Oil Generation Zone Research Articles

Quantification of C10–C14 Adamantanes in High-Viscosity Naphthenic Oils

The paraffin–naphthenic fractions (with boiling points below 310°C) prepared from three high-viscosity naphthenic crude oils, classified as types B1 and B2 (according to Petrov’s classification), were subjected to thiocarbamide complexation. The molecular composition of polycyclic hydrocarbon biomarkers and C11–C13 adamantanes in the oil samples suggested a predominantly marine genotype of the precursor organic matter (OM). The molecular composition also suggested source rocks of a clayey type. Nonetheless, the biomarkers detected in one sample indicated some contribution of terrigenous components to the precursor OM. All the oils were generated under the conditions of the main oil generation zone and, presumably, underwent microbial transformations in the deposits. The compositions of C10–C14 adamantanes in the initial paraffin–naphthenic fraction, in the thiocarbamide adduct, and in the filtrate that remained after the adduction were comparatively characterized for each oil sample. The test conditions allowed us to have adamantane more than 100-fold concentrated (in the adduct), to quantify it in the oils, and to evaluate the concentrations of C11–C14 alkyladamantanes in the oils using adamantane as an internal standard. C10–C14 adamantanes exhibited selective adduction ability, with the extraction ratios of individual components being different. Taking into account these extraction ratios, the component concentrations were evaluated on crude oil basis: 2.7 to 7.6×10–3 wt % for adamantane and 87 to 267×10–3 wt % for total C10–C14 adamantanes. The identification of adamantanes in the initial paraffin–naphthenic fractions, adducts, and filtrates revealed the presence of some other tricyclanes (probable precursors of alkyladamantanes) as well as decaline homologues. Like adamantanes, these compounds exhibited selective ability to complex with thiocarbamide.

GEOCHEMICAL CHARACTERISTICS OF THE ORGANIC MATTER OF THE RIPHEAN DEPOSITS OF THE UST’-MAYSKAYA PARAMETRIC WELL FOR ASSESSMENT OF THE OIL AND GAS POTENTIAL

The investigation of the dispersed organic matter of the rocks in the Ust’-Maiskaya wildcat area was conducted. Data on the features of dispersed organic matter composition in the range of 2868.731-3057.68 m are presented. Alkanes, mono-, bi-, tri-, tetra- and pentacyclic arenes, bi-, tri-, tetra- and pentacyclanes, tetracyclic naphthenoaromatic hydrocarbons, dibenzothiophenes have been identified among hydrocarbons studied by means of gas chromatography - mass-spectrometry. Perylene and traces of nickel metalloporphyrins and perylene were also determined by means of spectrophotometry. It is shown that the initial organic matter was formed under the conditions of reduction and suboxidation, with a significant contribution from both terrestrial vegetation and phytoplankton. The presence of nickel porphyrin and perylene complexes in some sections of the log suggests the shallowness of the sedimentation basin and the proximity of the coastline during OM accumulation. The calculated vitrinite reflectance indicates that the differences observed for the MK2 stage of catagenesis correspond to the main zone of oil generation.

Source Rocks’ Potentiality of the Sargelu Formation (Middle Jurassic) in the Taq Taq Oilfield, Kurdistan Region, Iraq

Thirty rock samples were selected from the well Tq-1 that penetrated the Jurassic beds in the Taq Taq Oilfield to be studied the source rock potentiality of the Sargelu Formation. The formation is characterized by three types of microfacies, namely, foraminiferal packstone, grainstone microfacies, fossiliferous packstone microfacies, and foraminiferal wackestone which were deposited in an environment extending from middle to outer carbonate ramp. An average of 3.03 wt.% of total organic carbon was obtained from a Rock Eval pyrolysis analysis carried out on 24 selected rock samples. The petrographic analysis for such organic matters revealed that they are of kerogen types III and IV and they are currently in a post-mature state. Pyrolysis parameters showed that limited generation potential was remained for these sources to expel generated hydrocarbons. The palynological study showed that Amorphous Organic Matter forms the highest percentage of organic matter components with more than 70%, followed by phytoclasts with 10 – 25 % and palynomorphs of less than 10%. The organic matters within the Sargelu Formation are deposited at the distal part of the basin under suboxic to anoxic condition. The color of the organic matter components, examined under transmitted light, showed Thermal Alteration Index values between 3+ and 4-. Such values may indicate that these organic matters are thermally at the end of the liquid oil generation zone and beginning of condensate-wet gas generation zone. The thermal maturity of the Sargelu Formation depending on the calculated VRo% revealed that the formation in the studied oilfield is currently at the peak of the oil generation zone. The Sargelu Formation in the studied field is considered as an effective source rock, as it has already generated and expelled hydrocarbons.

The Bamaga Basin: a frontier play in a non-frontier location

The undrilled, offshore Bamaga Basin (pre-Jurassic) is overlain by two previously explored sedimentary basins: Carpentaria (Jurassic–Cretaceous) and Karumba (Tertiary). In 1984, Duyken-1, the only well in the Gulf of Carpentaria, 120km southwest of the Bamaga Basin, tested the Carpentaria and Karumba successions but not the deeper Bamaga Basin, which at the time was unrecognised. 2D regional seismic data acquired in 2012, and a second infill seismic survey in 2014, confirmed the presence of a sedimentary succession in the Bamaga, probably of early–middle/late Paleozoic age, and identified an intriguing, complex structural history and large potential petroleum traps. Basin modelling in the centre of the Bamaga Basin where the sedimentary section is deepest shows that the sediments are mature for petroleum generation with the hydrocarbon phase being either oil or gas, although gas is more likely, especially below 2000m. Analysis of the available data indicates that in the oil generation zone there are six targets with the potential to hold prospective resources (3U) of more than 250 million stock barrels (MMstb) of oil each, the largest of which could hold as much as 663 MMstb of oil. In the gas generation zone, there are nine targets with the potential to hold prospective resources (3U) of 1 trillion cubic feet (Tcf) or more gas each, the largest of which could hold as much as 2.5 Tcf gas. The water depth (60m) and closeness to shore (150km) make it operationally and commercially attractive.

Petroleum source rocks of the Silurian deposits on the Chernov swell (Timan‑Pechora basin)

Silurian source rocks are among the least studied in the Timan-Pechora basin. This is mainly due to their occurrence at great depths (3.0–4.5 km) and the limited penetration of this stratigraphic interval by wells. Another source of information is the outcrops of the Silurian, which are known in the eastern and northeastern parts of the Timan-Pechora basin. The studied section of the Silurian deposits is exposed on the Padimeityvis River, located on the Chernov swell in the northeastern part of the basin. This article is devoted to the study of Silurian source rocks based on the results of lithological, coal petrographic studies and geochemistry of organic matter. The studied section is composed of carbonate and clay-carbonate deposits formed in shallow-water shelf conditions. Most of the section, composed of microcrystalline and microcrystalline with bioclasts limestones, is characterized by low concentrations of organic matter (Corg is generally less than 0.3 %). Elevated Corg contents (up to 1.16 %) are characteristic of clay-carbonate rock varieties, which make up about 20 % of the section. Sediments with increased concentrations of organic matter were formed in isolated and deepened areas of the bottom of the shallow-water basin as a whole. Assessment of the catagenetic transformation based on Rock-Eval pyrolysis data, coal petrographic studies, and conodont color indices showed that organic matter reached the conditions of the middle-end of the main oil generation zone (gradation MC2‑MC3). The obtained geochemical characteristics (Corg, S2, HI), taking into account a certain level of organic matter maturity, indicate that the Silurian source rocks had an average hydrocarbon potential.

ПЕРСПЕКТИВЫ НЕФТЕГАЗОНОСНОСТИ АНТИКЛИНАЛЬНОЙ ЗОНЫ ХАЛИ-НЕФТ ДАШЛАРЫ В СВЯЗИ С ЕЁ ПАЛЕОТЕКТОНИЧЕСКИМИ УСЛОВИЯМИ

Актуальность. Абшеронский нефтегазоносный район, где были проведены исследования, является одним из продуктивных в Азербайджане. Цель поисково-разведочных работ в основном заключается в увеличении добычи углеводородов, а это достигается выявлением новых нефтегазоносных объектов. С этой точки зрения в антиклинальном поясе Хали‒Нефт Дашлары в разрезе палеоген-миоценовых отложений выявление залежей, связанных с антиклинальными и неантиклинальными типами ловушками, имеет важную практическую особенность и это однозначно сыграет немаловажную роль в повышении добычи нефти и газа в республике. Наши исследования были проведены по определяющим нефтегазоносность критериям: геотермическим, литофациальным, тектоническим, палеотектоническим и т. д., по стратиграфическому разрезу палеоген-миоцен и плиоцена для определения новых объектов. Цель: определить с геотермической точки зрения в какой зоне нефтегазообразования в настоящее время находятся отложения продуктивной толщи и, в соответствии с этим, уточнить перспективность зоны, а также исследовать распространенность неантиклинальных ловушек в связи с палеотктоническими особенностями и конседиментационным развитием зоны. Объекты: отдельные структуры, представляющие антиклинальную зону Хали‒Нефт Дашлары, свиты нижнего отдела продуктивной толщи. Методы. Изменения общей мощности и песчанистости отложений продуктивной толщи в исследуемых структурах были проанализированы в локальном и региональном направлениях, были построены соответствующие диаграммы, отражающие закономерности изменения мощности и песчанистости по свитам. Наряду с этим были построены палеопрофили, отражающие палеотектоническое развитие структур антиклинальной зоны Хали‒Нефт Дашлары. Результаты. Построение графика скорости осадконакопления и, в связи с этим, анализ данных, изучение палеотемпературных условий Пираллахи-Келькорской впадины и проведенный анализ позволяют определить время нахождения отложений как продуктивной толщи, так и нижележащих отложений миоцена, палеогена и мезозоя в главной зоне нефтегазообразования, а также сопоставить главные этапы миграции со временем образования структур в пределах данной территории. Результаты всех исследований, проведенных в этом направлении, позволяют утверждать, что область исследований и ее окрестности также являются перспективными с точки зрения нефтегазоносности.

ASSESSMENT THE HYDROCARBON POTENTIALITY OF THE MIDDLE JURASSIC SARGELU FORMATION, NORTHERN IRAQ

The Middle Jurassic Sargelu Formation is evaluated for its hydrocarbon generation potential in three wells near Duhok Governorate, Northern Iraq using ten borehole cutting samples analyzed by Rock-Evil pyrolysis, gas chromatography coupled with gas chromatography-mass spectrometry (MSS) and stable isotope. The results showed that the total organic carbon and genetic potential of the formation ranges from 0.5 to 11.6 wt.% and 1.7 to 66.3 mg HC/g of rock, respectively indicating fair to excellent source rock petroleum potential, with hydrogen index values between 270 to 555 mg HC/g TOC. The results also show kerogen Types II and mixed II/III reflecting thermal maturity within the oil generation zone. The estimated ratios of Pr/Ph, Pr/n-C17 and Ph/n-C18 ­­­­­­ from the extracted bitumen reveal primary accumulations of marine organic matter under reducing conditions. The δ13CSat and δ13CAro for the extracted bitumen range from -29.5 to -27.5‰ and -28.4 to -27.2‰, respectively. The biomarkers results indicate a significant contribution of marine organic matters preserved under relatively anoxic conditions.

The heat flow, thermal history of the oil source Lower Jurassic Togurskaya suite and oil-and-gas potential of the Paleozoic of the Koltogor mezodepression(southern segment of the Koltogor-Urengoy paleorift)

Input of the pre-Jurassic («Paleozoic») oil is important to the reproduction of the in-situ resources base of Western Siberian oil and gas extraction. Prospecting and forecasting studies of the pre-Jurassic reservoirs in the territory of the Koltogor mezodepression and structures of its surrounding — in the north-western part of Tomsk Region, in the zone of the southern segment of the Koltogor-Urengoy Permian-Triassic paleorift are of interest. The pre-Jurassic oil and gas complex(oil and gas bearing horizon of the contact zone— OGBHCZ and, actually, the Inner Paleozoic) is assigned along with the Cretaceous (the Neocomian), Upper Jurassic, Middle Jurassic and Lower Jurassic oil and gas complexes in the study area. It is accepted that the Upper Jurassic Bazhenov suite is the oil source formation for the Middle Jurassic, Upper Jurassic and Cretaceous oil and gas complexes, as well as Togurskaya suite — for the Lower Jurassic and pre-Jurassic deposits. Researches are carried out in the context of the methodology of the sedimentary and migrational theory of naftidogenesis. Spatiotemporal localization of the generation foci of Togurskaya oil is performed with the original method of paleotemperature modeling. The heat flow in sections of 82 deep wells is calculated at the first stage of modeling. At the following stages the oil source suite geotemperatures are directly figured up in key moments of geological time. The integral express-assessment of realization of generation potential of the suite is performed on the base of calculated data about time of the oil source suite residence in the main oil generation zone and its geotemperatures. Vewing to the concept about predominantly vertical migration of hydrocarbons the forecasting is carried out in the outline of the oil source suite distribution. Schemes of distribution of Togurskaya oil accumulation density are built and zoning of deposits is performed taking into account the thickness and quality of potential reservoirs of the pre-Jurassic deposits. Oil geological zoning of the pre-Jurassic complex and ranking areas according to the degree of prospect abilities were accomplished. The most forward-looking zone for prospecting in the weathering crust reservoir is the area, which comprises the eastern part of the Cheremshanskaya mezzo saddle and its articulation with the northern side of the Koltogor mezodepression and the western slope of the Srednevasyuganskiy megaswell (in the order of 3500 km 2 ). The most optimistic forecast for the Inner Paleozoic reservoir is made for the same areas as for the weathering crust, less optimistic — for the Severo-Chkalovskiy incised valley and its articulation with the Murasovskiyhigh and Trassovoe dome-shaped uplift (in the order of 5700 km 2 ).Consistency of the forecast with established direct evidence of oil saturation amounts to 70 %. Detailed map of the heat flow density in the study area showed that the trench of the Koltogor-Urengoy graben-rift does not have significant manifestation in enhanced values of the heat flow. The article demonstrates methodological approaches and complex technology of zonal forecasting of oil and gas potential of the pre-Jurassic basement of Western Siberia, which are working out by Tomsk research school of Geothermy.

Mixgenetic concept of of oil and gas fields formation in basement and sedimentary cover on the shelf of South Vietnam

According to the geodynamic model of oil and gas formation, the most favorable conditions for the oil and gas fields are formed in the mobile zones of the earth’s crust, especially in areas of active continental margins, characterized by high seismicity, the presence of deep faults, the development of subduction and riftogenic processes. Therefore, it is logical that most of the world’s oil and gas deposits are concentrated in rifts or in the vicinity of paleo- and modern subduction zones. The study of the unique oil deposits in the granite basement of the White Tiger field, using data from other fields in the world, allows concluding that the formation of oil deposits in the basement can occur not only due to the resources of adjacent oil and gas deposits. Taking into account modern geodynamic ideas, in the context of the Earth’s internal geospheres, at least three oil generation zones can be distinguished: mantle-asthenospheric abiogenic synthesis; subduction-dissipative biomineral synthesis; stratospheric-biogenic synthesis. Obviously, all these three zones, as a single open system for the generation of hydrocarbons, will be interconnected only in conditions of deep faults, active continental margins and other parts of the Earth’s crust. This suggests that there are deep generation zones, which are currently fueling the developed fields.

Geochemical features of bitumen shows in the Lower-Middle Devonian deposits of the Northern-Western part of Kotelny Island (Novosibirsk Island Archipelago) v

The work presents the results of organic matter (OM) study of rocks, the composition, chemical structure of chloroform bitumen (CB), their fractions and the nature of the hydrocarbon biomarkers distribution in samples taken from outcrops. The obtained results confirmed the existing idea of ​​the domanicoid nature of OM and the high oil and gas potential of the studied deposits. According to our data, the aquagenic type of OM is indicated by a high content of Corg, a high yield of CB, a high content of oils in the composition of synbitumoids, and the predominance of relatively low molecular weight n-alkanes with a maximum at nС15-18. A sufficient maturity of bitumen can be judged by CPI coefficients close to unity and low absorption coefficients of oxygen-containing groups and bonds in the CB, thus deposits entered the main oil generation zone and generated liquid hydrocarbons that could migrate and form clusters. According to the data of Chromato Mass Spectrometry, it is shown that a feature of the composition of CB from the Lower Devonian sediments is the presence of high concentrations of dibenzothiophenes, in contrast to the Middle Devonian, which may be associated with the formation of the initial OM in an environment with higher hydrogen sulfide contamination of sediments. It has been suggested that naphthides generated by aquagenic OM of the Lower Devonian deposits can be enriched with dibenzothiophenes. The studied bitumen shows are mainly syngenetic in nature and have been influenced by hypergenic oxidation (judging by the nature of the IR spectra of resinous components) and contact metamorphism. According to the characteristics of the distribution of saturated hydrocarbons, it was shown that, in the Middle Devonian, bitumen occurrences along with chemical oxidation were affected to a different degree of bacterial oxidation processes, in contrast to the Lower Devonian bitumen shows. The results can be used to assess the generation potential of oil source strata and to forecast the prospects of oil and gas potential in the shelf of the eastern sector of the Russian part of the Arctic.

Source rock assessment within a sequence stratigraphic framework of the Yogou Formation in the Termit Basin, Niger

A preliminary sequence stratigraphic geochemical investigation was carried out to assess the areal distribution and hydrocarbon generation potential of marine mudstones of the Upper Cretaceous Yogou Formation in the Termit Basin, Niger. A total of three third‐order sequences (YSQ1, YSQ2, and YSQ3, from bottom to top) and nine systems tracts were identified in the Yogou Formation. Mudstones of each sequences are widely distributed throughout the study area with their maximum cumulative thickness of ~600–900 m in the Dinga and Moul depressions. The ΔlogR method was applied to establish a prediction model for predicting the total organic carbon (TOC) content of the Yogou Formation mudstones. The results of this source rock evaluation indicate that thick offshore mudstones with fair to good hydrocarbon generation potential and dominated Type II to Type III kerogen widely occur in YSQ1, YSQ2, and in the LST (lowstand systems tract) and TST (transgressive systems tract) of YSQ3, while the thin lower shoreface mudstone intervals in the HST (highstand systems tract) of YSQ3 are characterized by good to excellent hydrocarbon generation potential, dominated by Type II kerogen. The present‐day thermal maturation level of source beds from the YSQ3, YSQ2, and YSQ1 has overpassed the main zone of oil generation in the depocenter of Dinga Depression, whereas the YSQ3 and part of YSQ2 source beds were still within the oil window in the depocenter of Moul Depression. The organic matter richness and hydrocarbon generation potential of source beds varies within the Yogou Formation because of changes in organic matter source during evolution of Western Africa rift basins and global sea‐level fluctuations. This study provides a practical sequence stratigraphic geochemical framework which will give a better understanding for the geochemical characteristics of source rock and support improved assessment of petroleum resources.

Distinguishing Oil Generation Zones by IR Spectra of Chloroform Bitumens within Mezozoic and Cenozoic Deposits of the Azov–Kuban Oil-and-Gas Basin

The use of IR spectrometry for examining the structural and group composition of chloroform bituminous components of dispersed organic matter in Mesozoic and Cenozoic deposits of the Azov–Kuban oil-and-gas basin resulted in obtaining significant information on the conditions of sedimentation and diagenesis of the deposits that enclose organic matter, as well as on its degree of katagenetic transformation. The IR spectra, which conformed to 15 genetic types of chloroform bitumen, allow one to distinguish the zones that contain no oil-and-gas source rocks, along with those with generation of hydrocarbons and those with completed processes.

Use of infrared spectrophotoscope examination of bituminous components for determination of the oilgeneration zones in the mesozoic and Cenozoic deposits of the Azov-Kuban petroleum basin

Use of infrared spectrometry method for examination of bituminous components of dispersed organic matter in Mesozoic and Cenozoic deposits of the Azov-Kuban petroleum basin gave very important information about conditions of formation of source rocks containing organic matter and the degree of its diagenetic or catagenetic transformation level. Character of infrared spectrums represented by 15 genetic types of chloroform bitumen allows to subdivide the zones with the source beds absence, zones of oil generation and zones where this processes have come to the end.

Integration of the outcrop and subsurface geochemical data: implications for the hydrocarbon source rock evaluation in the Lower Indus Basin, Pakistan

The present study details the hydrocarbon source rock geochemistry and organic petrography of the outcrop and subsurface samples of the Middle Jurassic Chiltan Formation and the Lower Cretaceous Sembar Formation from the Sann #1 well Central and Southern Indus Basin, Pakistan. The total organic carbon (TOC), Rock–Eval pyrolysis, vitrinite reflectance (Ro) % and Maceral analysis techniques were used and various geochemical plots were constructed to know the quality of source rock, type of kerogen, level of maturity and migration history of the hydrocarbons. The outcrop and Sann #1 well data on the Sembar Formation reveals poor, fair, good and very good quality of the TOC, type II–III kerogen, immature–mature organic matter and an indigenous hydrocarbon generation potential. The outcrop and Sann #1 well data on the Chiltan Formation show a poor–good quality of TOC, type II–III kerogen, immature–mature source rock quality and having an indigenous hydrocarbon generation potential. The vitrinite reflectance [Ro (%)] values and Maceral types [fluorescent amorphous organic matter, exinite, alginite and inertnite] demonstrate that maturity in both Sembar and the Chiltan formation at surface and subsurface fall in the oil and gas generation zone to cracking of oil to gas condensate zone. Recurrence of organic rich and poor intervals within the Sembar and Chiltan formation are controlled by the Late Jurassic thermal uplift preceding the Indo-Madagascar separation from the Afro-Arabian Plate and Early Cretaceous local transgressive–regressive cycles. From the current study, it is concluded that both Sembar and Chiltan formation can act as a potential hydrocarbon source rock in the study area.

Oil Shale Prospects of Imo Formation Niger Delta Basin, Southeastern Nigeria: Palynofacies, Organic Thermal Maturation and Source Rock Perspective

The search for oil and gas in the Nigerian inland basins and efficacy of the unconventional oil shale in hydrocarbon generation have necessitated the palynofacies characterization, thermal maturation and source rock evaluation of the Imo Formation, updip Niger Delta basin to determine its palynofacies constituents and oil shale potential. The standard acid maceration technique, palynofacies description as well as palynomorph colour index chart systematically compared to thermal alteration index and vitrinite reflectance index values were utilized for the study. The palynofacies components of the Imo Formation is dominant of yellow and brown amorphous organic matter, marine taxa, opaque particles, with few dark brown structured phytoclasts and terrestrial microflora. The source rock content is interpreted as Kerogen Type II - oil prone with abundant marine palynomorphs, amorphous organic matter and few terrestrial microfossils. The spore/pollen colour of the strata is light brown signifying mature and oil generation zone. This correlates to thermal alteration index (TAI) 2+ to 3 and vitrinite reflectance index (%Ro) values of 0.5% to 1.0%. The abundance of the amorphous organic matter of marine origin suggests good source rock which indicates good oil shale prospects. The oil shale prospects of the Imo Formation in the study area are hindered by the low abundance of the palynofacies associations. Field evidence indicate that the grey to slightly light grey shales in hand specimen, as against black carbonaceous shales rich in organic matter suggests that the environmental conditions affected the quality of the organic kerogen. The oil yields may be compensated by the great volume of marine shale deposited in the formation and the abundance of amorphous organic matter of marine origin which is known to be an excellent indicator of oil. The palynofacies model enhances the understanding of palynofacies events and oil shale quality which can be tied to the development of unconventional oil shale, oil fields and subsequent exploration drive in the area.

Zoning of the Bazhenov suite and clinoforms of Neocomian according to the density resources of shale and primaryly-accumulated oil (Nurol megadepression as an example)

Complex representation of the methodology, of search criteria and basis for the use of data of Geothermal technology for solution of the problem of forecasting oil and gas potential has been given. The technology is based on the method paleotemperature modeling, allowing to reconstruct the thermal history of maternal deposits and allocate geothermal criteria and mapping the source of oils generation. The resource estimate is determined by an integral indicator, which is directly dependent on the time of maternal suite location in the main zone of oil generation and on geo-temperature of the zone. Perspective areas and plots for search of the shale (accumulated in situ) Bazhenov oil and of primaryly accumulated oil of terrigenous Achimov Neocomian reservoir Nurol megadepression (Western Siberia) have been identified. Consistency of zoning has been argued by the oil shows and flows of oil in deep wells of the intervals of the parent rocks and clastic reservoirs Shale resource potential of the Bazhenov Formation and difficult-to-determine resources of Neocomian are the subject to priority economic development in accordance with the new strategy of development of hydrocarbon resource base of the Russian Federation.

Geochemistry of cretaceous rocks, Pakistan: I. Biomarker approach to assess thermal maturity of OM

ABSTRACTThe sediment samples from cretaceous sequences, Lower Indus basin, were analyzed using diagnostic biomarkers to predict the thermal maturity of organic matter. The sediments were tested for aliphatic biomarkers ratios, i.e. homohopanes and steranes isomerization ratios and carbon preference indices. These biomarker maturity parameters reveal that the Lower Goru (including its members Upper shale, Lower shale, and Talhar shale) and Sembar Formations in the Lower Indus Basin of Cretaceous age have reached the maturity level equivalent to the main zone of hydrocarbons generation, whereas Parh and Upper Goru Formations are immature and far from oil window. Geochemical analyses carried out stresses that hydrocarbons derived from the Sembar and Lower Goru Formations (particularly deeper Members) are within the zone of peak oil generation.

Optical thermal maturity parameters and organic geochemical alteration at low grade diagenesis to anchimetamorphism: A review

Sedimentary organic matter derives from biological precursor material which undergoes systematic, irreversible changes upon burial which mainly reflect increasing diagenetic temperatures, although other factors have also an influence. Several parameters have been established in the last decades to determine the palaeotemperature history of sedimentary rocks based on geochemical or petrographical methods. Organic matter is the most temperature-sensitive solid constituent in sedimentary rocks and vitrinite reflectance (VR), miospore and conodont colour alteration are among the most widely used optical maturity parameters. Despite tremendous interest in estimating maturity parameters in the oil generation zone as well as for high grade diagenesis and metamorphism and despite decades of research only a few of these methods have been well established and compared to each other by now. The focus of this review is on some new aspects with respect to organic matter maturation and optical palaeotemperature parameters, especially for high grade diagenesis and anchimetamorphism. Such a discussion might be a prerequisite for a better understanding of palaeotemperature assessments in different sedimentological and/or geotectonic settings and useful for different fields in applied sciences. Furthermore, suggestions for further research are discussed.

A basin modeling and organic geochemistry study in the Vallecitos syncline, San Joaquin Basin, California

The Vallecitos syncline is a westerly structural extension of the San Joaquin Basin. The Vallecitos oil field, comprised of eight separate areas that produce from Cretaceous and Paleogene reservoirs, accounted for 5.4 MMB of oil and 5.6 BCF associated of gas through 2010. However, exploration for oil and gas in the Vallecitos area is challenging due to structural complexity and limited data. The purpose of this study is to evaluate whether source rocks are actively generating petroleum in the Vallecitos syncline and to improve our understanding of burial history and timing of hydrocarbon generation. We conducted biomarker analysis on twenty-two oil samples from the Vallecitos syncline. Source-related biomarkers show two genetic groups of oil, which originated from two different source rocks. These results differ from earlier published interpretations in which the Kreyenhagen Formation is the only source rock in the Vallecitos syncline, and suggest that the Cretaceous Moreno Formation in the syncline also is an active source rock.Stratigraphic evidence and modeling suggest that late Cenozoic episodes of erosion due to folding and uplift removed significant overburden on the flanks of the syncline. To better understand the petroleum systems and clarify the total active source rocks in the area, 2D burial histories were generated through the Vallecitos syncline. A published cross-section through the deepest part of the syncline was selected to conduct thermal history, basin evolution, and migration analyses. The 2D model results indicate that the lower Kreyenhagen Formation has various maturities within the formation at different locations in the present-day syncline. The basal part of the Kreyenhagen Formation is in the dry gas window and maturity decreases away from the central part to the flanks. It remains immature along shallow portions of the present-day flanks. In contrast, the basal part of the Moreno Formation achieved extremely high maturity (past the gas generation zone) but is in the oil generation zone on the flanks of the syncline at shallow depth. All of our geochemical and 2D model results suggest that there are two active source rocks in the Vallecitos syncline. Accordingly, we propose that there are two active petroleum systems in the Vallecitos syncline.

Upper Jurassic source rocks in the Sab’atayn Basin, Yemen: Depositional environment, source potential and hydrocarbon generation

ABSTRACT The Sab’atayn Basin is a major hydrocarbon province in Yemen. Important source rocks occur in Upper Jurassic units (Lam Member of the Madbi Formation, Sab’atayn Formation). Depositional environment, source potential and maturity of the source rocks were investigated using 60 cuttings samples from the Tagina South-1 Well. All samples were analysed for bulk parameters (total organic carbon (TOC), carbonate, sulphur, RockEval). A subset of samples was selected for biomarker analysis, pyrolysis-gas chromatography and isotope investigations. A carbonate-rich, euhaline, dysoxic to anoxic environment prevailed during deposition of the Lam Member. Bituminous shales within the overlying Sab’atayn Formation formed in a hypersaline, strictly anoxic depositional setting. Changes in the phytoplankton communities coincide with the outlined changes in the water body. Upward decreasing δ13C values suggest changes in carbon cycling due to changing redox conditions. The Lam Member, at least 500 m thick, is a good to very good source rock with an average TOC of 2.2%. The hydrogen index is controlled by maturity, but reaches 300 mg HC/g TOC in samples with low maturity (type II-III kerogen). The Lam Member produces sulphur-poor, paraffinic-naphthenic-aromatic low-wax oil. Bituminous shales in the Sab’atayn Formation contain up to 11% TOC and a type II (to III) kerogen (HI: up to 427 mg HC/g TOC). These shales are excellent sources for oil (and gas), but their source potential is limited by their relatively low thickness. Both, bituminous shales in the Sab’atayn Formation and the Lam Member are mature. The maturity of the deepest drilled part of the Lam Member is close to the zone of main oil generation. Numeric models show that Cenozoic heat flow is about 50 mW/m2. An increase in heat flow during Jurassic rifting is likely, but cannot be quantified. Major hydrocarbon generation occurred during Eocene–Oligocene times (assuming a Late Cretaceous heat flow of 50 mW/m2) or during both, Late Cretaceous and Eocene–Oligocene times (assuming a Late Cretaceous heat flow of 68 mW/m2).