Black shales in Ukraine – A review

As a result of a long-lasting and complex geological history, organic-matter-rich fine-grained rocks (black shales) with widely varying ages can be found on Ukrainian territory. Several of them are proven hydrocarbon source rocks and may hold a significant shale gas potential.Thick Silurian black shales accumulated along the western margin of the East European Craton in a foreland-type basin. By analogy with coeval organic-matter-rich rocks in Poland, high TOC contents and gas window maturity can be expected. However, to date information on organic richness is largely missing and maturity patterns remain to be refined.Visean black shales with TOC contents as high as 8% and a Type III-II kerogen accumulated along the axis of the Dniepr-Donets rift basin (DDB). They are the likely source for conventional oil and gas. Oil-prone Serpukhovian black shales accumulated in the shallow northwestern part of the DDB. Similar black shales probably may be present in the Lviv-Volyn Basin (western Ukraine).Middle Jurassic black shales up to 500 m thick occur beneath the Carpathian Foredeep. They are the likely source for some heavy oil deposits. TOC contents up to 12% (Type II) have been recorded, but additional investigations are needed to study the vertical and lateral variability of organic matter richness and maturity.Lower Cretaceous black shales with a Type III(-II) kerogen (TOC > 2%) are widespread at the base of the Carpathian flysch nappes, but Oligocene black shales (Menilite Fm.) rich in organic matter (4–8% TOC) and containing a Type II kerogen are the main source rock for oil in the Carpathians. Their thermal maturity increases from the external to the internal nappes.Oligocene black shales are also present in Crimea (Maykop Fm.). These rocks typically contain high TOC contents, but data from Ukraine are missing.     

Source rock characteristics and biostratigraphy of the Lower Silurian (Telychian) organic-rich shales at Akyaka, central Taurus region, Turkey

The Akyaka section in the central Taurus region in the southern part of Turkey includes the organic matter and graptolite-rich black shales which were deposited under dysoxic to anoxic marine conditions in the Early Silurian. A biostratigraphical analysis, based on graptolite assemblages, indicates that the sediments studied may well be referable to the querichi Biozone and early Telychian, Llandovery. A total of 15 samples have been subjected to Leco and Rock-Eval pyrolysis and graptolite reflectance measurements for determination of their source rock characteristics and thermal maturity. The total organic carbon content of the graptolite-bearing shales varies from 1.75 to 3.52 wt% with an average value of 2.86 wt%. The present Rock-Eval pyrolytic yields and calculated values of hydrogen and oxygen indexes imply that the recent organic matter type is inert kerogen. The measured maximum graptolite reflectance (G_Rmax %) values are between 5.04% and 6.75% corresponding to thermally over maturity. This high maturity suggests a deep burial of the Lower Silurian sediments resulting from overburden rocks of Upper Paleozoic to Mesozoic Upper Cretaceous and Middle-Upper Eocene thrusts occurred in the region.     

Generation characteristics of Mesozoic syn- and post-rift source rocks,Bonaparte Basin,Australia: New insights from compositional kinetic modelling

Potential source rocks on the Laminaria High, a region of the northern Bonaparte Basin on the North West Shelf of Australia, occur within the Middle Jurassic to Lower Cretaceous early to post-rift sequences. Twenty-two representative immature source rock samples from the Jurassic to Lower Cretaceous (Plover, Laminaria, Frigate, Flamingo and Echuca Shoals) sequences were analysed to define the hydrocarbon products that analogous mature source rocks could have generated during thermal maturation and filled the petroleum reservoirs in the Laminaria High region. Rock-Eval pyrolysis data indicate that all the source rocks contain type II–III organic matter and vary in organic richness and quality. Open system pyrolysis-gas chromatography on extracted rock samples show a dominance of aliphatic components in the pyrolysates. The Plover source rocks are the exception which exhibit high phenolic contents due to their predominant land-plant contribution. Most of the kerogens have the potential to generate Paraffinic–Naphthenic–Aromatic oils with low wax contents. Bulk kinetic analyses reveal a relatively broad distribution of activation energies that are directly related to the heterogeneity in the kerogens. These kinetic parameters suggest different degrees of thermal stability, with the predicted commencement of petroleum generation under geological heating conditions covering a relatively broad temperature range from 95 to 135 °C for the Upper Jurassic−Lower Cretaceous source rocks. Both shales and coals of the Middle Jurassic Plover Formation have the potential to generate oil at relatively higher temperatures (140–145 °C) than those measured for crude oils in previous studies. Hence, the Frigate and the Flamingo formations are the main potential sources of oils reservoired in the Laminaria and Corallina fields. Apart from being a reservoir, the Laminaria Formation also contains organic-rich layers, with the potential to generate oil. For the majority of samples analysed, the compositional kinetic model predictions indicate that 80% of the hydrocarbons were generated as oil and 20% as gas. The exception is the Lower Cretaceous Echuca Shoals Formation which shows the potential to generate a greater proportion (40%) of gas despite its marine source affinity, due to inertinite dominating the maceral assemblage.     

Speculative petroleum systems of the southern Pelotas Basin,offshore Uruguay

The Pelotas Basin of Brazil and Uruguay represents a frontier basin with under-explored hydrocarbon potential. Although oil and gas accumulations have yet to be identified, only 21 exploratory wells have been drilled in an area of more than 330,000 km², 20 of which are located in the Brazilian portion of the basin. A detailed study of the petroleum system of offshore Uruguay has strong potential to contribute to a better characterization of the capacity of the basin to generate and accumulate hydrocarbons. Three stages have previously been recognized during the evolution of Pelotas basin: (1) a prerift phase which preserved Paleozoic and Mesozoic units of the Paraná Basin; (2) an Early Cretaceous volcano-sedimentary synrift phase; and (3) a Cretaceous to Cenozoic postrift phase deposited during the passive margin stage. In this study, we use sequence stratigraphy methodology to interpret 2D multichannel seismic sections of the southern segment of the Pelotas Basin in the Uruguayan Atlantic margin. This analysis allows us to identify depositional sequences, systems tracts and the distribution of the main elements of the potential petroleum systems. Following our analysis, we propose six speculative petroleum systems (SPS) in the Pelotas Basin. The first SPS is related to the prerift phase and is represented by a Lower Permian restricted marine source rock and reservoirs related to Permian to Upper Jurassic aeolian and fluvial sandstones. The second SPS corresponds to the synrift phase and is constituted by a Barremian lacustrine source rock with reservoirs of alluvial/fluvial sandstones of the same age. The other four proposed SPS are associated with the postrift phase, represented by marine source rocks related to Aptian-Albian, Cenomanian-Turonian and Paleocene transgressions, all of which are identified in the region and interpreted in seismic lines from Uruguay. These postrift SPS have predominantly siliciclastic reservoirs represented by Early Cretaceous aeolian sandstones and Cretaceous to Cenozoic deltaic sandstones and turbidites.     

Modeling free gas content of the Lower Paleozoic shales in the Weiyuan area of the Sichuan Basin,China

Two sets of Lower Paleozoic organic-rich shales develop well in the Weiyuan area of the Sichuan Basin: the Lower Cambrian Jiulaodong shale and the Lower Silurian Longmaxi shale. The Weiyuan area underwent a strong subsidence during the Triassic to Early Cretaceous and followed by an extensive uplifting and erosion after the Late Cretaceous. This has brought about great changes to the temperature and pressure conditions of the shales, which is vitally important for the accumulation and preservation of shale gas. Based on the burial and thermal history, averaged TOC and porosity data, geological and geochemical models for the two sets of shales were established. Within each of the shale units, gas generation was modeled and the evolution of the free gas content was calculated using the PVTSim software. Results show that the free gas content in the Lower Cambrian and Lower Silurian shales in the studied area reached the maxima of 1.98–2.93 m³/t and 3.29–4.91 m³/t, respectively (under a pressure coefficient of 1.0–2.0) at their maximum burial. Subsequently, the free gas content continuously decreased as the shale was uplifted. At present, the free gas content in the two sets of shales is 1.52–2.43 m³/t and 1.94–3.42 m³/t, respectively (under a current pressure coefficient of 1.0–2.0). The results are roughly coincident with the gas content data obtained from in situ measurements in the Weiyuan area. We proposed that the Lower Cambrian and Lower Silurian shales have a shale gas potential, even though they have experienced a strong uplifting.     

Geochemistry,reservoir characterization and hydrocarbon generation potential of lacustrine shales: A case of YQ-1 well in the Yuqia Coalfield,northern Qaidam Basin,NW China

Ever since a breakthrough of marine shales in China, lacustrine shales have been attracting by the policy makers and scientists. Organic-rich shales of the Middle Jurassic strata are widely distributed in the Yuqia Coalfield of northern Qaidam Basin. In this paper, a total of 42 shale samples with a burial depth ranging from 475.5 m to 658.5 m were collected from the Shimengou Formation in the YQ-1 shale gas borehole of the study area, including 16 samples from the Lower Member and 26 samples from the Upper Member. Geochemistry, reservoir characteristics and hydrocarbon generation potential of the lacustrine shales in YQ-1 well were preliminarily investigated using the experiments of vitrinite reflectance measurement, maceral identification, mineralogical composition, carbon stable isotope, low-temperature nitrogen adsorption, methane isothermal adsorption and rock eval pyrolysis. The results show that the Shimengou shales have rich organic carbon (averaged 3.83%), which belong to a low thermal maturity stage with a mean vitrinite reflectance (R_o) of 0.49% and an average pyrolytic temperature of the generated maximum remaining hydrocarbon (T_max) of 432.8 °C. Relative to marine shales, the lacustrine shales show low brittleness index (averaged 34.9) but high clay contents (averaged 55.1%), high total porosities (averaged 13.71%) and great Langmuir volumes (averaged 4.73 cm⁻³ g). Unlike the marine and marine-transitional shales, the quartz contents and brittleness index (BI) values of the lacustrine shales first decrease then increase with the rising TOC contents. The kerogens from the Upper Member shales are dominant by the oil-prone types, whereas the kerogens from the Lower Member shales by the gas-prone types. The sedimentary environment of the shales influences the TOC contents, thus has a close connection with the hydrocarbon potential, mineralogical composition, kerogen types and pore structure. Additionally, in terms of the hydrocarbon generation potential, the Upper Member shales are regarded as very good and excellent rocks whereas the Lower Member shales mainly as poor and fair rocks. In overall, the shales in the top of the Upper Member can be explored for shale oil due to the higher free hydrocarbon amount (S₁), whereas the shales in the Lower Member and the Upper Member, with the depths greater than 1000 m, can be suggested to explore shale gas.     

Stable carbon isotope ratios of CH4-rich gas inclusions in shale-hosted fracture-fill mineralization: A tool for tracing hydrocarbon generation and migration in shale plays for oil and gas

Fluid inclusion gases in minerals from shale hosted fracture-fill mineralization have been analyzed for stable carbon isotopic ratios of CH₄ using a crushing device interfaced to an isotope ratio mass spectrometer (IRMS). The samples of Paleozoic strata under study originate from outcrops and wells in the Rhenish Massif and Campine Basin, Harz Mountains, and the upper slope of the Southern Permian Basin. Fracture-fill mineralization hosted by Mesozoic strata was sampled from drill cores in the Lower Saxony Basin. Some studied sites are candidates for shale gas exploration in Germany. Samples of Mesozoic strata are characterized by abundant calcite-filled horizontal fractures which preferentially occur in TOC-rich sections of the drilled sediments. Only rarely are vertical fractures filled with carbonates and/or quartz in drill cores from Mesozoic strata but in Paleozoic shale they occur frequently. The δ¹³C(CH₄) values of fluid inclusions in calcite from horizontal fractures hosted by Mesozoic strata suggest that gaseous hydrocarbons were generated during the oil/early gas window and that the formation of horizontal fractures seems to be related to hydraulic expulsion fracturing. The calculated maturity of the source rocks at the time of gas generation lies below the maturity derived from measured vitrinite reflectance. Thus, the formation of horizontal fractures and trapping of gas that was generated in the oil and/or early gas window obviously occurred prior to maximal burial. Rapidly increasing vitrinite reflectance data seen locally can be explained by hydrothermal alteration, as indicated by increasing δ¹³C (CH₄–CO₂) values in fluid inclusions. The formation of vertical fractures in studied Mesozoic sediments is related to stages of post-burial inversion; gas-rich inclusions in fracture filling minerals recorded the migration of gas that had probably been generated instantaneously, rather than cumulatively, from high to overmature source rocks. Since no evidence is given for the presence of early generated gas in studied Paleozoic shale, it appears likely that major gas loss from shales occurred due to deformation and uplift of these sediments in response to the Variscan Orogeny.     

Organic geochemical study of source rocks and natural gas and their genetic correlation in the eastern part of the Polish Outer Carpathians and Palaeozoic–Mesozoic basement

Geochemical characteristics of organic matter in the profiles of Dukla, Silesian, Sub-Silesian and Skole units of the Polish Outer Carpathians and of the Palaeozoic–Mesozoic basement in the Dębica-Rzeszów-Leżajsk-Sanok area were established based on Rock-Eval, vitrinite reflectance, isotopic and biomarker analyses of 485 rock samples. The Oligocene Menilite beds have the best hydrocarbon potential of all investigated formations within the Dukla, Silesian, and Skole units. The Ordovician, Silurian, Lower Devonian and locally Middle Jurassic strata of the Palaeozoic–Mesozoic basement are potential source rocks for oil and gas accumulated in Palaeozoic and Mesozoic reservoirs. Thirty one natural gas samples from sandstone reservoirs of the Lower Cretaceous-Lower Miocene strata within the Outer Carpathian sequence and eight from sandstone and carbonate reservoirs of the Palaeozoic–Mesozoic basement were analysed for molecular and isotopic compositions to determine their origin. Natural gases accumulated both in the Outer Carpathian and the Palaeozoic–Mesozoic basement reservoirs are genetically related to thermogenic and microbial processes. Thermogenic gaseous hydrocarbons that accumulated in the Dukla and Silesian units were generated from the Menilite beds. Thermogenic gaseous hydrocarbons that accumulated in the Sub-Silesian Unit most probably migrated from the Silesian Unit. Initial, and probably also secondary microbial methane component has been generated during microbial carbon dioxide reduction within the Oligocene Menilite beds in the Dukla Unit and Oligocene-Lower Miocene Krosno beds in the Silesian Unit. Natural gases that accumulated in traps within the Middle Devonian, Mississippian, Upper Jurassic, and Upper Cretaceous reservoirs of the Palaeozoic–Mesozoic basement were mainly generated during thermogenic processes and only sporadically from initial microbial processes. The thermogenic gases were generated from kerogen of the Ordovician-Silurian and Middle Jurassic strata. The microbial methane component occurs in a few fields of the Dukla and Silesian units and in the two accumulations in the Middle Devonian reservoirs of the Palaeozoic–Mesozoic basement.     

A new Carboniferous coal/shale driven gas play in the Western Black Sea Region (Turkey)

The sedimentary sequence in the Western Black Sea region of Turkey both onshore and offshore offers many possibilities for different hydrocarbon plays. This study presents a new play, which considers Carboniferous coals and shales as source beds, Cretaceous sandstones as reservoirs and Cretaceous shales and marls as seal rocks. The evaluation of this play is performed using the petroleum system approach. Results suggest that the coals and shales have a good to very good source rock potential for gas, that the Cretaceous synrift sandstones are good reservoirs. On the other hand, the sealing efficiency of respective Cretaceous units is assumed to be sufficient based on their lithological (shales and carbonaceous marls) characteristics. Stratigraphic traps, which formed by transgression and by onlap on paleohighs, were sealed and potentially available at 97 million years (ma) before present. Structural traps related to Early Cretaceous extension were also sealed around 97 ma. On the contrary, traps formed by folding and thrusting during the Alpine orogeny only formed during the last 50 ma. The timing of gas generation and migration was determined by one and two-dimensional basin modeling in one well and along a cross-section. The modeling results indicated that during the period between 90 and 42 ma, large volumes of gas were generated from the Carboniferous source rocks. Comparison with the age of stratigraphic and structural traps showed that stratigraphic and normal fault traps were potentially available for the entire volume of generated gas and that the other structural traps associated with Alpine orogeny were available only for gas generated and/or re-migrated during the last 50 ma. The evaluation of this new play results in the conclusion, that the Western Black Sea region is worthy of further exploration for conventional accumulations of thermogenic gas.     

Evaluation of burial history, thermal maturity and source-rock assessment of the Upper Paleozoic succession of the eastern Taurus region, southern Turkey

The regional burial history pattern, thermal maturity variations and source rock assessment of the sedimentary succession in the eastern Taurus region, in the southern part of Turkey, have been studied on surface samples collected from the six different sections which represent the entire region. Organic petrography (Thermal Alteration Index) and geochemical data (TOC content, T_max and HI values) were obtained from transmitted-light microscopy and Rock-Eval pyrolysis.The Lower Paleozoic (Cambrian, Ordovician and Silurian) strata were not investigated and modeled in terms of the maturity and hydrocarbon source rock potential, because of their poor organic matter content and their over maturity resulting from great burial depth (more than 7630 m). Other Paleozoic strata, except the Lower Devonian Ayitepesi Formation, generally have the values of more than 0.5% TOC. Organic matter of the Middle Devonian Safaktepesi sediments are composed of highly terrestrial organic material (type III kerogen), while samples from other three formations (Gumusali, Ziyarettepe and Yigilitepe Formations), while samples from other organic matter (type II and type III kerogen). The average TAI values are as high as 3.4 (equivalent to 1.42 of R₀%) for Ayitepesi and as low as 2.75 (equivalent to 0.77 of R₀%) for Yigilitepe Formations. Time-temperature index values (TTI) indicate that Ziyarettepe and Yigilitepe sediments are marginally mature to mature, while the Devonian strata are overmature. There are minor discrepancies between ΣTTI values and geochemical data in terms of the organic maturity for Devonian strata. In contrast, the e is a consistency between those values for the Ziyarettepe and the Yigilitepe Formations. The onset of oil generation time in the region was initiated from as early as the Norian (216 Ma) to as late as the Lutetian (45 Ma).Regional variations in the level of thermal and source-rock maturities of the Upper Paleozoic sediments in the eastern Taurus region largely depend on burial depth.     

Hydrocarbon Potential of Pre-cenozoic Strata in the North Yellow Sea Basin

The North Yellow Sea Basin ( NYSB ), which was developed on the basement of North China (Huabei) continental block, is a typical continental Mesozoic Cenozoic sedimentary basin in the sea area. Its Mesozoic basin is a residual basin, below which there is probably a larger Paleozoic sedimentary basin. The North Yellow Sea Basin comprises four sags and three uplifts. Of them, the eastern sag is a Mesozoic Cenozoic sedimentary sag in NYSB and has the biggest sediment thickness; the current Korean drilling wells are concentrated in the eastern sag. This sag is comparatively rich in oil and gas resources and thus has a relatively good petroleum prospect in the sea. The central sag has also accommodated thick Mesozoic-Cenozoic sediments. The latest research results show that there are three series of hydrocarbon source rocks in the North Yellow Sea Basin, namely, black shales of the Paleogene, Jurassic and Cretaceous. The principal hydrocarbon source rocks in NYSB are the Mesozoic black shale. According to the drilling data of Korea, the black shales of the Paleogene, Jurassic and Cretaceous have all come up to the standards of good and mature source rocks. The NYSB owns an intact system of oil generation, reservoir and capping rocks that can help hydrocarbon to form in the basin and thus it has the great potential of oil and gas. The vertical distribution of the hydrocarbon resources is mainly considered to be in the Cretaceous and then in the Jurassic.     

二次生烃机理在中下扬子高演化烃源岩评价中的应用

在野外地质观察、油气地球化学和样品分析的基础上,通过总结二次生烃特征和生烃机理,将其应用到中下扬子区海相高演化烃源岩生烃潜力的评价。模拟实验结果表明,二次生烃具有明显的迟缓现象,也仍具有相对的生烃高峰,二次生烃量与一次生烃量的总和小于连续热演化的生烃量,这些特征都与一次生烃的演化程度密切相关,初始演化程度成为评价高演化烃源岩二次生烃潜力的关键因素。中下扬子区中—古生界发育的6套烃源岩中,下二叠统、下志留统和下寒武统烃源岩具有较强的生烃能力,是主要的烃源层。下古生界烃源岩进入生烃时间较早,在强烈的构造运动背景下,生成的油气难以保存;上古生界烃源岩热演化程度相对较低,燕山—喜山期的再次沉降地区成为二次生烃的供源区。因此,下古生界台地相区和上古生界烃源岩具有一定的二次生烃潜力。     

Oil/gas–source rock correlations in the Dniepr-Donets Basin (Ukraine): New insights into the petroleum system

The Dniepr-Donets Basin (DDB) hosts a multi-source petroleum system with more than 200 oil and gas fields, mainly in Carboniferous clastic rocks. Main aim of the present study was to correlate accumulated hydrocarbons with the most important source rocks and to verify their potential to generate oil and gas. Therefore, molecular and isotopic composition as well as biomarker data obtained from 12 oil and condensate samples and 48 source rock extracts was used together with USGS data for a geological interpretation of hydrocarbon charging history.Within the central DDB, results point to a significant contribution from (Upper) Visean black shales, highly oil-prone as well as mixed oil- and gas-prone Serpukhovian rocks and minor contribution from an additional Tournaisian source. Devonian rocks, an important hydrocarbon source within the Pripyat Trough, have not been identified as a major source within the central DDB. Additional input from Bashkirian to Moscovian (?) (Shebelinka Field) as well as Tournaisian to Lower Visean rocks (e.g. Dovgal Field) with higher contents of terrestrial organic matter is indicated in the SE and NW part, respectively.Whereas oil–source correlation contradicts major hydrocarbon migration in many cases for Tournaisian to Middle Carboniferous reservoir horizons, accumulations within Upper Carboniferous to Permian reservoirs require vertical migration up to 4000 m along faults related to Devonian salt domes.1-D thermal models indicate hydrocarbon generation during Permo-Carboniferous time. However, generation in coal-bearing Middle Carboniferous horizons in the SE part of the basin may have occurred during the Mesozoic.     

Jurassic source rocks in the Vienna Basin (Austria): Assessment of conventional and unconventional petroleum potential

The Upper Jurassic marlstones (Mikulov Fm.) and marly limestones (Falkenstein Fm.) are the main source rocks for conventional hydrocarbons in the Vienna Basin in Austria. In addition, the Mikulov Formation has been considered a potential shale gas play. In this paper, organic geochemical, petrographical and mineralogical data from both formations in borehole Staatz 1 are used to determine the source potential and its vertical variability. Additional samples from other boreholes are used to evaluate lateral trends. Deltaic sediments (Lower Quarzarenite Member) and prodelta shales (Lower Shale Member) of the Middle Jurassic Gresten Formation have been discussed as secondary sources for hydrocarbons in the Vienna Basin area and are therefore included in the present study.The Falkenstein and Mikulov formations in Staatz 1 contain up to 2.5 wt%TOC. The organic matter is dominated by algal material. Nevertheless, HI values are relative low (<400 mgHC/gTOC), a result of organic matter degradation in a dysoxic environment. Both formations hold a fair to good petroleum potential. Because of its great thickness (∼1500 m), the source potential index of the Upper Jurrasic interval is high (7.5 tHC/m²). Within the oil window, the Falkenstein and Mikulov formations will produce paraffinic-naphtenic-aromatic low wax oil with low sulfur content. Whereas vertical variations are minor, limited data from the deep overmature samples suggest that original TOC contents may have increased basinwards. Based on TOC contents (typically <2.0 wt%) and the very deep position of the maturity cut-off values for shale oil/gas production (∼4000 and 5000 m, respectively), the potential for economic recovery of unconventional petroleum is limited. The Lower Quarzarenite Member of the Middle Jurassic Gresten Formation hosts a moderate oil potential, while the Lower Shale Member is are poor source rock.     

Source rocks and related petroleum systems of the Chelif Basin, (western Tellian domain,north Algeria)

In the Chelif basin, the geochemical characterization reveals that the Upper Cretaceous and Messinian shales have a high generation potential. The former exhibits fair to good TOC values ranging from 0.5 to 1.2% with a max. of 7%. The Messinian series show TOC values comprised between 0.5 and 2.3% and a high hydrogen index (HI) with values up to 566 mg HC/g TOC. Based on petroleum geochemistry (CPLC and CPGC) technics, the oil-to source correlation shows that the oil of the Tliouanet field display the same signature as extracts from the Upper Cretaceous source rocks (Cenomanian to Campanian). In contrast, oil from the Ain Zeft field contains oleanane, and could thus have been sourced by the Messinian black shale or older Cenozoic series. Two petroleum systems are distinguished: Cretaceous (source rock) – middle to upper Miocene (reservoirs) and Messinian (source rock)/Messinian (reservoirs). Overall, the distribution of Cretaceous-sourced oil in the south, directly connected with the surface trace of the main border fault of the Neogene pull-apart basin, rather suggests a dismigration from deeper reservoirs located in the parautochthonous subthrust units or in the underthrust foreland, rather than from the Tellian allochthon itself (the latter being mainly made up of tectonic mélange at the base, reworking blocks and slivers of Upper Cretaceous black shale and Lower Miocene clastics). Conversely, the occurrence of Cenozoic-sourced oils in the north suggests that the Neogene depocenters of the Chelif thrust-top pull-apart basin reached locally the oil window, and therefore account for a local oil kitchen zone. In spite of their limited extension, allochthonous Upper cretaceous Tellian formations still conceal potential source rock layers, particularly around the Dahra Mountains and the Tliouanet field. Additionally they are also recognized by the W11 well in the western part of the basin (Tahamda). The results of the thermal modelling of the same well shows that there is generation and migration of oil from this source rock level even at recent times (since 8 Ma), coevally with the Plio-Quaternary traps formation. Therefore, there is a possibility of an in-situ oil migration and accumulation, even from Tellian Cretaceous units, to the recent structures, like in the Sedra structure. However, the oil remigration from deep early accumulations into the Miocene reservoirs is the most favourable case in terms of hydrocarbon potential of the Chelif basin.     

Thermal maturity history and petroleum generation modelling for the Lower Cretaceous Abu Gabra Formation in the Fula Sub-basin,Muglad Basin,Sudan

Two petroleum source rock intervals of the Lower Cretaceous Abu Gabra Formation at six locations within the Fula Sub-basin, Muglad Basin, Sudan, were selected for comprehensive modelling of burial history, petroleum maturation and expulsion of the generated hydrocarbons throughout the Fula Sub-basin. Locations (of wells) selected include three in the deepest parts of the area (Keyi oilfield); and three at relatively shallow locations (Moga oilfield). The chosen wells were drilled to depths that penetrated a significant part of the geological section of interest, where samples were available for geochemical and source rock analysis. Vitrinite reflectances (Ro %) were measured to aid in calibrating the developed maturation models.The Abu Gabra Formation of the Muglad Basin is stratigraphically subdivided into three units (Abu Gabra-lower, Abu Gabra-middle and Abu Gabra-upper, from the oldest to youngest). The lower and upper Abu Gabra are believed to be the major source rocks in the province and generally contain more than 2.0 wt% TOC; thus indicating a very good to excellent hydrocarbon generative potential. They mainly contain Type I kerogen. Vitrinite reflectance values range from 0.59 to 0.76% Ro, indicating the oil window has just been reached. In general, the thermal maturity of the Abu Gabra source rocks is highest in the Abu Gabra-lower (deep western part) of the Keyi area and decreases to the east toward the Moga oilfied at the Fula Sub-basin.Maturity and hydrocarbon generation modelling indicates that, in the Abu Gabra-Lower, early oil generation began from the Middle- Late Cretaceous to late Paleocene time (82.0–58Ma). Main oil generation started about 58 Ma ago and continues until the present day. In the Abu Gabra-upper, oil generation began from the end of the Cretaceous to early Eocene time (66.0–52Ma). Only in one location (Keyi-N1 well) did the Abu Gabra-upper reach the main oil stage. Oil expulsion has occurred only from the Abu Gabra-lower unit at Keyi-N1 during the early Miocene (>50% transformation ratio TR) continuing to present-day (20.0–0.0 Ma). Neither unit has generated gas. Oil generation and expulsion from the Abu Gabra source rocks occurred after the deposition of seal rocks of the Aradeiba Formation.     

Hydrocarbon potential and palynological study of the Latest Ordovician – Earliest Silurian source rock (Sarchahan Formation) in the Zagros Mountains,southern Iran

Source rock studies are one of the key issues of petroleum exploration activities. In the supercontinent of Gondwana, ice ages related to the Upper Ordovician (Hirnantian) and rising sea levels caused by glacial melting at the end of the Ordovician and Early Silurian (Llandoverian) created excellent source rocks along the margin of Gondwana. Investigations conducted in the Arabian Peninsula have been indicated indicating that the lower Qalibah Formation (the so-called Qusaiba Member or Hot Shale) is a good source rock for the Paleozoic petroleum system in this area. Likewise, the Sarchahan Formation was recently introduced as a source rock in the Zagros Basin of Iran, which is probably equivalent to the Qalibah Formation in the Arabian Peninsula. In this study, samples were prepared from surface and subsurface Paleozoic rock units in Iran's Zagros Basin. The emphasis of the paper was on the Sarchahan Formation in Kuh-e Faraghan, ranging in age from the Late Ordovician (Hirnantian) to Lower Silurian (Llandoverian) to determine whether the high richness of organic matter in the Sarchahan Formation is related to the Late Ordovician or Lower Silurian. The basal part of the Sarchahan Formation belongs to the Late Ordovician (Hirnantian) because of the presence of the persculptus graptolite biozone, while the remainder belongs to the Lower Silurian. The Ordovician and early Llandoverian parts of the Sarchahan Formation contain type II and III kerogen with TOC ranging from 2.94 to 7.19, but the rest of the Sarchahan Formation (late Llandoverian) has TOC ranging from 0.1 to 0.58. Therefore, the Hot Shale in Iran falls within the Hirnantian and early Llandoverian (Rhuddanian), and not the latest Llandoverian (Aeronian and Telychian). Utilizing organic petrography, kerogen type was found II/III. The carbon stable isotope studies revealed that the source rock of hydrocarbons in Dalan and Kangan reservoirs has been the Sarchahan Formation. Based on analytical data, the kerogenous shales in the lower part of the Sarchahan Formation are at end of gas window, and the gamma ray amount is approximately 180 API. This research indicates the differences between the source rocks in the southern and northern Persian Gulf and suggesting, the Hot Shale should be considered in different views and used in modeling studies of sedimentary basins for future exploration targets.     

Oil-oil and oil-source rock correlations in the Alpine Foreland Basin of Austria: Insights from biomarker and stable carbon isotope studies

The Alpine Foreland Basin is a minor oil and moderate gas province in central Europe. In the Austrian part of the Alpine Foreland Basin, oil and minor thermal gas are thought to be predominantly sourced from Lower Oligocene horizons (Schöneck and Eggerding formations). The source rocks are immature where the oil fields are located and enter the oil window at ca. 4 km depth beneath the Alpine nappes indicating long-distance lateral migration. Most important reservoirs are Upper Cretaceous and Eocene basal sandstones.Stable carbon isotope and biomarker ratios of oils from different reservoirs indicate compositional trends in W-E direction which reflect differences in source, depositional environment (facies), and maturity of potential source rocks. Thermal maturity parameters from oils of different fields are only in the western part consistent with northward displacement of immature oils by subsequently generated oils. In the eastern part of the basin different migration pathways must be assumed. The trend in S/(S + R) isomerisation of ααα-C₂₉ steranes versus the αββ (20R)/ααα (20R) C₂₉ steranes ratio from oil samples can be explained by differences in thermal maturation without involving long-distance migration. The results argue for hydrocarbon migration through highly permeable carrier beds or open faults rather than relatively short migration distances from the source. The lateral distance of oil fields to the position of mature source rocks beneath the Alpine nappes in the south suggests minimum migration distances between less than 20 km and more than 50 km.Biomarker compositions of the oils suggest Oligocene shaly to marly successions (i.e. Schoeneck, Dynow, and Eggerding formations) as potential source rocks, taking into account their immature character. Best matches are obtained between the oils and units a/b (marly shale) and c (black shale) of the “normal” Schöneck Formation, as well as with the so-called “Oberhofen Facies”. Results from open system pyrolysis-gas chromatography of potential source rocks indicate slightly higher sulphur content of the resulting pyrolysate from unit b. The enhanced dibenzothiophene/phenanthrene ratios of oils from the western part of the basin would be consistent with a higher contribution of unit b to hydrocarbon expulsion in this area. Differences in the relative contribution of sedimentary units to oil generation are inherited from thickness variations of respective units in the overthrusted sediments. The observed trend towards lighter δ¹³C values of hydrocarbon fractions from oil fields in a W-E direction are consistent with lower δ¹³C values of organic matter in unit c.     

Petrology and depositional evolution of the Paleozoic rocks of Iraq

The study integrates petrographical and lithological data from deep exploration wells and outcrops in northern Iraq to better understand the sedimentary environments present in the basin and to evaluate the depositional evolution of the Paleozoic rocks in Iraq. The studied Paleozoic successions are represented by five sedimentary cycles of intracratonic sequences. These are dominated mainly by siliciclastic and mixed sedimentary packages, and are separated by major and minor unconformity surfaces. These cycles are as follow: the Ordovician cycle, represented by the Khabour Formation; the Silurian cycle, represented by the Akkas Formation; the Middle-Late Devonian to Early Carboniferous cycle, represented by the Chalki, Pirispiki, Kaista, Ora and Harur formations; the Permian–Carboniferous cycle, represented by the Ga’ara Formation and late Permian cycle, represented by the Chia Zairi Formation. Generally, the cycles are characterized by siliciclastic and mixed carbonate–clastic facies with abrupt changes during Late Paleozoic reflecting the environmental and tectonic events during this period. The Ordovician Khabour Formation is suggested to be of shallow marine environment of deposition with stacked transgressive and regressive cycles that are eustatically controlled. The shale of Silurian Akkas Formation was deposited in open-marine environment. Depositional regimes in the Late Devonian to Early Carboniferous are considered as a continuation of deposition in the subsiding basin with a wide geographic distribution that reflect the epicontinental or epeiric seas in a homoclinic ramp setting. The Permo-Carboniferous Ga’ara Formation was deposited in continental to paralic environment while the Late Permian Chia Zairi Formation represents the carbonate platform deposition. The study revealed that potential source rocks may include some shale beds of the Khabour Formation, hot shales of Akkas Formation and the shales of Ora Formation. The sandstones of the Khabour, Akkas and Kaista formations have good reservoir potential. The Late Permian carbonates of Chia Zairi Formation may be self-sourcing and contain multiple reservoirs. The occurrence of shale as source rocks and limestone as reservoir rocks and some evaporates as sealing horizons make the formation as a reservoir in its own right.     

Organic geochemistry and petroleum potential of Early Cretaceous Garau Formation in central part of Lurestan zone,northwest of Zagros,Iran

Deposition of organic rich black shales and dark gray limestones in the Berriasian-Turonian interval has been documented in many parts of the world. The Early Cretaceous Garau Formation is well exposed in Lurestan zone in Iran and is composed of organic-rich shales and argillaceous limestones. The present study focuses on organic matter characterization and source rock potential of the Garau Formations in central part of Lurestan zone. A total of 81 core samples from 12 exploratory wells were subjected to detailed geochemical analyses. These samples have been investigated to determine the type and origin of the organic matter as well as their petroleum-generation potential by using Rock-Eval/TOC pyrolysis, GC and GCMS techniques. The results showed that TOC content ranges from 0.5 to 4.95 percent, PI and Tmax values are in the range of 0.2 and 0.6, and 437 and 502 °C. Most organic matter is marine in origin with sub ordinary amounts of terrestrial input suggesting kerogen types II-III and III. Measured vitrinite reflectance (Rrandom%) values varying between 0.78 and 1.21% indicating that the Garau sediments are thermally mature and represent peak to late stage of hydrocarbon generation window. Hydrocarbon potentiality of this formation is assessed fair to very good capable of generating chiefly gas and some oil. Biomarker characteristics are used to provide information about source and maturity of organic matter input and depositional environment. The relevant data include normal alkane and acyclic isoprenoids, distribution of the terpane and sterane aliphatic biomarkers. The Garau Formation is characterized by low Pr/Ph ratio (<1.0), high concentrations of C27 regular steranes and the presence of tricyclic terpanes. These data indicated a carbonate/shale source rock containing a mixture of aquatic (algal and bacterial) organic matter with a minor terrigenous organic matter contribution that was deposited in a marine environment under reducing conditions. The results obtained from biomarker characteristics also suggest that the Garau Formation is thermally mature which is in agreement with the results of Rock-Eval pyrolysis.