Jurassic Source Rocks Research Articles

Hydrocarbon Generation Characteristics of Coal‐measure Source Rocks and their Contribution to Natural Gas: A Case Study of Middle and Lower Jurassic Targets from the Southern Junggar Basin Margin

AbstractIn order to study the hydrocarbon generation (HCGE) characteristics of coal‐bearing basins, the coal‐measure source rocks of the Middle Jurassic–Lower Jurassic (MLJ) of the piedmont thrust belt in the southern margin of the Junggar Basin in Northwest China are taken as research objects. More than 60 MLJ samples were collected from outcrops and wells. Total organic carbon (TOC), rock pyrolysis (Rock–Eval), organic petrological, vitrinite reflectance (%Ro), and hydrous pyrolysis were performed to analyze the relevant samples. The pyrolysis gases and liquid products were measured, and then the chemical composition, as well as carbon isotopes of the gases, were analyzed. The results indicate that the MLJ source rocks have the capacity for large‐scale gas generation. In addition, for coal‐measure source rocks, the heavier the carbon isotope of kerogen (δ13Ckerogen), the lower the liquid hydrocarbon and hydrocarbon gas yield, and the easier it is to produce non‐hydrocarbon gas. It is worth noting that when the δ13Ckerogen in organic matter (OM) is relatively heavier, the fractionation of its products may become weaker in the evolutionary process. The vital contribution of the MLJ source rock to natural gas resources in the study area was further confirmed by comparing it with the Jurassic source gas.

Hydrocarbon generation potential in Jurassic source rocks from hydrous pyrolysis experiments under ultradeep conditions

This study investigates the hydrocarbon generation potential of Jurassic source rocks under ultradeep conditions by utilizing semiclosed system hydrous pyrolysis experiments to simulate the geological processes at play. This study examines four distinct lithologies (shale, mudstone, carbonaceous mudstone, and coal) and three kerogen types (I, II, and III) across a temperature range of 250–650 °C and fluid pressures ranging from 34 to 100 MPa. The results indicate a bimodal distribution in total oil yields, with peak generation observed at approximately 350 °C and 600 °C. This pattern suggests a complex relationship between temperature, pressure, kerogen type, and hydrocarbon output. Notably, while I-Shale and II-Mudstone display higher hydrocarbon efficiency, III-type rocks exhibit superior oil and gas production rates because of their higher total organic carbon content. Research revealed that the oil expulsion rate exceeds 99% at temperatures above 500 °C, with the expelled oil predominantly comprising nonhydrocarbons and asphaltenes. Our findings suggest that Jurassic hydrocarbon source rocks maintain oil and gas potential under ultradeep conditions (high-over maturity stages at depths exceeding 6000 m). Under sustained fluid overpressure exceeding 70 MPa, the hydrocarbon generation peaks of various kerogen types in source rocks are markedly delayed. This phenomenon enables the source rocks to retain the potential for liquid hydrocarbon generation even during the stages of overmaturity. The results significantly enhance the theoretical framework of hydrocarbon generation under ultradeep conditions, thereby providing a crucial extension to the existing thermal boundary theory of hydrocarbon formation. These insights are crucial for the oil and gas industry, directing future exploration efforts towards ultradeep reservoirs and informing the development of new technologies to exploit these resources. This research not only enhances the understanding of subsurface hydrocarbon systems but also has implications for strategies aimed at maximizing resource recovery and managing the environmental impact of deep Earth exploration.

Jurassic Source Rock Characteristics and Resource Evaluation in Junggar Basin

Jurassic Source Rock Characteristics and Resource Evaluation in Junggar Basin

Opening and Post-Rift Evolution of Alpine Tethys Passive Margins: Insights from 1D Numerical Modeling of the Jurassic Mikulov Formation in the Vienna Basin Region, Austria

This study employed 1D numerical pseudo models to examine the Upper Jurassic carbonate succession, focusing on the Mikulov Formation in the Vienna Basin region. It addresses the protracted and complex history of the Jurassic source rock play, revealing a transition from rapid syn-rift (>200 m/Ma) to slower post-rift sedimentation/subsidence of the overlying layers during extensional deformation (up to 120 m/Ma with a thickness of 1300 m). This provides valuable insights into the rift-to-drift stage of the central Alpine Tethys margin. The Mikulov marls exhibit characteristics of a post-rift passive margin with slow sedimentation rates. However, a crustal stretching analysis using syn-rift heat flow sensitivity suggested that thermal extension of the basement alone cannot fully explain the mid-Jurassic syn-rift stage in this segment of the Alpine Tethys. The sensitivity analysis showed that the mid-late Jurassic differential syn-rift sequences were exposed to slightly cooler temperatures than the crustal stretching model predicted. Heat flow values below 120 mW/m2 aligned with measurements from deeply settled Mesozoic successions, suggesting cold but short gravity-driven subsidence. This may account for the relatively low thermal maturation of the primary source rock interval identified by the time-chart analysis, despite the complex tectonic history and considerable sedimentary burial. The post-Mesozoic changes in the compaction trend are possibly linked to the compressional thrusting of the Alpine foreland and postdating listric faulting across the Vienna Basin.

PETROLEUM GEOLOGY OF THE CENOZOIC SUCCESSION IN THE ZAGROS OF SW IRAN: A SEQUENCE STRATIGRAPHIC APPROACH

The Cenozoic stratigraphy of the Zagros records the ongoing collision between the Arabian and Eurasian Plates and the closure of NeoTethys. A Paleogene NW‐SE trending foreland basin was inherited from a Late Cretaceous precursor. Widespread progradation into the foredeep was a feature of both margins which, allied to ongoing tectonism, had by the late Eocene led to the narrowing and subsequent division of the foredeep into the Lurestan – Khuzestan and Lengeh Troughs, separated by the northward continuation of the rejuvenated Qatar‐Fars Arch. This sub‐division strongly influenced subsequent deposition and the petroleum geology of the area. In addition, the diachronous nature of the Arabian – Eurasian collision led to strong diachroneity in lithostratigraphic units along the length of the Zagros. Hence its petroleum geology is best understood within a regional sequence stratigraphic framework. This study identifies three tectono‐megasequences (TMS 10, TMS 11a, TMS 11b) and multiple depositional sequences.The Cenozoic contains a world class hydrocarbon province with prolific oil reservoirs in the Oligo‐Miocene Asmari Formation sealed by the evaporite‐dominated Gachsaran Formation, mostly contained within giant NW‐SE trending “whaleback” anticlines concentrated in the Dezful Embayment. Reservoirs in the SW are dominantly siliciclastic or comprise mixed siliciclastics and carbonates, whereas those to the east and NE are dominated by fractured carbonates. There remains untested potential in stratigraphic traps, especially in deeperwater sandstone reservoirs deposited along the SW margin of the foredeep.Late Miocene to Pliocene charge to the Asmari reservoirs was mostly from Aptian – Albian Kazhdumi Formation source rocks. In some fields, an additional component was from organic‐rich late Eocene to earliest Oligocene Pabdeh Formation source rocks confined to the narrowing Lurestan – Khuzestan Trough. Where mature, the latter source rock is also a potential unconventional reservoir target, although the prospective area is limited due to recent uplift and erosion. Deeper Jurassic source rocks contributed to the Cheshmeh Khush field in Dezful North. Silurian source rocks charged gas‐bearing structures in the Bandar Abbas region.

Characteristics of Jurassic Source Rocks and Evaluation of Hydrocarbon Resources in Tarim Basin, western China

Jurassic strata in Tarim are significant for their hydrocarbon-rich content. However, the distribution of hydrocarbon source rocks in this region is uneven, and the conditions for hydrocarbon accumulation vary significantly among the different structural elements. Therefore, it is essential to investigate the distribution of Jurassic source rocks, the evolution history of hydrocarbon generation, and the mechanisms influencing hydrocarbon accumulation for effective hydrocarbon exploration and development. To achieve this, seismic, geologic, drilling, logging, and testing data were integrated to analyze the distribution and quality of hydrocarbon source rocks, the evolution of hydrocarbon generation, and the factors influencing hydrocarbon accumulation in Jurassic hydrocarbon source rocks in Tarim Basin. The study revealed that the Jurassic effective hydrocarbon source rock centers are mainly located in the piedmont areas of Kuqa depression, southwest depression, and southeast depression, as well as Yingjisu sag and Manjiaer sag in the eastern Tarim area. Based on a comprehensive evaluation and comparison of the potential of Jurassic hydrocarbon potential in each secondary structural unit, it is concluded that Kuqa Depression has the most favorable exploration zone due to its excellent hydrocarbon accumulation conditions and abundant hydrocarbon resources. Although the overall exploration potential of the southwest depression is lower than that of the Kuqa depression, the hydrocarbon resources potential of the piedmont thrust belt and the associated depression is very high. Similarly, the eastern part of the Manjiaer sag and the Altun piedmont zone of the southeastern depression still have promising exploration prospects, although the overall exploration potential of the eastern Tarim area and the southeastern depression is not as good as the former two.

Present-Day Geothermal Regime and Thermal Evolution of the Fukang Sag in the Junggar Basin, Northwest China

The Fukang Sag in the Junggar Basin is an important petroleum exploration and exploitation region. However, the geothermal regime and tectono-thermal evolution of the Fukang Sag, which control its hydrocarbon generation and conservation, are still controversial. This study involved a systematic analysis of the present-day geothermal gradient, heat flow, and thermal history of the Fukang Sag for better further exploration. According to the well log data and well-testing temperature data, we calculated that the geothermal gradient of the Fukang Sag ranges from 16.6 °C/km to 29.6 °C/km, with an average of 20.8 °C/km, and the heat flow ranges from 34.6 mWm−2 to 64.3 mWm−2, with an average of 44.6 mWm−2. Due to the basement relief, they decrease from northeast to southwest. The weight averages of the single-grain apatite (U-Th)/He ages of the core samples are 1.3–85.2 Ma, and their apatite fission track ages range from 50.9 Ma to 193.8 Ma. The thermal modeling results revealed that the Fukang Sag experienced late Permian, late Jurassic, and late Cretaceous cooling events (although the timing and magnitude of these events varied among the samples), which were related to the continuous compression of the Junggar Basin. In addition, basin modeling indicated that the heat flow of the Fukang Sag decreased from 80 mWm−2 in the Carboniferous to the current value of 44.6 mWm−2. The Fukang Sag’s edge exhibits prolific hydrocarbon generation in the Carboniferous–Permian source rocks, while the Jurassic source rocks within the sag also undergo abundant hydrocarbon generation. This study provides new insights into the present-day geothermal field and tectono-thermal evolutionary history of the Fukang Sag, which are significant in terms of regional tectonic evolution and oil and gas resource assessment.

Burial and thermal history simulation of the Middle Jurassic source rocks in Matruh basin, north Western Desert, Egypt

Burial and thermal history simulation of the Middle Jurassic source rocks in Matruh basin, north Western Desert, Egypt

Contribution of the Lower-Middle Jurassic source rocks in petroleum potential of the Jurassic-Cretaceous series within the central part of West Siberia

In this paper, based on a geochemical study of rock samples and fluids, it is proven that carbon-bearing deposits of the Lower and Middle Jurassic complex of Western Siberia on the southern outskirts of the Khanty-Mansiysk and Yamalo-Nenets Autonomous Okrug can generate liquid hydrocarbons. It has been established that the oil-generation potential of carbon-bearing deposits depends on the paleogeographic conditions of burial of the organic matter and the enrichment of rocks with macerals of the liptinite group. The complex of studies included pyrolysis of coals, coal-rich shale of Lower and Middle Jurassic rocks, study of maceral composition and measurement of reflectivity indicators, hydrocarbon and isotopic composition of extracts from rocks, as well as study of the composition of oils from the studied area, selected both within the Jurassic and Cretaceous complexes. The studied area is located in the Frolov megadepression and the South Nadym megamonoclise. The result of the research was the identification of significant geochemical characteristics of an additional source of hydrocarbons – coals, coal-rich shale of the Lower and Middle Jurassic, which had not previously been proven on the studied area, the contribution of which to the formation of oil and gas potential was confirmed by the correlation of hydrocarbon and isotopic characteristics of fluids and extracts from source rocks. Сluster and the principal component analysis were used for genetic correlation of extracts and oils. The conclusions obtained from geochemical studies suggest the possible prospects of Lower and Middle Jurassic deposits from the point of view of detecting hydrocarbon accumulations.

Gas source of the Middle Jurassic Shaximiao Formation in the Zhongjiang large gas field of Western Sichuan Depression: Constraints from geochemical characteristics of light hydrocarbons

The Zhongjiang gas field is a typical large gas field in terrigenous strata of the Western Sichuan Depression. It remains debatable which member of the Upper Triassic Xujiahe Formation served as the source rocks and how significant the member contributed to the gas accumulations in the Zhongjiang gas field. In this study, we analyzed the essential characteristics of the Lower Jurassic source rocks and the geochemical features of light hydrocarbons in natural gas from the 2nd (T3x2) and 4th members (T3x4) of the Upper Triassic Xujiahe Formation (T3x), as well as the Middle Jurassic Shaximiao (J2s) and Qianfoya (J2q) formations. Based on this, we explored the sources of the natural gas in the Zhongjiang gas field and determined the natural gas migration patterns and their effects on the properties of light hydrocarbons in the natural gas. The results indicate that the Lower Jurassic lacustrine source rocks of the Zhongjiang gas field contain humic organic matter, with vitrinite reflectance (Ro) values ranging from 0.86% to 0.98%. Samples meeting the criterion for effective source rocks [total organic carbon (TOC) content ≥0.75%] exhibited an average TOC content of merely 1.02%, suggesting significantly lower hydrocarbon generation potential than source rocks in the underlying T3x, which show higher thermal maturity and TOC contents. For natural gas samples from T3x2, T3x4, J2s, and J2q reservoirs, their C5–7 iso-alkane content was significantly higher than their n-alkane content, and their methylcyclohexane (MCH) index ranged from 59.0% to 77.3%, indicating the predominance of methylcyclohexane in C7 light hydrocarbons. As indicated by the origin identification and gas-source correlation based on the geochemical features of light hydrocarbons, the natural gas in the Zhongjiang gas field is typical coal-derived gas. The gas from the primary pay zone of the Shaximiao Formation, with significantly high K1, (P2 + N2)/C7, and P3/C7 values, predominantly originated from the 5th member of the T3x and migrated in the free phase, with a small amount possibly sourced from the Lower Jurassic source rocks. The dissolution and adsorption during gas migration led to a decrease in the aromatic content in C6–7 light hydrocarbons and an increase in the iso-heptane values. Therefore, their effects must be considered when determining the gas origin and thermal maturity based on the aromatic content in C6–7 light hydrocarbons and iso-heptane values.

Features and favorable exploration direction of normal faults in Jurassic strata in northern central Sichuan Basin, China

Studies focusing on the fault system in the Jurassic strata of the Sichuan Basin have been limited, restricting the understanding of the hydrocarbon accumulation mode of the Shaximiao Formation and the expansion of exploration. Through interpretation and coherent slice analysis of extensive seismic data, we have newly discovered that normal faults are widely developed in the northern central Sichuan Basin in the Jurassic strata. These faults mainly extend from the Lower to Upper Jurassic strata and are characterized by the continuous arrangement of NEE-trending small faults in the plane, with a few NNE-trending and NNW-trending faults also present. The distribution of Jurassic fault combinations varies within the basin, with normal faults mainly distributed in the low uplift areas of central Sichuan and the north of central Sichuan. Geochemical data comparisons indicate that these normal faults serve as conduits between the Jurassic source rocks and the Shaximiao Formation reservoir in these areas. Furthermore, the newly discovered normal faults are superimposed with the middle and lower Jurassic source rocks in the northern central Sichuan Basin, suggesting the formation of a new hydrocarbon accumulation model involving hydrocarbon generation from the middle and lower Jurassic, facilitated by communication through normal faults. Notably, one of the promising directions for exploration lies in the multi-stage channel superimposed development zone near these normal faults.

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.

Source-reservoir rock assemblages and hydrocarbon accumulation models in the Middle-Lower Jurassic of eastern Sichuan Basin, China

The eastern Sichuan Basin in China holds vast potential for oil and gas exploration in the Lower-Middle Jurassic strata. However, the geological characteristics and hydrocarbon accumulation patterns of this region remain largely unclear. During the deposition period of the Lower-Middle Jurassic strata, the eastern Sichuan is characterized by the formation of multiple sets of source, reservoir, and caprock assemblages through depositing lake-delta-fluvial deposits, which have great exploration potential. The Jurassic source rocks in eastern Sichuan are mainly developed in the Dongyuemiao Member, Da’anzhai Member, and Liangshan Formation. These source rocks have a total organic carbon (TOC) content greater than 1 and a varying range of organic matter maturity, with a Ro value of 0.8–2.0. The kerogen in these source rocks is primarily type II, with a smaller proportion being type III. A range of reservoir rocks can be found in the Jurassic strata of eastern Sichuan, with sandstone reservoirs being predominantly found in the Liangshan Formation, Shaximiao Formation, and Zhenzhuchong Member. Shale reservoirs are mostly present in the Dongyuemiao, Da’anzhai, Liangshan, and Maanshan Members, and there is a limited distribution of limestone reservoirs in the Da’anzhai Member and Dongyuemiao Formation. The arrangement of source rocks and reservoir rocks in eastern Sichuan has led to the formation of three types of reservoir-forming combinations, including lower generation and upper storage, self-generation and self-storage, and composite. Sandstone reservoirs are typically of lower generation and upper storage, shale reservoirs are primarily of self-generation and self-storage, and limestone reservoirs are mostly composite. The exploration of Jurassic oil and gas in eastern Sichuan should prioritize “layer and area selections.” The Da’anzhai, Dongyuemiao, and Liangshan shale reservoirs should be the primary exploration targets, with the semi-deep lake deposits in the syncline area being the most favorable. The degree of fracture development in the exploration area also has a significant impact on the shale oil and gas content. The Liangshan Formation and Shaximiao Formation sandstone reservoirs can serve as secondary exploration targets, with anticline areas that have better sealing conditions being more favorable. Limestone reservoirs have limited distribution, and exploration areas with high and steep fractures are relatively more advantageous.

Relationship between structural style and the petroleum system in the siba gas field, southern Iraq

The Siba gas field is the only non-associated gas field in southern Iraq, located in an area primarily for oil production. The study aimed to identify the reasons for gas generation and accumulation in the field's Lower Cretaceous Yamama reservoir and the source of the gas. The study focuses on seven wells from the field, namely Siba-1, 4, 5, 6, 7, 8, and 9, and the structural and tectonic settings of the field were studied by interpreting seismic data. Geometric analysis showed that the Siba field is a non-cylindrical, asymmetrical, open, anticlinal fold. The anticline is northeast-southwest-trending with two culminations, of which the northeastern one is the higher by about 100 m. The Siba field overlies deepest parts of the Mesopotamian foreland basin, almost adjacent to the Zagros orogenic front, where burial depth and thermal conditions were ideal for organic-matter maturation and increased pore pressures that lead to hydrocarbon migration from Middle Jurassic source rocks to the Lower Cretaceous Yamama Formation reservoir. The geochemical parameters of oils from the Yamama Formation are like those of oils from Sargelu Formation in adjacent fields, indicating that the Middle Jurassic Sargelu Formation is the most likely source of Siba hydrocarbons. Vitrinite reflectance and thermal analyses of oils from the Yamama reservoir (0.87% R0; 128.1 °C) and from the Sargelu Formation (1.36% R0; 156.96 °C) show that only the Sargelu Formation had the right burial depths and temperatures in this area during Miocene deformation to source Yamama hydrocarbons in the Siba field. Although the anhydrites of the Upper Jurassic Gotnia Formation form a prominent regional seal separating Jurassic source rocks from Cretaceous reservoirs, structure-contour maps and seismic analyses indicate that many faults and fractures, mostly related to Miocene deformation, penetrate Gotnia anhydrites. Hence, the study interprets that these faults, as well as facies changes on the margin of the Gotnia basin, seriously impaired the Gotnia seal, allowing the vertical migration of hydrocarbons from the Middle Jurassic Sargelu Formation into the Lower Cretaceous Yamama reservoir in the Siba field.

Conversion of the Oil and Gas Generation Potential of the Deep Source Formations of the West Siberian Basin: An Example of Well Tyumen SG-6

A model of the thermal evolution of the lithosphere of the West Siberian Basin in the area of Superdeep Well SG-6, which was drilled through the Koltogor–Urengoi graben, is used to numerically estimate the generation of various hydrocarbon (HC) fractions by the Triassic and Jurassic source rocks. The thermal model assumes the emplacement of a sill into the subsurface layers of the basement in the Early Jurassic and hydrothermal activity in the Late Pliocene–Lower Pleistocene, which noticeably impacted the conversion history of the HC potential of the Triassic and Jurassic source rocks. For the Triassic Pur formation, the emplacement of the sill into the subsurface layers of the basement in the Lower Jurassic drastically intensified the conversion of the HC potential to 84% and the degradation of more than 97% of the generated light oil mass. Calculations show that the heavy oil generated by the rocks of the Pur, Togur, and lower horizons of the Tyumen formations has degraded almost completely as a result of secondary cracking, while heavy oil predominates among the generated HC fractions in the upper horizons of the Tyumen Formation and in the rocks of the Bazhenovo Formation. The light oil remaining nowadays in the matrix of the source rocks has completely degraded in the Triassic rocks but makes up much of the HC products in rocks at the bottom of the Togur Formation and the top of the Tyumen Formation. This oil is the dominant in the upper horizons of the Togur Formation and in the bottom part of the Tyumen Formation. According to calculations, gas hydrocarbons account for a significant proportion of HC products in the Togur and Tyumen formations, and they dominate in the Middle Triassic Pur Formation. At the relatively low initial potential of HC generation and a low content of organic matter in the rocks of the Pur, Togur, and Tyumen formations, no primary expulsion threshold of liquid HC has been reached, and the generated liquid HC probably did not leave the rock matrix, while the gaseous HC likely migrated. The threshold of primary expulsion of liquid HC for the Bazhenov rocks was calculated to be reached at about 65 My.

Formation evaluation utilizing a new petrophysical automation tool and subsurface mapping of the Upper Cretaceous carbonate reservoirs, the southern periphery of the Abu-Gharadig basin, Western Desert, Egypt

The southern periphery of the Abu-Gharadig basin in the Northern Egyptian Western Desert is characterized by some subsurface geological challenges related to the carbonate reservoir's quality, which requires precise petrophysical evaluation and seismic structural interpretation. Therefore, we conducted a subsurface mapping and formation evaluation for the Upper Cretaceous carbonate reservoirs in the Southwest Abu Sennan (SWS) area utilizing seismic reflection profiles and borehole geophysical data. Seismic mapping of the Upper Cretaceous carbonate reservoirs (Abu Roash (AR)/B,/D, and/F) revealed 3-way folds with NE-SW trends divided by NW-SE normal fault trends presenting significant chances for exploration. These closures were filled by hydrocarbons generated from the Jurassic source rocks. Formation evaluation was performed using the new petrophysical tool “Gaialog” which was coded using Python. Petrophysical parameters for the recognized net pay intervals of AR/B, AR/D, and AR/F carbonate reservoirs showed that the effective porosity (φeff: Phie) and the hydrocarbon saturation (Sh) increases towards the East to Southeast direction while the water saturation (Sw) increases to the Northwest of the study area. The highest net pay and the effective porosity were found in the Eastern part of the study area. The study procedures can be applied in neighboring areas to evaluate and understand similar reservoirs.

The Rossano–San Nicola Fault Zone evolution impacts the burial and maturation histories of the Crotone Basin, Calabrian Arc, Italy

This work addresses the tectonic significance of a NW–SE-trending strike-slip fault zone in the Calabrian Arc of southern Italy, the Rossano–San Nicola Fault Zone (RSFZ). High-quality seismic reflection and 1D forward models of exploration boreholes and pseudo-wells show that the RSFZ experienced multiple Miocene phases of contractional/transpressional tectonics. These were followed by crustal extension during the Pliocene, which occurred in association with the oceanization of the Tyrrhenian Sea, Apennine orogenesis, and collision between the Calabrian Arc and adjacent tectonic plates. Such a setting had a profound influence on the Crotone Basin and its economic potential: (1) tectonic reactivation allowed reservoir units of the Crotone Basin to be charged by gas derived from Triassic/Lower Jurassic source rocks; and (2) source rocks reached their maximum depth and remained in the gas generation window after the emplacement of a large mass-transport complex in the Pliocene. In the surrounding areas, tectonic activity near the RSFZ contributed to source-rock maturation by enhancing local sedimentation rates, particularly during Langhian (Middle Miocene) and Zanclean (early Pliocene) tectonics. This work is important as it demonstrates that the tectonostratigraphic evolution of the Crotone Basin was closely related to the structural evolution of the RSFZ. Crucially, the study area reveals the first example of a gas field fully sealed by a large mass-transport complex. As a corollary, we tie the Late Cenozoic geological history of the Crotone Basin to the geodynamic evolution of the central Mediterranean region, namely the Ionian and Tyrrhenian seas. We identify new prospects in the Crotone Basin, and provide a time frame for gas generation and accumulation in southern Italy.

Petroleum system modeling in complex tectonic setting; a study case of the Huallaga-Marañon retroforeland basin system, Peru

The present study explores the oil and gas potential of the Huallaga–Marañon Andean retroforeland basins in Perú, considering a regional transect which extends from the Eastern Cordillera in the west trough the Huallaga fold-and-thrust belt at the Andean deformation front to the Marañon Basin in the east. The sequential restoration of main tectonic events was derived from previous stratigraphic and structural interpretations revisited with reprocessed seismic lines, and new geochemical, petrographical, geochronological and thermochronological data. The resulting framework was tested in a 2-D Basin and Petroleum System Modeling (BPSM) to check the relationship between burial history, thermal maturity evolution and timing of hydrocarbon generation, expulsion and trapping at regional scale. BPSM suggests that during the Late Cretaceous (ca. 80 Ma) the petroleum generated in the Upper Triassic–Lower Jurassic source rock known as the Aramachay Formation migrated through the Middle–Upper Jurassic Sarayaquillo Formation basal sandstones up to 250 km and accumulated in the southeast of the Marañon Basin. From the Late Miocene, the reactivation of vertical faults favored the migration and accumulation of petroleum in Cretaceous siliciclastic reservoirs which is consistent with the hydrocarbon fields existence in this sector of the basin.In addition, results of modeling show that in the southwest of the Marañon Basin the development of structures during Late Miocene times postdated the generation and expulsion of hydrocarbons calculated for the Aramachay Formation which introduces a risk of synchronization between oil migration and charge. However, part of the generated hydrocarbons during the Late Cretaceous and Cenozoic are partially preserved in Jurassic reservoirs due to the high seal capacity of mudstones of the Sarayaquillo Formation. Such hydrocarbon fluids are redistributed and migrated into structural traps during Miocene times. In addition, the Miocene gas generation and expulsion also will reduce the risk of synchronization with the development of structures. In the Eastern Cordillera, organic-rich levels of the Aramachay Formation are in the late immature to early oil window show the occurrence of organic pores adding hydrocarbon storage capacity, suggesting this unit to be considered as a potential unconventional target in future exploration activities.

MODELING OF HYDROCARBON GENERATION ZONES AND MIGRATION PATHWAYS OF AN OIL FIELD OF PRECASPIAN REGION, KAZAKHSTAN

This article highlights the features of geological (basin) modeling of various zones and migration routes and presents the assessment of resources of the oil field in the Precaspian region in western Kazakhstan. A brief overview of geochemical features of the basin is presented using modern assaying and visualization software packages. The preferred method of constructing 1D models is indicated, and the results of such 1D modeling derived from the results of basin modeling are presented. Additional data points (including paleowater depths, sediment-water interface temperatures and heat flows) as boundary conditions were collected and included in the modeling software for data calibration and cross-checking purposes. For all 1D models produced in this study, Jurassic source rocks were deemed to have entered the oil window in Cretaceous time with the critical moment occurring in Late Cretaceous and Early Paleogene. The implied tectonic history of the basin suggests two possible periods of trap formation: tectonic inversion in the Middle Jurassic and possible folding during late Alpine orogeny which began in Late Cretaceous or early Eocene. While the Middle Jurassic traps can undoubtedly be filled with hydrocarbons, there is no such high degree of certainty with regards to traps formed after Late Cretaceous, as those traps were formed after peak migration periods.

Geochemical assessment of upper Cretaceous crude oils from the Iranian part of the Persian Gulf Basin: Implications for thermal maturity, potential source rocks, and depositional setting

The Upper Cretaceous carbonate successions of the Sarvak Formation host giant oil reservoirs in the Persian Gulf. In this research, a total of 28 oil samples from nine oilfields located in the western, central and eastern parts of the Persian Gulf region were studied to determine the genetic relationships of oils, depositional setting of possible source rocks, thermal maturity, and source-rock ages in the Persian Gulf basin. According to the measured geochemical data, the source rocks facies vary from marine carbonates and marl/carbonates in the central and eastern oilfields to shale/carbonates in the western oilfields. The Pr/Ph ratio, steranes and terpanes suggest anoxic to dysoxic conditions of the depositional environments. The depositional environments experienced both low water stratification/low salinity and normal salinity/unstratified conditions. Evaluation of the saturated and aromatic biomarkers shows that all oil samples are mature and most of the source rocks lie within the beginning of the oil-generation window. The thermal maturity of the central oilfields is higher than that of the other samples, and has gone beyond the oil-generation stage. The C28/C29 steranes ratio suggest that the central oilfields of the Persian Gulf have Paleozoic and Jurassic source rocks, whereas the Sarvak reservoir in other parts of this region is sourced from Cretaceous carbonate rocks.