Thermal Maturity Modeling Research Articles

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.

Geochemical characteristics and thermal maturity modelling of Alam El Bueib/Kharita in the Tut Oil Field, Shushan Basin, North Western Desert, Egypt

Geochemical characteristics and thermal maturity modelling of Alam El Bueib/Kharita in the Tut Oil Field, Shushan Basin, North Western Desert, Egypt

An Integrated Approach for the Thermal Maturity Modeling Re-Assessment of an Exploration Well in the Hellenides Fold and Thrust Belt

Utilizing geological and geochemical data, we re-assessed the thermal maturity of the Lower Cretaceous Vigla shales of the AY-3 well, located in the Internal Ionian geotectonic zone of Greece, using 1D thermal maturity modeling. Vigla shales primarily containing kerogen type I to II, incorporated within alternations of carbonates, cherts, and marly limestones, were selected as the main source rock intervals. Biomarkers and Rock-Eval data were used on top of vitrinite reflectance data for the calibration of the 1D model. Hopane and sterane isomerization ratios for the Vigla shales appear to hold values of 58–64% and 44–49%, respectively, while vitrinite reflectance ranges from 0.61% to 0.71% and Tmax between 431 and 451 °C. One-dimensional thermal maturity modeling suggests that lower Cretaceous Vigla shales entered the oil window in early Miocene times and reached the expulsion onset during the middle Miocene. Additionally, thermal modeling estimates the overburden eroded thickness to range between 2.1 and 2.6 km. This unravels the pre-eroded shape of this part of the belt of Miocene times alongside the burial history of the area and its evident relation to the hydrocarbon potential. This assessment comprises a step towards the understanding of the belt and the different timings of hydrocarbon generation in the External Hellenides.

Organic matter composition and thermal maturity evaluation of Mesoproterozoic source rocks in the Beetaloo Sub-Basin, Australia

The Beetaloo Sub-basin in northern Australia comprises extensively developed marine, organic-rich shales within the Mesoproterozoic Velkerri and Kyalla formations. Oil and gas derived from the thermal maturation of primitive organic matter in these shales represent some of the oldest and best-preserved hydrocarbon accumulations identified worldwide. The organic matter is derived largely from prokaryotes with petrographic evidence indicating these primarily occur as filamentous strands or lamellae typical of cyanobacteria (blue-green algae) and commonly referred to as ‘alginite’. The shales also contain bitumen generated through thermal maturation of the primary organic matter, as well as pyrobitumen remaining as a residue after secondary cracking of heavy hydrocarbons to gas. At present, no well-defined method exists to accurately assess thermal maturity nor define their hydrocarbon generation windows in source rocks of this age. Our organic petrographic and geochemical analyses indicate alginite reflectance (Ra) increases with thermal maturity showing consistent relationships with depth, atomic H/C of kerogen and aromatic molecular ratios of extractable organic matter in the shales. Among the aromatic parameters tested, vitrinite reflectance calculated from methylphenanthrene index (MPI-1 Rc) shows the strongest correlation with Ra (Rc = 0.5834Ra + 0.3842) confirming it is an effective parameter to calibrate thermal maturity models, particularly for wells where only organic petrology data are available. Molecular and isotopic composition of in situ hydrocarbons from two deep wells suggest the primary hydrocarbon generation window for Mesoproterozoic source rocks lies between Ra ∼ 0.2 % (Rc ∼ 0.5 %) and ∼ 1.5 % (Rc ∼ 1.25 %) with the dry gas threshold at Ra > 2.5 % (Rc > 1.8 %). These findings represent a refinement of the existing source rock maturity evaluation methods for the Beetaloo Sub-basin and serve as a guide for assessing other Precambrian petroleum systems worldwide.

Source rock evaluation and petroleum system modeling of the East Beni Suef Basin, north Eastern Desert, Egypt

This study deals with the East Beni Suef Basin (Eastern Desert, Egypt) and aims to evaluate the source-generative potential, reconstruct the burial and thermal history, examine the most influential parameters on thermal maturity modeling, and improve on the models already published for the West Beni Suef to ultimately formulate a complete picture of the whole basin evolution. Source rock evaluation was carried out based on TOC, Rock-Eval pyrolysis, and visual kerogen petrography analyses. Three kerogen types (II, II/III, and III) are distinguished in the East Beni Suef Basin, where the Abu Roash “F” Member acts as the main source rock with good to excellent source potential, oil-prone mainly type II kerogen, and immature to marginal maturity levels. The burial history shows four depositional and erosional phases linked with the tectonic evolution of the basin. A hiatus (due to erosion or non-deposition) has occurred during the Late Eocene-Oligocene in the East Beni Suef Basin, while the West Beni Suef Basin has continued subsiding. Sedimentation began later (Middle to Late Albian) with lower rates in the East Beni Suef Basin compared with the West Beni Suef Basin (Early Albian). The Abu Roash “F” source rock exists in the early oil window with a present-day transformation ratio of about 19% and 21% in the East and West Beni Suef Basin, respectively, while the Lower Kharita source rock, which is only recorded in the West Beni Suef Basin, has reached the late oil window with a present-day transformation ratio of about 70%. The magnitude of erosion and heat flow have proportional and mutual effects on thermal maturity. We present three possible scenarios of basin modeling in the East Beni Suef Basin concerning the erosion from the Apollonia and Dabaa formations. Results of this work can serve as a basis for subsequent 2D and/or 3D basin modeling, which are highly recommended to further investigate the petroleum system evolution of the Beni Suef Basin.

Integrated geophysical analysis of the Sembar Formation, Central Indus Basin, as an unconventional resource

The ever-increasing demand for new energy sources witnessed at present is leading to a shortage of oil and gas resources throughout the world. At the same time, polluting energy sources such as coal are being gradually replaced by gas, new fuel types and electricity produced by renewable methods. Unconventional shale gas reserves, relying on the presence of substantial volumes of good quality, thermally mature organic matter, are therefore crucial in shaping the economic future of multiple regions in the world. Using seismic reflection data to estimate Total Organic Carbon (TOC) in the underexplored Sembar Formation of the Qadirpur Area, Central Indus Basin, this study investigates the potential of a new unconventional resource in Pakistan. We estimate TOC based on well-log data using Passey's Δ Log R, Schmoker's, and Schwarzkopf's methods. In a second stage, thermal maturity modelling was carried out for the formations encountered in Well Qadirpur Deep-01, while focusing primarily on the Sembar Formation. Petrophysical and petroelastic properties were determined and cross-plotted to identify potential zones favourable to hydraulic fracturing. The results show calculated TOC values ranging from 2 to 4 wt% based on the multiple methods indicated above, proving that the Sembar Formation is a good to excellent unconventional oil gas play. Thermal maturity modelling further confirms that the organic matter in the Sembar Formation is mature. Our seismic based spatial distribution indicates that TOC values are particularly favourable in the lower part of the formation, which is also prone to hydraulic fracturing based on its petroelastic evaluation. This study presents a valid approach to characterise source-rock potential in sedimentary basins throughout South Asia and around the world.

The hydrocarbon potential of the offshore Talara Basin, Peru

The offshore Talara Basin is the western extension of the hydrocarbon producing onshore fields since the mid-1800s area of Peru and is also located above the subduction zone of the active continental margin of South America. The offshore portion was evaluated using high quality 3D seismic where mapping horizons are all unconformities within the Eocene as well as the unconformities at the top Paleocene and top Cretaceous. Possible source rocks are the Cretaceous black marine shales of the Campanian Redondo Formation, the limestones of the Albian Muerto Formation, and the marine shales of the Paleogene. The primary target offshore is expected to be deep-water turbidites of Paleocene/Eocene age with a depositional source from the northeast from highlands created by the compressional uplift of the Andes. The main seals offshore are expected to be shales of the upper Eocene Lagunitos Formation and shales in the Chacra Formation, which are also seals in the onshore Litoral field. Thermal maturation modeling shows that two hydrocarbon kitchens exist in the offshore portion of the Talara basin, one in the north and one in the south. The probable Cretaceous source rocks reached the onset of maturity (VR = 0.63%) at a depth of 3,250 to 3,285 m (10,663 – 10,778 ft) between 30 and 39 Ma (Late Eocene to Oligocene). Importantly, the Cretaceous source rocks stay within the oil window once they enter it in the late Eocene. Satellite studies show a large offshore present-day oil seep in the southern part of the basin and 3D seismic shows direct hydrocarbon indicators (DHIs) imaged as flat spots and bottom simulating reflectors (BSR). Basin modeling suggests hydrocarbon migration pathways would have been updip (to the east) into the onshore traps and would therefore have first filled the offshore traps along the migration pathway. We conclude that the Talara Basin offshore offers excellent exploration opportunities in a proven productive area where multiple prospects have been mapped.

Thermal history of the East European Platform margin in Poland based on apatite and zircon low-temperature thermochronology

Abstract. The Phanerozoic tectonothermal evolution of the SW slope of the East European Platform (EEP) in Poland is reconstructed by means of thermal maturity, low-temperature thermochronometry, and thermal modelling. We provide a set of new thermochronometric data and integrate stratigraphic and thermal maturity information to constrain the burial and thermal history of sediments. Apatite fission track (AFT) analysis and zircon (U-Th)/He (ZHe) thermochronology have been carried out on samples of sandstones, bentonites, diabase, and crystalline basement rocks collected from 17 boreholes located in central and NE Poland. They penetrated sedimentary cover of the EEP subdivided from the north to south into the Baltic, Podlasie, and Lublin basins. The average ZHe ages from Proterozoic basement rocks as well as Ordovician to Silurian bentonites and Cambrian to lower Carboniferous sandstones range from 848 ± 81 to 255 ± 22 Ma with a single early Permian age of 288 Ma, corresponding to cooling after a thermal event. The remaining ZHe ages represent partial reset or source ages. The AFT ages of samples are dispersed in the range of 235.8 ± 17.3 Ma (Middle Triassic) to 42.1 ± 11.1 Ma (Paleogene) providing a record of Mesozoic and Cenozoic cooling. The highest frequency of the AFT ages is in the Jurassic and Early Cretaceous prior to Alpine basin inversion. Thermal maturity results are consistent with the SW-ward increase of the Paleozoic and Mesozoic sediments thickness. An important break in a thermal maturity profile exists across the base Permian–Mesozoic unconformity. Thermal modelling showed that significant heating of Ediacaran to Carboniferous sedimentary successions occurred before the Permian with maximum paleotemperatures in the earliest and latest Carboniferous for Baltic–Podlasie and Lublin basins, respectively. The results obtained suggest an important role of early Carboniferous uplift and exhumation at the SW margin of the EEP. The SW slope of the latter was afterward overridden in the Lublin Basin by the Variscan orogenic wedge. Its tectonic loading interrupted Carboniferous uplift and caused resumption of sedimentation in the late Viséan. Consequently, a thermal history of the Lublin Basin is different from that in the Podlasie and Baltic basins but similar to other sections of the Variscan foreland, characterized by maximum burial at the end of Carboniferous. The Mesozoic thermal history was characterized by gradual cooling from peak temperatures at the transition from Triassic to Jurassic due to decreasing heat flow. Burial caused maximum paleotemperatures in the SW part of the study area, where the EEP was covered by an extensive sedimentary pile. However, further NE, due to low temperatures caused by shallow burial, the impact of fluids can be detected by vitrinite reflectance, illite/smectite, and thermochronological data. Our new results emphasize the importance of using multiple low-temperature thermochronometers and thermal modelling in connection with thermal maturity analysis to elucidate the near-surface evolution of platform margins.

Burial and Thermal History Modeling of the Paleozoic–Mesozoic Basement in the Northern Margin of the Western Outer Carpathians (Case Study from Pilzno-40 Well, Southern Poland)

Hydrocarbon exploration under thrust belts is a challenging frontier globally. In this work, 1-D thermal maturity modeling of the Paleozoic–Mesozoic basement in the northern margin of the Western Outer Carpathians was carried out to better explain the thermal history of source rocks that influenced hydrocarbon generation. The combination of Variscan burial and post-Variscan heating due to elevated heat flow may have caused significant heating in the Paleozoic basement in the pre-Middle Jurassic period. However, the most likely combined effect of Permian-Triassic burial and Late Triassic–Early Jurassic increase of heat flow caused the reaching of maximum paleotemperature. The main phase of hydrocarbon generation in Paleozoic source rocks developed in pre-Middle Jurassic times. Therefore, generated hydrocarbons from Ordovician and Silurian source rocks were lost before reservoirs and traps were formed in the Late Mesozoic. The Miocene thermal overprint due to the Carpathian overthrust probably did not significantly change the thermal maturity of organic matter in the Paleozoic–Mesozoic strata. Thus, it can be concluded that petroleum accumulations in the Late Jurassic and Cenomanian reservoirs of the foreland were charged later, mainly by source rocks occurring within the thrustbelt, i.e., Oligocene Menilite Shales. Finally, this work shows that comprehensive mineralogical and geochemical studies are an indispensable prerequisite of any petroleum system modelling because their results could influence petroleum exploration of new oil and gas fields.

Thermal maturity and hydrocarbon generation modelling for the Lower Rudeis source rock and petroleum system analysis in Garra area, Gulf of Suez Rift, Egypt

The Lower Rudeis Formation is an active source rock in the Garra region, which is characterized by a good hydrocarbon generative potential. The Lower Rudeis source rock reached the early mature stage in the Middle Miocene Langhian (15.5 Ma) and went through the mid mature stage at 0.9 Ma.. It was generated from a clay source rock, deposited under sub-oxic to oxic conditions and derived from an organic material composed mainly of terrestrial organic material. The Lower Rudeis source rock went through two phases of hydrocarbon generation and expulsion. The first phase occurred from 6.0 Ma to 3.4 Ma, while the second phase started at 3.4 Ma and continued until the present time, with a transformation ratio estimated of 42%. The oil expulsion increased to 16 mg/gTOC and gas expulsion to 40 mg/gTOC, thus the expelled hydrocarbons are mainly composed of mainly gas and some oil. In contrast to the southern province, the Garra region has a single petroleum system which is charged by pre-Miocene and Miocene, Lowers Rudeis, source rocks along vertical and lateral migration routes and the main Kareem-Rudeis reservoirs that were sealed by the Belayim evaporite. The current study is based on the geological, geochemical, biomarker and stable carbon isotope data, which were analyzed, interpreted and presented as burial, thermal and maturity models using the petroleum systems and basin analysis program (BasinMod software).

Generative potential, thermal maturity, and TOC modeling of petroleum systems in Southwestern Khuzestan Province, Zagros Basin, Iran

ABSTRACT In this study, a series of analytical geochemistry and petro-physical studies has been done to a number of effective source rock samples in the southwestern region of Khuzestan province and it illustrates that some strata’s in investigated wells have high hydrocarbon generation potential with the existence of commercial hydrocarbon production. There are some practical drawbacks to these analytical strategies, which can be solved through a combination of the results of different analyses, such as Thermal maturity, TOC, Rock Eval analysis that the main reason behind implementing different strategies in this paper. Twenty-five samples were analyzed in terms of TOC, PI, HI, OI, S3, S2, Tmax and we could determine oil/gas prone samples (resource areas) and distinguish them from strata’s with very low organic matter content Larter & Douglas, (1982). These predictions are quite crucial to E&P stage hydrocarbon exploitation as they will lead to solid predictions and they would avoid substantial expenses and eliminate uncertainties. In conclusion, after in depth comparison and study of organic carbon content, hydrogen and oxygen index, Type of organic matter content and Maturity of organic matter, we determined that studied resource areas are considered for medium to large size hydrocarbon discoveries and should be considered favorable.

Thermal maturation, hydrocarbon generation and expulsion modeling of the source rocks in the Baiyun Sag, Pearl River Mouth Basin, South China Sea

The Baiyun Sag plays a role as the most important, largest deepwater target in petroleum exploration across the northern side of the South China Sea. Three sets of primary source rocks are developed in the Baiyun Sag: early Eocene middle-deep lacustrine source rock (EMD), late Eocene-early Oligocene inshore-shallow lacustrine source rock (OIS), and late Oligocene transitional source rock (LOT). A quantitative 3D model of the Baiyun Sag was constructed by using a stratigraphic framework based on 3D seismic interpretations and lithology well logging data of 66 wells. The geothermal parameters of the 3D model were determined and calibrated based on the measurements of seafloor temperature, formation temperature, and vitrinite reflectance from the wells. The source rock property parameters of the EMD, OIS, and LOT in the 3D model were set according to the results of the total organic carbon test and Rock-Eval pyrolysis analysis of the well samples. The thermal maturation, hydrocarbon generation and expulsion histories of the EMD, OIS, and LOT were reconstructed to study how the evolution of source rocks influenced the current oil accumulation. Modeling results show significant differences among evolutions of the EMD, OIS, and LOT in both vertical and plane directions. The majority of the EMD reached the threshold of hydrocarbon generation (Ro = 0.5%) at about 45 Ma and kept in the oil window (Ro = 0.5–1.3%) from 45 to 15 Ma. The majority of the OIS and LOT was not capable of generating hydrocarbon until 35 Ma and 20 Ma, respectively, and have not entirely passed the oil window at present. The EMD, OIS, and LOT in the south and east region of the Baiyun Sag matured faster than the ones in the north and west region. The total oil generation quantities of the EMD, OIS, and LOT are 3772.51 × 108 t, 585.93 × 108 t, and 517.83 × 108 t, respectively; and the total oil expulsion quantities of the EMD, OIS, and LOT are 1246.04 × 108 t, 47.85 × 108 t, and 18.49 × 108 t, respectively. The oil generated and expelled in the Sub-sag B1 accounts for 82% of the total oil generation and 96% of the total oil expulsion in the study area, respectively. However, only 4% of the oil originated from the EMD, and 3% of the oil generated in the Sub-sag B1, was expelled after the deposition of primary reservoir rocks (23.8–0 Ma). On the contrary, 69% of the oil expulsion of the OIS and all of the oil expelled from the LOT took place after 23.8 Ma. The EMD in the Sub-sag B2, the OIS in the Sub-sag B1 and B4, and the LOT in the Sub-sag B1 are favorable to current oil accumulation due to their high proportions and large quantities of the oil expulsion after the deposition of primary reservoir rocks.

Maturity evolution of Lower Cambrian Qiongzhusi Formation shale of the Sichuan Basin

The Lower Cambrian Qiongzhusi Formation source rock is one of the main sources of oil and gas in the Sichuan Basin. Owing to the controversial thermal history and the complex structural pattern in the Sichuan Basin, it is difficult to characterize the differences in maturity evolution and the timing of hydrocarbon generation periods of Qiongzhusi hydrocarbon source rocks in different tectonic zones. Based on the comprehensive analysis of the previous thermal history and denudation studies from the tectonic units of the basin, the thermal histories and denudation amount in main period of tectonic movement of a five-part tectonic development are obtained in this paper. Although the thermal history of different tectonic units varies, generally, the heat flow increased slowly in the early Paleozoic, and it experienced a peak heat flow at the end of the Middle Permian and decreased subsequently. Based on new thermal history and denudation data, the maturation of the Lower Cambrian Qiongzhusi Formation source rocks in the Sichuan Basin were modeled and their evolution can be classified into three patterns, which are: (1) continuous heating pattern in southern Sichuan, (2) Silurian-Permian heating cessation pattern in western Sichuan and northwest central Sichuan, and (3) Silurian-Permian and Triassic heating cessation pattern in the central uplift, northern structural zone and western part of the eastern structural zone. In addition, the key hydrocarbon generation periods of different tectonic units were determined in this study. Tectonic and sedimentary burial, together with high heat flow values during the Late Permian, were the main factors controlling levels of thermal maturity and thermal evolution models of the Qiongzhusi Formation. The present-day thermal maturity of the Qiongzhusi Formation depends on the thermal history and maximum burial depth before uplift in Late Cretaceous. However, the maturity evolution pattern affecting the key hydrocarbon generation stage was mainly related to the burial histories of source rocks in the Paleozoic. The thermal modelling of this study provides new evidence for the source rock evolution and new insight into Lower Paleozoic shale gas.

Thermal history of the Northwestern Argentina, Central Andean Basin, based on first-ever reported graptolite reflectance data

The thermal maturity from the Early Paleozoic strata in Northwestern Argentina was studied using reflected light microscopy and Rock-Eval analyses. The graptolites were collected from the Acoite and Lipeón formations, at the Los Colorados section, Cordillera Oriental, and the Huaytiquina, and Muñayoc sections, Puna highland, corresponding to the "Coquena" Formation and the Cochinoca-Escaya Magmatic-Sedimentary Complex. Rock-Eval parameters were unreliable due to the low TOC, S1, and S2 values. The Cordillera Oriental region sediments have low maturity based on low reflectance (%GRo= 0.63%–1.11%) and anisotropy of graptolites. In contrast, the higher graptolite reflectance of samples from the Muñayoc and Huaytiquina sections (%GRo= 5.57%–6.62%), in the Puna region, indicates considerably higher maturity. This could result from the combination of hydrothermal fluids with a temperature range from 336 °C to 358 °C, associated volcanism, and deformation related to tectonics events, which produced a higher geothermal gradient in the Puna. The Los Colorados section's thermal maturity modeling shows a better fit considering erosion episodes at the Late Paleozoic and Early Cenozoic. However, more studies about geothermal parameters and stratigraphy are necessary to corroborate these preliminary models and propose new approaches for the Puna region.

Geological process of Late Paleozoic shale gas generation in the eastern Ordos Basin, China: Revelations from geochemistry and basin modeling

During the Meso-Cenozoic, the eastern Ordos Basin (EOB) underwent a complex tectonothermal process influenced by the destruction of North China Craton, significantly affecting the thermal maturation of the Late Paleozoic source rocks. Tectonothermal modeling and maturation of coal-bearing shales were performed in the EOB to reveal the geological process of shale gas generation. Organic geochemical data for shales show that TOC values vary from 0.96 wt% to 21.36 wt% and Ro values range from 1.56% to 2.47%, as well as that organic matter mainly consists of type III kerogen—indicating excellent potential, and sufficient maturity, for gas generation. Thermal modeling suggests that heat flow in the EOB significantly increased as a result of intense magmatic activities during the Yanshanian orogeny, with peak values of 108 and 128 mW/m2 in the northern and southern regions, respectively. Consequently, great variations in maturation history are seen in different regions of the EOB, with the Taiyuan and Shanxi shales reaching the wet gas and dry gas stages, respectively, in the northern region and all shales reaching the dry gas stage in the southern region. Hydrocarbons were generated at 237 Ma and peaked around 162 Ma, whereas hydrocarbon expulsion began at 230 Ma and peaked at 131 Ma. Rapid subsidence in the Triassic brought the shales to the oil generation window and Early Cretaceous magmatic activities led to rapid maturation of shales, again reaching the gas generation stage. Accordingly, extremely high levels of thermal maturity are well documented in hydrocarbons' alkane composition and stable carbon isotope ratio. Gas geochemical data (δ13C1 vs. C1/C2+3, δ13C1 vs. C2+) imply that that hydrocarbons are from highly mature thermogenic gas generated mainly from humus, and this offers great support for thermal maturation modeling. Regionally, coal-bearing shales have been steadily uplifted and eroded since the Late Cretaceous, causing partial destruction of gas reservoirs. The tectonothermal evolution and hydrocarbon generation of EOB were controlled primarily by magmatic thermal effects resulting from the westward subduction of the Pacific plate.

Regional thermal maturity modelling of hydrocarbons along the deep-water Yucatan margin, southern Gulf of Mexico

Abstract The stratigraphy, structure and hydrocarbon potential of the deep-water Yucatan margin remains less understood than other margins of the Gulf of Mexico (GoM), as Yucatan has not been systematically mapped and has few well penetrations. Despite the presence of widespread oil slicks along the continent–ocean boundary, the maturity and distribution of source rock kitchen areas have not been well defined. This study uses a grid of 2D post-stack depth migration (PSDM) seismic profiles covering an area of approximately 120 000 km 2 to map the structure and stratigraphy, and to model thermal maturities of three potential Mesozoic source horizons. Thermal 1D modelling of six pseudo-wells, positioned along a dip profile, was performed using estimates of lithospheric thickness and thermal properties. Integrated 3D model results indicate that the principal Tithonian-age source rock reached the oil window within the diapiric salt province during the Oligocene–Miocene. Inherent model uncertainty was addressed using a range of thermal scenarios. The result of modelling was that deeply-buried, salt-related minibasins along the outer marginal trough are low risk and the uppermost slope is high risk for maturity. Large, salt-related structural traps are directly adjacent to oil kitchens within deeply-buried minibasins. Normal faults bounding minibasins provide effective vertical migration pathways as supported by the clustering of overlying oil slicks.

Thermal maturity modelling for the pre-Miocene source rocks in Ras Garra area, Suez rift Basin, Egypt

The main potential source rocks in the Ras Garra area of the Suez rift Basin are thought to be the pre-Miocene formations, Duwi, Esna, and Thebes, from the oldest to youngest. The total organic carbon content (TOC) ranges from 6.0 to 7.0 wt %, suggesting very good hydrocarbon generative potential. The hydrogen index (HI) ranges from 600 to 700 mg HC/g TOC and the kerogen is of type I/II. Burial and thermal maturity modelling indicates that the pre-Miocene source rocks started the oil generation as early mature stage in Langhian (14.3 Ma), and mid-mature stage in Pleistocene (2.4 Ma). The early mature stage is characterized by the depth to maturity of 1400 m, burial maximum temperature up to 87 °C and vitrinite reflectance (VR) up to 0.7% Ro. The mid-mature stage is characterized by the depth to maturity of 3007 m, burial maximum temperature up to 120 °C and vitrinite reflectance up to 0.75% Ro. The hydrocarbon generation and expulsion history is divided into two phases and Duwi source rock passed the second phase of hydrocarbon generation, and expulsion with transformation ratio (TR) of 29%. From 0.8 Ma until the present, the hydrocarbon generation and expulsion rates have been increased and the generated and expelled hydrocarbons are mainly oil with minor gases. The results show that the most important factor affecting the maturity of the source rocks and hydrocarbon generation and expulsion rates is the durations of early and mid-mature stages.

The role of Late Cretaceous wrench tectonics in hydrocarbon endowment in El-Gindi Basin, northern Western Desert, Egypt

Abstract Detailed subsurface mapping and structural analysis of El-Gindi basin indicate the hydrocarbon potentiality of the Cretaceous reservoirs. El-Gindi basin is a Late Cretaceous-Eocene basin located at El-Fayium district, northeastern Western Desert of Egypt. The overwhelming impact of the Late Cretaceous wrench tectonics was evident during the inversion of the Jurassic-Early Cretaceous rift-related basins along the North Western Desert of Egypt and subsequent deposition of a thick succession of Eocene sediments (~6000 ft Apollonia Formation) within El-Gindi Basin. These tectonic events were developing the oil maturity and trapping through the Late Cretaceous reservoir sequences, Upper Bahariya Formation (Cenomanian) and the Abu Roash “G” Member (Turonian). The Gindi Fault, however, is a NW-trending basement feature breaching El-Gindi basin and bounding several deeper half grabens in the western half of El-Fayium district. It has been reactivated during the Cretaceous, Eocene and probably Oligocene-Early Miocene times, where extended northwestward to the Qarun Field at the footslopes of the Kattaniya inverted basin forming several oil traps along its strike. The Late Cretaceous dextral wrenching developed a regional system of ENE-oriented structural ridges such as Kattaniya and Silah (bounded El-Gindi basin to the north and south, respectively), associated with a series of NE-to ENE- oriented right-lateral strike-slip faults enclosing some structural closures in between. The development of such ridges causing regional subsidence and subsequent deposition of the Apollonia Formation creating several structural hydrocarbon traps. In addition, the structural closures formed between the ends of right-lateral strike-slip faults at Silah High became potential sites for hydrocarbon accumulation. The thermal maturity model of El-Gindi basin suggests a phase of hydrocarbon expulsion occurred during or immediately after deposition of the Apollonia Formation, where the Lower and Upper Cretaceous sediments passing the oil window. According to the analysis of well cores, E-logs and seismic data, shallow marine to deltaic environments have been assigned for the Cenomanian-Turonian reservoir sediments. Moreover, the deposition within channels, point-bars and estuarine environments for the hydrocarbon bearing sandstone reservoirs within El-Gindi Basin was identified.

Thickness matters: Influence of dolerite sills on the thermal maturity of surrounding rocks in a coal bed methane play in Botswana

Abstract Global studies suggest that igneous intrusions usually have thermal aureole thicknesses between 30% and 250% of the intrusion thickness. Here, we discuss data and 1D thermal maturity models from nine coreholes (wells) drilled in Botswana to explore for coal bed gas. The coreholes penetrated multiple dolerite sills with thicknesses ranging from 1.2 m to 73.4 m. The sills intruded the sedimentary rocks in the Jurassic period and significantly affected the rank, properties and thermal maturity of Permian coals. The thermal influence of the sills extends for >5–53 m away from their contacts with surrounding rocks. The relatively thick (>13 m) sills have thermal aureole thicknesses of >31–137% of the sill thickness, in line with global observations. However, the relatively thin ( 1000% of the sill thickness, significantly larger than previously reported from most other locations affected by igneous intrusions. Thin sill intrusions in coals and organic-rich shales may lead to the generation of larger volumes of CH4, other hydrocarbon gases, and CO2 than previously thought, affecting the safety in coal mines and gas resources.

Burial and thermal history of the Lower Palaeozoic petroleum source rocks at the SW margin of the East European Craton (Poland)

Thermal maturity modelling was carried out in over sixty wells along the SW margin of the East European Craton (EEC). The burial and thermal history modelling of the EEC, using thermochronological data, allowed the construction of burial history maps showing its geological development in the Phanerozoic. These results have proved that the Ordovician and Silurian source rocks occurring at the SW margin of the EEC reached a maximum palaeotemperature in the Palaeozoic, mainly during Devonian–Carboniferous time and at the latest during the Silurian in the most westerly part of this margin, along the Teisseyre-Tornquist Zone. In Mesozoic and Cainozoic time, the Ordovician and Silurian strata generally were subjected to cooling or to very minor heating, certainly below the Variscan level. The maximum burial and maximum temperature of the Ediacaran–Lower Palaeozoic strata were reached during the Early Carboniferous in the Baltic Basin and during the Late Carboniferous in the Lublin area, and even in the Early Permian in the SE corner of the Lublin Basin. Thus, the main period of maturation of organic matter and hydrocarbon generation in the Ordovician and Silurian source rocks was in the Late Palaeozoic (mainly Devonian–Carboniferous) and in the westernmost zone along the Teisseyre-Tornquist line at the end of the Silurian.