up to the Pliocene. The restored Neogene burial history (subsidence rates), paleotemperature, and calibrated paleo-heat fluxes (or changes in the ancient crustal or basal heat flow) indicated a two-staged crustal stretching of the wider Toplica area. The combined tectonic, i.e., thermal subsidence, resulted in a very high sedimentation rate, having an average ca. 300–400 m/Ma (Čučale unit). The intense tectonically-driven subsidence is consistent with the involvement of extensional processes, affecting the crustal and lithospheric layers of the retreating Adria/Dinarides, amplified by a distant Carpathian rollback stage. The regional extension led to the asymmetric opening and the formation of the Toplica Lower Miocene mesosaline to the freshwater lacustrine system. Higher participation of mixed microbiologically reworked/terrestrial organic matter incorporated in oil-prone Type II kerogen mainly characterized the investigated lacustrine sedimentary sequence. The latest Oligocene–earliest Neogene subsidence onset was characterized by elevated temperatures, affecting the early development of the oil window (ca. at 16 Ma). The 1D models also showed that the Lower Čučale unit achieved ca. 50% transformation ratio for the Type II organic matter. The two intra-Neogene extensional episodes suggested the existence of the Early Neogene “syn-rift” stage, followed by a thermal sagging. The Neogene continuous thinning of the overriding Serbo-Macedonian continental crust contributed to the “negative inversion” of the former pre-Neogene nappes. Therefore, Neogene tectonic reactivation induced contemporaneous subsidence, further allowing the extensional rise of the Jastrebac core complex.

Organic geochemical signals of Paleozoic rocks in the southern Tethys, Siwa basin, Egypt: Implications for source rock characterization and petroleum system

Paleozoic sedimentary succession research is valuable for better understanding the global petroleum province and future hydrocarbon reserves. Paleozoic rocks are the prime source of the enormous hydrocarbon fields in North Africa. Despite the Western Desert of Egypt being part of the North African Platforms and having similar depositional, tectonic, and diagenetic constraints, the hydrocarbon system for Paleozoic rocks in the Siwa Basin is indeed not characterized. Forty-five Paleozoic samples were collected from the Siwa Basin to evaluate the source rock characteristics using Rock-Eval pyrolysis, vitrinite reflectance, stable carbon isotopes, biomarkers, headspace gas, and palynofacies analyses. Additionally, the burial and thermal histories of these rocks were investigated by 1D basin modeling. The Paleozoic succession is represented by the Silurian (Basur Formation), Devonian (Zeitoun and Desouqy formations), and Carboniferous (Dhiffah Formation). The routine bulk geochemical analysis of the studied samples indicates poor to good source rock potential. The studied samples contain mostly kerogen type III with some kerogen type II, whereas the Carboniferous samples contain mostly kerogen type IV. The organic matter of the Devonian samples is suggested to have originated from marine and terrigenous sources, with a dominant upward terrigenous source. The lower part of the Devonian is deposited in more reduced marine conditions than the upper part. The organic matter is found to be mature, as indicated by Rr%, Tmax, and biomarker data. The composition of collected headspace gases in Paleozoic rocks suggests their thermogenic origin. Moreover, the similarity of the molecular composition between Paleozoic source rocks and crude oil in reservoir rocks supports the same hydrocarbon sources. Accordingly, the petroleum system in the Siwa Basin is based on active Paleozoic source rocks that charge and accumulate hydrocarbons in the sand reservoirs of the Desouqy Formation. The Paleozoic section entered the oil window in the Early Cretaceous (∼101 myr) based on its burial history. Thus, this study gives improved insights into the petroleum system in the Siwa Basin. Additionally, the Siwa Basin's lesser thickness and burial depth in comparison to other North African basins most likely contributed to its poor petroleum potential.

Source rock characteristics and 1D basin modeling of the lower Cretaceous Latrobe Group, Gippsland Basin, Australia

The aim of this study is to perform source rock characterization of the Lower Cretaceous Latrobe Group's formations in the Gippsland Basin. A total of 138 source rock samples with coal and shale lithologies were selected from three formations represented by Chimaera, Curlip and Kipper Shale formations. The geochemical analyses consisting Rock-Eval pyrolysis, total organic carbon (TOC), vitrinite reflectance (% VR), maceral composition, and biomarkers were used for source rock characterization of the studied formations. It can be interpreted that the formations have poor to very good TOC (average of 2.32 wt %) indicating good organic abundance, while the coal samples from Chimaera Formation have higher organic abundance with excellent TOC (average of 45.25 wt %). These indicate good hydrocarbon generative potential. The formations mostly generate type II/III (mixed) to type III (gas prone) kerogens. Maturity parameters including production index (PI), temperature of maximum pyrolysis (Tmax), % VR and carbon preference index (CPI) indicated that the source rocks are immature to late mature (oil to oil/gas windows). Paleodepositional environment of source rocks is evaluated with biomarker data – normal alkane distribution, pristane/phytane (Pr/Ph) and isoprenoid/normal-alkane ratios. The results show that the source rocks are dominantly terrestrial, deposited in oxic setting. The rock samples did not show any sign of hydrocarbon migration, but experienced biodegradation. However, biomarker analyses were only done on the Chimaera Formation and the results do not represent the whole source rocks in this study. 1D basin modeling was done for Kipper wells. The results show that in Kipper-1, the oil and gas generations started in Kipper Shale at depths 1900 m about 24 Ma, and 2510 m about 15.4 Ma, respectively. In Kipper-2, oil and gas generations started in Chimaera Formation at depths 2540 m about 8 Ma, and 2580 m about 2.5 Ma, respectively. Transformation ratio (TR) plots show that the oil and gas generations have not reached the peak. Petroleum system event (PSE) chart suggested that the main hydrocarbon generation of the Latrobe Group started 26 Ma and is simultaneously being preserved in the Gippsland Basin. This study hopes to give insight of the burial history concept, hydrocarbon generation, and give support in the development of the hydrocarbon fields in the Gippsland Basin.

Petroleum system analysis-conjoined 3D-static reservoir modeling in a 3-way and 4-way dip closure setting: Insights into petroleum geology of fluvio-marine deposits at BED-2 Field (Western Desert, Egypt)

Imperfect determination of petroleum system processes coincidence, entrapment and charge timing, along with reservoir heterogeneity can considerably cause high risks throughout exploration and development phases of petroleum. Therefore, a complete subsurface visualization of the petroleum system nature, elements and processes, is badly required. To this end, we corroborated, in this study, static reservoir modeling with petroleum system analysis workflows, to better characterize the Cenomanian fluvio-marine reservoir, sandstones of Bahariya Formation, at Bed-2 Field, Abu Gharadig basin (Western Desert, Egypt). We used dataset of 2D seismic profiles and well logs of eight wells. The geometry and property of the reservoir were acquired performing static reservoir geocellular modeling approach. The geohistory, timing of charge, migration pathways, and accumulation sites were identified performing 1D and 2D basin modeling approaches. Combining both approaches was aimed at identifying new petroleum prospect areas, and estimating the hydrocarbon volumes, that are the need for such poorly-defined petroleum systems area. As indicated by the constructed, robust, reservoir and 1D-2D basin models, an additional hydrocarbon prospect, to the north central part of Bed-2 Field, is proposed to be drilled during the further oilfield development phases of the area. This prospect has all features that adequately lead to reliable inferences regarding the ultimate petroleum potential of the area. • Reservoir modeling delineating geometry and property, with depositional facies analysis unlocking reservoir heterogeneity • Petroleum system analysis workflow defining the hydrocarbon charge timing, confirming the hydrocarbon potential of the area • Pixel-based stochastic simulation algorithms modeling the rock property. • Hydrocarbon volumes assessment, gas initially in place (GIIP) and stock-tank oil initially in place (STOIIP), in the area • Defining new prospect areas, justifying future oilfield development plans

Geochemical characteristics of inclusion oils and charge history in the Fushan Sag, Beibuwan Basin, South China Sea

The Fluid Inclusion (FI) petrology and biomarker analysis of the inclusion oils were carried out on three sandstone samples from the Liushagang Formation (Els) reservoirs in the Fushan Sag, the Beibuwan Basin, South China Sea. The purpose of this study is to identify the origin of the inclusion oils and understand the charging history and oil accumulation process in the Els reservoirs through the inclusion oil-source correlation, analysis of Homogenization Temperature (Th) and 1D basin modelling. The results show that the maturities of the Els22 inclusion oils are higher than that of the Els1 inclusion oil based on methylphenanthrene index and the inclusion oils were originated from fluvial/delta mudstone. The geochemical correlation between the inclusion oils and source rocks based on the biomarkers clearly shows that the inclusion oils from the Els22 sandstone reservoirs may have sourced from Els22 source rock or mixed source from the Els3 and Els22 mudstones, and the inclusion oil in the Els1 reservoir was generated from the Els1 source rock in the sag. The oil source of inclusion oils from different layers was almost consistent with that of crude oil in reservoirs. Combined with the Th of the FIs and 1D basin modelling, two episodes of oil charge are identified in the center of the Bailian Sub-sag: the first oil charge in the Els22 reservoirs started around 38.5 Ma in the lower petroleum play, which is consistent with the early oil generation time of the Els3 and Els22 source rocks in the Bailian Sub-sag. The second oil charge in the Els1 reservoir was coincided with the early oil generation time (∼13-0 Ma) of Els1 source rock. The oil charge and accumulation occurred in the isolated upper and lower petroleum plays. The oil charge and accumulation in the lower petroleum play from the Els3 and/or Els22 source rocks is almost distributed in the whole sag, and the oil in the upper petroleum play from the Els21 and/or Els1 source rock is mostly distributed in the center of the sag.

2D Restorations and Basin Modeling Provide Insight Into Formation Maturation

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 2021-5434, “Delaware Basin Wolfcamp Formation Maturation and Post-Permian Basin Evolution Based on 2D Restorations and Basin Modeling,” by Rachel Hoar, Mauro Becker, and Alan Yu, Texas A&M University. The paper has not been peer reviewed. _ The Permian Delaware Basin is a complex system in which the maturation of organic matter is affected by events not evident in the post-Permian available data. In this study, the authors aim to identify the effect of various geologic controls on hydrocarbon maturation in the Delaware Basin by restoring regional cross sections and performing simulations of organic-matter maturity. Integration of these data with seismic interpretation of the stratigraphic intervals present in the basin is used to refine the structural restorations and calibration of resulting 2D thermal models. Methods As a direct source of information for the initial evaluation of the post-Permian layers, surface geological maps, residual thickness maps, and structural information collected from the literature were examined. Next, four regional cross sections were selected and restudied with this objective. For the cross-sectional analysis, the data sets available were surficial geological and shallow-formation-thickness maps, subsurface seismic interpretation of the main stratigraphic intervals (proprietary data in the Delaware Basin sector), well logs, vitrinite reflectance evaluations, and apatite fission track analysis (AFTA) data available from the literature. In this Delaware Basin thermal-maturity study, the Wolfcamp formation was the unit selected and analyzed; however, the whole stratigraphic column needed to be included to produce the most-accurate and consistent model. With a major objective of this work being to evaluate the controls that post-Pennsylvanian depositional and erosional history have had on Delaware source-rock thermal maturity, this study focused on constraining the syn- and post-tectonic phase of the Ouachita/Marathon thrusting event. As such, the deformed rocks of the “known” phase (Carboniferous and older formations) were not considered, except for the paleogeomorphology resulted from the tectonic deformation and inherited by the lower Permian depositional phase. Previous work in the literature presented a comprehensive revision of the post-Permian sedimentary rocks and the patterns of erosion for the major post-Permian unconformities. The thickest post-Permian unit is the Triassic Dockum Group, a nonmarine red bed succession that paraconformably covers the Permian rocks. The Wichita paleoplain, an extensive unconformity, is recognized as an important exhumation and nondepositional period between the Triassic and the Cretaceous (Albian) in the area. Later Cretaceous carbonate strata also were deformed and exhumed at the Laramide contraction (Maastrichtian to Paleocene). The latest deformations that affected the area were the Miocene Basin Range event and Rio Grande Rift faulting complex. The work detailed in the complete paper details the cross section named the Diablo Platform/Central Basin Platform (CBP). All other cross sections followed the same methodology.

Thermal evolution and resources of the Bowland Basin (NW England) from apatite fission-track analyses and multidimensional basin modelling

Abstract Once highlighted for having significant shale gas resource potential, the Bowland Basin has been at the centre of both scientific and political controversy over the last decade. Previous shale gas resource estimates range from 10 3 to 10 1 TCF. Repeated events of induced seismicity following hydraulic fracturing operations led to an indefinite government moratorium and abandonment of operations across the mainland UK. We use apatite fission-track analyses to investigate the magnitude and timing of post-Triassic uplift and exhumation. Results indicate that maximum palaeotemperatures of 90–100°C were reached in the stratigraphically younger Sherwood Sandstone. We combine palaeotemperature predictions to constrain palaeo heat flow and erosion in regional basin models for the first time. Our results indicate variable maximum Late Cretaceous palaeo heat flow values of 62.5–80 mW m −2 and the removal of 800–1500 m of post-Triassic strata at wells across the basin. Regional 2D basin modelling indicates a gas-in-place estimate of 131 ± 64 TCF for the Bowland Shale. This reduces to a resource potential of 13.1 ± 6.4 TCF, assuming a recovery factor of 10%. These values are significantly lower than previous resource estimates and reflect the highly complex nature of the Bowland Basin and relatively unknown history of post-Triassic uplift, exhumation and erosion.

Geochemistry of oils and condensates from the lower Eagle Ford formation, South Texas. Part 3: Basin modeling

Maturity-dependent bulk properties and molecular compositions of oils and condensates produced from the lower Eagle Ford shales exhibit two distinct regional trends with production depth. Samples west of 98.6 West longitude form a trend that is offset upwardly by ∼2000 ft compared to samples near the Karnes Trough area. This offset is unlikely due to variations in source facies or regional heat flow. To test whether the offset is the result of different amounts of uplift and overburden removal, a psuedo 3D basin model was constructed for the Eagle Ford Formation using standard geologic methods and rock-calibrated 1D burial histories. Present-day thermal maturity was found to correlate with reconstructed maximum burial depth (MBD). When maturity-dependent geochemical parameters are plotted versus MBD, the trends show significantly greater fidelity than when plotted versus true vertical depth; however, the regional offsets are still evident, suggesting that the basin model could be refined. Petroleum samples can be used to calibrate basin models provided they reflect the current maturity of their source. This criterium may be met by unconventional fluids provided the producing strata is charged with the latest generated hydrocarbons from very limited, localized fetch area – conditions believed to be present in the lower Eagle Ford. API gravity from initial production, the only oil property reported for all wells, generally correlates with molecular maturity parameters but can be influenced by other processes. To compensate for these extraneous influences, trends of API gravity versus TVD were plotted for 0.2° longitudinal segments across the Eagle Ford play and used to model the relative amount of uplift and erosion needed to yield oil with the same API gravity and by inference the same maturity. Calculated MDB's from the API gravity oil-based model were found to agree well with those determined by the rock-based basin model and yielded more coherent depth trends with the measured maturity parameters. Both the rock-based and oil-based models find that the amount of Neogene uplift and overburden removal to be no more than ∼500 ft in the area near the San Marcos Arch and increases to the west, reaching ∼6500 ft in Maverick County. This finding strongly supports, if not proves, Cander's (2013) model for petroleum retention/production in the Eagle Ford shales and that the produced petroleum is a near-instantaneous, rather than a cumulative charge, of the latest generated hydrocarbons. This implies that unconventional continuous source petroleum systems are suitable for oil-based calibration of basin models. In many ways, the Eagle Ford petroleum system is ideal in its simplicity for the application of type of calibration.

3D basin and petroleum systems modeling in Shushan Basin, Western Desert, Egypt

3D basin and petroleum systems modeling in Shushan Basin, Western Desert, Egypt

Neogene-Quaternary evolution of the La Baja Guajira basin, Colombia: Burial and thermal history with implications on petroleum systems

The La Baja Guajira Basin is South America's northernmost part that extends from onshore Colombia into the Caribbean Sea and represents an important gas-producing region in Colombia. The dataset used in this study consists of twenty-four (24) regional 2D seismic-reflection lines integrated with information from nine (9) boreholes across the basin. We present seismic interpretations of key stratigraphic and structural features constrained by 1D basin modeling. This allows us to describe the Neogene-Quaternary evolution of the basin, and understand the possible implications for the hydrocarbon potential.We have interpreted eight (8) seismic units within the La Baja Guajira Basin (acoustic basement to U7) affected by three fault groups: 1) NW-SE-striking basement normal faults, 2) inverted normal faults, and 3) strike-slip faults. Considering the evidence, we propose four tectonic phases along the basin's evolution. The basement was affected by normal faulting as the result of extensional tectonics prior to the deposition of the sedimentary infill (Paleogene?). Another extensional interval occurred during the Early Miocene, triggering a moderate accommodation within the proximal area. Subsequently, extension migrated westwards resulting in the formation of the main La Baja Guajira Basin depocenter. In the Middle Miocene (post-extension), sedimentation was controlled by exhumation pulses in adjacent areas to the basin, which resulted in significant sediment input contemporaneous with rapid tectonic subsidence. Yet, local inversion of NW-SE-oriented basement-rooted faults affected today's offshore domain until the Late Miocene. This inversion can be associated with regional compressive deformation linked to the activity of the Oca and Cuiza faults. A second episode of rapid tectonic subsidence happened in the Early Pliocene. In the south of the basin, rocks were subjected to maximum burial and highest temperatures in recent times, conditions that might lead to hydrocarbon generation. The high Neogene to recent sedimentation rates calculated for the La Baja Guajira Basin support microbial gas generation; structural reactivation in this time supported trap formation, particularly in the offshore parts of the basin.

Innovation in assessment of the geothermal energy potential of abandoned hydrocarbon wells in the southern and southeastern foreground of the Bükk Mountains, northeast Hungary

An innovative methodology is introduced to study abandoned oil exploration drillings for possible geothermal energy production at a test area in northeast Hungary. An evaluation method supported by robust statistical analysis was elaborated to provide the possible future investors with adequate technical and earth-science related information for their decision-making processes. All the available data of 161 abandoned hydrocarbon wells, with different physical conditions, were examined based on the proposed evaluation system to provide information about the geothermal energy potential for each well, as well as over a bigger area. The abandoned wells and their environments, the quantity of stored heat, and the fluid temperature and geothermal heat were the key parameters determined, which are critical when considering geothermal energy utilization or thermal water production. The maximum amount of stored energy was determined as the sum of the amount of energy extractable from the rock and the fluid. The heat stored in the rock was determined by basin modelling. The evaluation process, using one-dimensional (1D) basin modelling and 3D lithological-stratigraphic modelling, was successfully applied in the pilot area. The maximum amount of heat stored in the fluid can be determined by subtracting the heat stored in the rock from the total heat. Drilling and completing geothermal wells are rather expensive in Hungary, depending on the depth and the types of geological formations. The application of this research could greatly reduce the cost and risk of creating new geothermal energy systems based on production wells or abandoned wells in Hungary or elsewhere.