The Paratethys area extends from Central Europe to the borders of the Caspian Sea in Central Asia and hosts a significant number of petroleum provinces, many of which have been charged by Eocene to Miocene source rocks of supra‐regional significance. These include highly oil‐prone Middle Eocene marls and limestones in the Eastern Paratethys (Kuma Formation and equivalents) which are several tens of metres thick. Estimates of the source potential index (SPI) indicate that the Kuma Formation in the northern Caucasus and the Rioni Basin (Georgia) may generate 1 to 2 tons of hydrocarbons per square metre (tHC/m 2 ). This implies that the Kuma Formation may also be an important and additional source rock in the eastern Black Sea. Oligocene and Lower Miocene pelitic rocks (Maikop Group and equivalents) are considered to be the most important source rocks in the Paratethys. Vertical variations in source potential record different stages of basin isolation that reached a maximum during the Early Oligocene (NP23) Solenovian Event. However major variations exist between different sub‐basins in the Central and the Eastern Paratethys. In the Central Paratethys, the highest quality source rocks occur in the Carpathian Basin where the Menilite Formation, several hundreds of metres thick, can generate up to 10 tHC/m 2 . Locally the Menilite Formation is about 1500 m thick and continues into the Lower Miocene. In these settings, the Menilite Formation can generate approximately 70 tHC/m 2 . In the Alpine Foreland Basin (Schöneck and Eggerding Formations) and the Pannonian Basin (Tard Clay Formation), oil‐prone source rocks are restricted to the Lower Oligocene. In the Eastern Paratethys, the best source rock intervals of the Maikop Group are typically associated with the Early Oligocene Solenovian Event. By contrast, with the exception of the Kura Basin in Azerbaijan, the potential of Upper Oligocene and Lower Miocene rocks is often limited. In total, the Maikop Group may generate up to 2 tHC/m 2 in the North Caucasus area and 4 tHC/m 2 in the Rioni Basin. A particular source rock facies is found in the Western Black Sea where diatomaceous rocks with good oil potential accumulated in the Kaliakra Canyon during Early Miocene time. This facies may generate up to 8 tHC/m 2 , but is probably limited to shelf‐break canyons. Middle and Upper Miocene rocks are the main source for oil and thermogenic gas in the Pannonian Basin System, and also contributed to thermogenic hydrocarbons in the Moesian Platform and the South Caspian Basin. In addition, Upper Oligocene and Miocene rocks are the source for microbial gas in several basins including the Alpine and Carpathian foredeeps.
Initial crustal collision between Africa and Eurasia in the middle Eocene – early Oligocene enclosed a semi‐restricted Paratethyan seaway of linked basins and platforms across a region stretching from the Eastern Alps to the South Caspian Sea. As the African Plate continued to advance north during the later Neogene, the seaway shrank into a series of more isolated basins separated by the rising Alpine – Carpathian – Caucasus fold‐thrust belts. Organic‐rich oil‐prone Paratethyan source rocks of middle Eocene (Kuma Formation and equivalents) and Oligocene – early Miocene (Maikop and Menilite Beds) ages, and more gas‐prone post‐orogenic mid‐upper Miocene shales, subsequently charged over 2500 accumulations across the region with combined recoverable reserves of 95 billion brl oil‐equivalent (B boe). These accumulations are clustered in discrete petroleum provinces, each with a distinct tectono‐stratigraphic architecture and comprised of one or more petroleum systems. The provinces can be grouped into five broad categories: Average Reserves Average Field Sizes Fold‐thrust Provinces 60,980 MMboe 2–590 MMboe Sub‐thrust Provinces 255 MMboe 3.4 MMboe Foreland Provinces 18,671 MMboe 2–77 MMboe Intermontane Provinces 13,122 MMboe 1–40 MMboe Black Sea back‐arc Province > 1391 MMboe >33 MMboe The productivity of each province (estimated very approximately from the number of barrels oil equivalent / square kilometre) is extremely variable, and its relationship with the geological factors controlling hydrocarbon entrapment and retention is complex. The most critical of these factors appears to be the quality and distribution of source rocks and post‐charge structural modification.
Studies of pore systems in volcanic rocks are of increasing importance due to these rocks' potential as reservoirs for hydrocarbons. For this paper, samples of basaltic pahoehoe, rubbly pahoehoe and acidic lava from the Lower Cretaceous Serra Geral Group (Paraná Basin, southern Brazil) were analysed in order to quantify and characterize the constituent pore systems. The Serra Geral Group volcanics were erupted as part of the Paraná‐Etendeka Igneous Province in the Early Cretaceous (Valanginian – Hauterivian). Analyses included experimental measurements by permo‐porosimeter integrated with X‐ray microtomography (μ‐CT) image analysis of vertical and horizontal sample plugs. In addition petrographic analyses were carried out to characterize pore types in thin section. The experimental porosity values ranged from 0.11 to 13.08% and most permeability values were generally lower than 0.0004 mD. Values varied as much within flow zones as they did between them. Porosity and permeability values were not sufficient for the Serra Geral Group volcanics to be considered as a potential reservoir analogue. However the wide range in values was attributed to the processes which controlled the origin and development of the pore system. Primary pores observed included intracrystalline sieve, vesicular and interflow laminar types; secondary porosity, such as spongy, interclast and intra‐matrix pore types, was related to dissolution and the precipitation of secondary minerals. The porosity values obtained by μ‐CT (between <0.01 and 3.37%) were lower than those experimentally measured by permo‐porosimeter. This was attributed to the presence of multi‐scale pores in the volcanic rocks sampled, and also to limitations with image resolution. Even so, the use of μ‐CT allowed the visualization of porosity variations and was useful in characterizing the pore system. The results presented in this paper demonstrate that the volcanic rocks in the Serra Geral Group have a heterogeneous pore system, similar to that in carbonate rocks.
The source rock potential of “hot shales” in the Silurian Akkas Formation in Iraq has been investigated by numerous studies, but the reservoir potential of sandstone intervals in the formation has received less attention. This study investigates the sedimentology and geochemistry of sandstones from the Akkas Formation in the Akkas‐1, Akkas‐3 and KH5/6 wells in western Iraq. The composition of sandstone samples from the Akkas wells is similar; in general they are classified as sub‐litharenites, quartz‐arenites and sub‐arkoses. Scanning electron microscopic analysis identified extensive microporosity and good pore connectivity, suggesting that these sandstones have the potential to form hydrocarbon reservoirs. The sandstones from the KH5/6 well are more lithic‐rich than those from the Akkas wells and are classified as sub‐litharenites. They have larger, more connected pores and better reservoir potential. Low permeability shale intervals within the Akkas Formation and the conformably‐underlying Ordovician Khabour Formation form barriers to hydrocarbon migration into the Akkas and Khabour sandstones. Hydrocarbon migration from the Akkas “hot shales” in the Akkas field is therefore controlled by faulting and fracturing. Petrographic and whole rock geochemical analyses showed that the composition of sandstones in the Akkas Formation is different from that of sandstones in the Khabour Formation. The chemical alteration index ranges from 77.39 to 87.06%, indicating intense weathering of the provenance area before sandstone deposition. The studied samples are texturally mature which indicates good potential for fluid storage capacity. A decrease in feldspar content in the Akkas Formation is attributed to possible recycling of sediments from the Khabour Formation into the Akkas Formation following the Hirnantian glaciation, or to longer distance transportation from the source area.
The Oligocene – Miocene Maikop Formation is the key source rock in the South Caspian and Kura Basins. The Maikop is composed of a thick (up to 3 km) succession of clay‐rich mudstones containing up to 15% total organic carbon (TOC). Despite decades of study, the mudstones often lack precise age control – Maikop strata rarely contain diagnostic microfaunal assemblages which can be used for dating, stratigraphic correlation, or constraining the depositional setting. Using rhenium‐osmium geochronology, this study adds important numerical age data for the Maikop Formation. Of five sample suites analysed from the Kura Basin, eastern Azerbaijan, one Re‐Os data‐set produced a significant range in 187 Re/ 188 Os versus 187 Os/ 188 Os space to yield an isochron of 17.2 ± 3.2 Ma (Early Miocene). Other sample suites yielded imprecise Re‐Os age constraints as a result of variable initial 187 Os/ 188 Os values and a limited range in 187 Re/ 188 Os versus 187 Os/ 188 Os space. The initial 187 Os/ 188 Os values of these data‐sets were compared with the known 187 Os/ 188 Os values of seawater for the past 70 Ma to provide more qualitative age constraints. Pre‐Maikopian strata from the Perikeshkul locality were found to coincide in 187 Os/ 188 Os values with an isotope excursion at the Eocene – Oligocene Transition (EOT), therefore indicating that deposition of Maikopian strata began around the EOT. While values such as this match well with global values, there are several 187 Os/ 188 Os values that are not easily explained by global ratios. Intervals with initial 187 Os/ 188 Os values that deviate significantly from global 187 Os/ 188 Os values suggest periodic basin restriction and the development of anoxia at discrete times as the basin transitioned towards a closed system. High Os abundances outside of expected global values are often coupled with enrichment in detrital elements (Al, Ti, Ga, Sc and La) and changes in basin circulation, suggesting changing basinal conditions and sediment routing dynamics related to the initial uplift of the Greater Caucasus Mountains, changes in sediment provenance, or changing proximity to the sediment source. Through generation of isochron age dates and imprecise Re‐Os age constraints from the Maikop Formation, we gain a better understanding of the timing and nature of the evolution of the South Caspian Basin during this critical time period. Better age constrains will also help to better constrain the wealth of geochemical information already gathered within this petroleum‐rich basin.
The petroleum‐bearing Assam oil province, NE India, has a complex tectonic history resulting from the Cenozoic collision of the Indian Plate with the Eurasian and Burma Plates. Well data show that there are significant variations in the magnitude and stratigraphic occurrence of overpressures across the foreland basin. In areas which have not been affected by thrust tectonics, analyses of pore pressures in Upper Miocene to Eocene and underlying sequences indicate that overpressures are caused by disequilibrium compaction. Pore pressures were observed to be 25.8–28 MPa over a depth interval of 2259–2382 m and 43–45 MPa between depths of 3820 m and 3994 m. In the adjacent Schuppen (fold‐thrust) belt, multiple overpressure regimes are recognised and disequilibrium compaction is the main cause of the overpressures in both the supra‐thrust and the sub‐thrust successions. Unloading due to uplift and erosion in the supra‐thrust section of the Schuppen belt was quantified using velocity data and the normal compaction trend for shales; net uplift was estimated to total 1000–1600 m with a standard deviation of 250–476 m. Overpressure development in supra‐thrust strata in the Schuppen belt suggests the possible effects of normal burial prior to tectonic deformation, as well as of compaction related to high horizontal stresses resulting from thrusting and associated fold development. Pore pressures in the supra‐thrust section, over a depth interval of 700–1400 m which corresponds to the Oligocene to Upper Miocene succession, were observed to range from 9.6 to 19.5 MPa. The top of the overpressured zone in sub‐thrust strata was observed in the Upper Eocene to Oligocene succession at a depth of 3700 m, in the argillaceous Barail Formation, with pore pressures ranging between 48 MPa and 54 MPa. Pore pressures were estimated using acoustic log data calibrated to measured pressures from Modular Dynamic and Drill Stem Test data. The modelled pore pressures closely correspond to the measured data, supporting the robustness of the model. The numerical parameters defined in this study may be used for future exploration in the region.
Seismic reflection profiles and well data show that the Nogal Basin, northern Somalia, has a structure and stratigraphy suitable for the generation and trapping of hydrocarbons. However, the data suggest that the Upper Jurassic Bihendula Group, which is the main source rock elsewhere in northern Somalia, is largely absent from the basin or is present only in the western part. The high geothermal gradient (∼35–49 °C/km) and rapid increase of vitrinite reflectance with depth in the Upper Cretaceous succession indicate that the Gumburo Formation shales may locally have reached oil window maturity close to plutonic bodies. The Gumburo and Jesomma Formations include high quality reservoir sandstones and are sealed by transgressive mudstones and carbonates. ID petroleum systems modelling was performed at wells Nogal‐1 and Kalis‐1, with 2D modelling along seismic lines CS‐155 and CS‐229 which pass through the wells. Two source rock models (Bihendula and lower Gumburo) were considered at the Nogal‐1 well because the well did not penetrate the sequences below the Gumburo Formation. The two models generated significant hydrocarbon accumulations in tilted fault blocks within the Adigrat and Gumburo Formations. However, the model along the Kalis‐1 well generated only negligible volumes of hydrocarbons, implying that the hydrocarbon potential is higher in the western part of the Nogal Basin than in the east. Potential traps in the basin are rotated fault blocks and roll‐over anticlines which were mainly developed during Oligocene–Miocene rifting. The main exploration risks in the basin are the lack of the Upper Jurassic source and reservoirs rocks, and the uncertain maturity of the Upper Cretaceous Gumburo and Jesomma shales. In addition, Oligocene‐Miocene rift‐related deformation has resulted in trap breaching and the reactivation of Late Cretaceous faults.
The principal source rocks in the Outer Carpathians are organic‐rich shales in the Oligocene to Lower Miocene Menilite Formation. The average total organic carbon (TOC) content in the Menilite Formation is 4–8 wt%; the maximum measured is 26 wt%. Organic matter (OM) is oil‐prone Type II kerogen derived mainly from algae and cyanobacteria which was deposited under euxinic conditions. The thermal maturity of the Menilite shales varies significantly within the Outer Carpathians, both vertically in relation to burial depth and laterally in different tectonic units, and increases from external to internal parts of the orogenic belt. Maturity in general ranges from immature to different phases of the “oil window” and up to the “gas window”.
For over a century, oil has been produced in Georgia from oilfields located in the foreland basins between the Greater and Lesser Caucasus foldbelts. To date, little information on the associated source rocks has been available. In this context, this paper presents a study of 380 samples of Eocene (Kuma Formation) and Oligocene to Lower Miocene (Maikop Group) source rocks from three outcrop sections in the Rioni and Kura Basins. The Kuma Formation in the Rioni Basin is composed of fully‐marine marls and is about 40 m thick. At the Martivili and Khobi sections, the formation is thermally immature and has an average TOC of 3.2 wt%. The hydrogen indices (HI) of 300–600 mg HC/g TOC indicate that the organic matter is oil‐prone Type II kerogen. The oil generation potential is between 1.0 and 2.4 t HC/m 2 , and the Kuma Formation is therefore interpreted as a prolific source rock. The Maikop Group in the Rioni Basin was studied at the Martvili section, where it is thermally immature. The Oligocene succession is divided by calcareous shales deposited during the Solenovian Event (at the onset of nannoplankton zone NP23) into Pshekhian and Solenovian‐to‐Kalmykian intervals. The Pshekhian interval (NP21‐22) is over 60 m thick and comprises a marly lower part and a shale‐rich upper part, and contains high quantities (average 2.7 wt% TOC) of Type II‐III kerogen (average HI: 278 mg HC/g TOC). The overlying largely carbonate‐free shale succession, 424 m thick, is less organic matter ‐rich (∼2.0 %TOC) and contains dominantly Type III kerogen (average HI: 140 mg HC/g TOC). In total, the Maikop Group has a generation potential of about 4 t HC/m 2 , a value which is higher than in most other sub‐basins in the Eastern Paratethys. Because the Rioni Basin continues westwards into the Black Sea, these results are relevant for future exploration in the eastern part of the Black Sea Basin. The Maikop Group in the western Kura Basin in the Tbilisi area is over 3500 m thick and includes numerous sandstone beds. Because of the great thickness of the Maikop Group and the presence of about 3 km of overburden, which was removed during Miocene to Recent unroofing, potential source rocks in the Eocene to Lower Oligocene succession have reached oil window maturities but their hydrocarbon potential is low.
Hydrocarbon discoveries in the Western Black Sea have proved the presence of both thermogenic and biogenic petroleum systems. The presence of Tertiary biomarkers in oils from the Romanian part of the Western Black Sea sub‐basin, and correlation with Oligocene to Lower Miocene black shales, suggests that the thermogenic petroleum system is sourced mainly by the Oligocene – Miocene Maikop Group. Older source rocks may also be present locally in other parts of the sub‐basin, but their contribution is currently poorly understood. This paper presents the results of 3D basin modelling which was intended to evaluate charge models for prospects in the Western Black Sea sourced by the Maikop Group shales. The model is built on the regional‐scale interpretation of recently acquired, long‐offset 2D reflection seismic data, and was calibrated with proprietary and published well, geochemical and temperature data. The sensitivity of the thermal models on source maturity was tested. The basin models investigated two end‐member heat‐flow scenarios, “hot” and “cold”. Whereas the “hot” model more successfully reproduces the field and well data in shelfal areas of the Western Black Sea, the “cold” model is considered to be more valid for deeper‐water areas. Hydrocarbon expulsion maps were calculated for both scenarios at key stratigraphic levels, with preferential migration routes identified. The results of the basin modelling suggest that the most likely source rocks for the oils in accumulations offshore Romania are located in the mid‐Maikop Group (Upper Rupelian? to Chattian). Core data from offshore wells indicate that the source rocks consist of black shales with fair to good oil generation potential (TOC ∼ 0.5 to 4.5%, HI <600 mg/g TOC, and mixed Type II/III kerogen). At the present day, these shales are in the early oil window offshore Romania to the SE of the producing fields, and in the wet gas window further to the east. Hydrocarbon expulsion from the mid‐Maikop interval began during the Middle Miocene, but significant volumes of liquids were generated only in the Late Miocene with the peak of expulsion not yet reached. Charging the accumulations on the Romanian Shelf requires lateral migration along the base‐Oligocene unconformity over distances of about 20–50 km. In addition, hydrocarbons have charged underlying Eocene and Cretaceous reservoir sections by lateral downward migration, filling structural traps and spilling over to higher structural levels. The results highlight the underexplored potential associated with the Maikop Group in the Western Black Sea.
The Mesozoic Cameros Basin, northern Spain, was inverted during the Cenozoic Alpine orogeny when the Tithonian – Upper Cretaceous sedimentary fill was uplifted and partially eroded. Tar sandstones outcropping in the southern part of the basin and pyrobitumen particles trapped in potential source rocks suggest that hydrocarbons have been generated in the basin and subsequently migrated. However, no economic accumulations of oil or gas have yet been found. This study reconstructs the evolution of possible petroleum systems in the basin from initial extension through to the inversion phase, and is based on structural, stratigraphic and sedimentological data integrated with petrographic and geochemical observations. Petroleum systems modelling was used to investigate the timing of source rock maturation and hydrocarbon generation, and to reconstruct possible hydrocarbon migration pathways and accumulations. In the northern part of the basin, modelling results indicate that the generation of hydrocarbons began in the Early Berriasian and reached a peak in the Late Barremian – Early Albian. The absence of traps during peak generation prevented the formation of significant hydrocarbon accumulations. Some accumulations formed after the deposition of post‐extensional units (Late Cretaceous in age) which acted as seals. However, during subsequent inversion, these reservoir units were uplifted and eroded. In the southern sector of the basin, hydrocarbon generation did not begin until the Late Cretaceous due to the lower rates of subsidence and burial, and migration and accumulation may have taken place until the initial phases of inversion. Sandstones impregnated with bitumen (tar sandstones) observed at the present day in the crests of surface anticlines in the south of the basin are interpreted to represent the relics of these palaeo‐accumulations. Despite a number of uncertainties which are inherent to modelling the petroleum systems evolution of an inverted and overmature basin, this study demonstrates the importance of integrating multidisciplinary and multi‐scale data to the resource assessment of a complex fold‐and‐thrust belt.
This study presents a 3D numerical model of a study area in the NW part of the Persian Gulf, offshore SW Iran. The purpose is to investigate the burial and thermal history of the region from the Cretaceous to the present day, and to investigate the location of hydrocarbon generating kitchens and the relative timing of hydrocarbon generation/migration versus trap formation. The study area covers about 20,000 km 2 and incorporates part of the intra‐shelf Garau‐Gotnia Basin and the adjacent Surmeh‐Hith carbonate platform. A conceptual model was developed based on the interpretation of 2700 km of 2D seismic lines, and depth and thickness maps were created tied to data from 20 wells. The thermal model was calibrated using bottom‐hole temperature and vitrinite reflectance data from ten wells, taking into account the main phases of erosion/non‐deposition and the variable temporal and spatial heat flow histories. Estimates of eroded thicknesses and the determination of heat‐flow values were performed by burial and thermal history reconstruction at various well and pseudo‐well locations. Burial, temperature and maturation histories are presented for four of these locations. Detailed modelling results for Neocomian and Albian source rock successions are provided for six locations in the intra‐shelf basin and the adjacent carbonate platform. Changes in sediment supply and depocentre migration through time were analyzed based on isopach maps representing four stratigraphic intervals between the Tithonian and the Recent. Backstripping at various locations indicates variable tectonic subsidence and emergence at different time periods. The modelling results suggest that the convergence between the Eurasian and Arabian Plates which resulted in the Zagros orogeny has significantly influenced the burial and thermal evolution of the region. Burial depths are greatest in the study area in the Binak Trough and Northern Depression. These depocentres host the main kitchen areas for hydrocarbon generation, and the organic‐rich Neocomian and Albian source rock successions have been buried sufficiently deeply to be thermally mature. Early oil window maturities for these successions were reached between the Late Cretaceous (90 Ma) and the early Miocene (18 Ma) at different locations, and hydrocarbon generation may continue at the present‐day.
Crude oil samples from surface seeps in the Douala Basin (southern Cameroon) and from producing fields in the nearby Rio del Rey and Kribi‐Campo sub‐basins were analysed for bulk and molecular geochemical parameters by inductively coupled plasma – mass spectrometry (ICP‐MS), gas chromatography – mass spectrometry (GC‐MS) and isotope ratio mass spectrometry (IRMS). The aims of the study were to assess the composition of the oils, to evaluate the relationship between the seep oils and the oils from producing fields, and to highlight the significance of the data for oil exploration in the region. Chromatograms of the saturate fractions of the oils exhibit biodegradation ranging from very light (PM1 on the scale of Peters and Moldowan, 1993) in oil from the offshore Lokele field in the Rio del Rey sub‐basin, to severe (PM 6+) for seep oils from the Douala Basin. A plot of Pr/n‐C 17 (1.3– 5.0) versus Ph/n‐C 18 (0.8–2.6) for the samples further supports mild biodegradation in some samples (Lokele, Kole, Ebome), and demonstrates that the oils from the Lokele and Kole fields (Rio Del Rey sub‐basin) and from Ebome field (Kribi‐Campo sub‐basin) originated from mixed organic matter with a dominant marine contribution. The Pr/Ph ratio (1.8–2.3) for the Lokele, Kole and Ebome oil samples, and the V/(V+Ni) ratios (< 0.5) for the seep oils (Douala Basin) and the oils from the Lokele, Kole and Ebome fields, indicate derivation from source rocks deposited in oxic – dysoxic environments. The CPI (1.0–1.1) demonstrates that the Lokele and Ebome oils originated from mature source rocks, with the ratios of C 31 22S/(S+R) (0.57 to 0.63) and C 30 ‐βαH/C 30 ‐αβH (0.18–0.23) for the Lokele, Kole and Moudi samples indicating early oil window maturity. Both V/(V+Ni) ratios (0.06–0.22) and δ 13 C (‐26.96 to ‐24.89 ‰) were used for correlation of the oils, with the seep oils from the Douala Basin showing the closest relationship to the oil from the Lokele field. The presence of mature Type II / III source rocks in different basins in southern Cameroon suggests significant potential for oil exploration in the region.
Identifying controls on the permeability of fluid‐conductive fractures is critical in tight reservoirs, but this is challenging in tectonically complex regions such as foothills belts where there may have been multiple stages of deformation and fracturing. Fracture permeability depends on fracture aperture and connectivity, both of which are affected by tectonism and cementation. Among the many factors that control the cementation history, oil charging may play an important role. Important challenges in studies of fractured reservoirs in tectonically complex regions include determining the timing (and intensity) of fracturing events relative to that of the oil charge, verifying the presence of matrix storage, and establishing the fracture cementation history. This paper reports on a comparative fracture study of four small‐scale oilfields in the west Adıyaman Basin, located within the foothills belt of the Tauride suture zone in SE Turkey. Here the tight reservoir carbonates of the Sayındere Formation (Campanian) were subjected to repeated phases of structural deformation. Major deformation phases took place in Campanian and Maastrichtian times, before oil charging into the reservoir began in the Eocene; and in the Late Eocene – Oligocene and Late Miocene, after the oil charge. Fractures that were generated before oil emplacement appear to have been cemented or partially cemented by calcite as indicated by cross‐cutting cemented fractures on borehole images. Partially‐cemented fractures in cores are oil‐stained with cement‐lined walls, suggesting cementation began before oil emplacement but was not completed. Image logs and cores also show the presence of clean, open fractures with no cement present on the walls. These open fractures cut across the cemented or partially‐cemented fractures, and are in general related to Late Miocene compressional folding. Open fracture density is correlated to Late Miocene fold curvature and asymmetry in the four oilfields studied. Of these fields, the Șambayat structure is the tightest and most asymmetric anticline and hence has the maximum open fracture density; this field also has the highest oil potential. Although the available data is not sufficient to evaluate the effects of oil charging on fracture cementation definitively, the observations are consistent with a model that oil charge into the fractured Sayındere Formation carbonates inhibited or slowed calcite cementation. Hence fracturing of a carbonate reservoir after oil emplacement may significantly enhance the fracture permeability, and may even render a tight reservoir prospective.
In the Ereğli‐Ulukıșla Basin, southern Turkey, crude oil shows have been observed in the subsurface in the shale‐dominated non‐marine Upper Miocene – Pliocene succession. Based on analyses of samples from four boreholes, the shales’ organic matter content, thermal maturity and depositional characteristics are discussed in this study. Geochemical correlations are established between shale extracts and a crude oil sampled from the shale succession. The shales have moderate to high hydrogen index (HI) and very low oxygen index (OI) values. Pyrolysis data show that the shales contain both Types I and II kerogen, and n‐alkane and biomarker distributions indicate that organic matter is dominated by algal material. Very high C 26 /C 25 and C 24 /C 23 , and low C 22 /C 21 tricyclic terpane ratios and C 31 R/C 30 hopane, C 29 /(C 28 +C 29 ) MA and DBT/P ratios in shale extracts indicate that deposition occurred in a lacustrine setting. High gammacerane and C 35 homohopane concentrations and low diasterane/sterane ratios with a very low Pr/Ph ratio suggest that both the shales and the source rocks for the oil were deposited in a highly anoxic environment in which the water column may have been thermally stratified. Although the shales analysed have very low T max values, the production index is quite high which suggests that the shales are early‐mature to mature. Biomarker ratios including C 32 22S/(22R+22S) homohopanes, C 29 20S/(20R+20S) and ββ(ββ+αα) steranes, moretane/hopane, TA(I)/TA(I+II) and MPI‐3 all suggest that the shales are within the oil window. Heavy components of free hydrocarbons (S 1 ) within the shales may have been recorded as part of the Rock‐Eval S 2 peak resulting in the low T max values. The oil and shale extracts analysed are similar according to their sterane and triterpane distributions, suggesting that the oil was generated by the shales. However burial depths of the Upper Miocene – Pliocene shale succession are not sufficient for thermal maturation to have occurred. It is inferred that intense volcanism during the Pliocene – Pleistocene may have played an important role in local maturation of the shale succession.
The Middle Jurassic Shimengou Formation in the Qaidam Basin, NW China, includes coals and lacustrine source rocks which locally reach oil shale quality (i.e. yielding >3.5 % oil on low‐temperature distillation). In the present study, the palaeo‐depositional environment and hydrocarbon potential of the 84.5 m thick Shale Member of the Shimengou Formation are investigated based on bulk geochemical parameters, organic petrographic data, biomarker analysis, and stable isotope geochemistry of 88 core samples. The Shale Member was deposited in an anoxic freshwater lake which formed following the drowning of a precursor low‐lying mire. Variations in bulk geochemical parameters allow four informal units to be identified, referred to (from the base up) as Units 1 to 4. These contain intervals of oil shale of varying thicknesses. In Unit 1, mudstones in the interval referred to as oil shale Layer 1 (true thickness [TD]: 2.06 m) are OM‐rich as a result of algal blooms and photic zone anoxia, and correspond to an initial flooding event. Subsequently, productivity of aquatic organisms decreased, resulting in the deposition of organic‐lean mudstones in Unit 2. Oil shale Layers 2 (TD: 2.03 m) and 3 (TD: 8.03 m) near the base of Unit 3 were deposited during maximum water depths. As with Layer 1, high productivity by algal blooms resulted in photic zone anoxia in a stratified water column. The shales in the upper part of Unit 3 are characterized by high TOC contents and a gradual increased input of terrigenous OM, and were deposited in a stable semi‐deep lake. Finally, organic‐lean mudstones in Unit 4 were deposited in shallow lacustrine conditions. The reconstruction of depositional environments in thick, non‐marine shale‐rich successions by mineralogical, petrographic and inorganic geochemical methods may be challenging as a result of the homogenous composition of component mudstones. The results of this study indicate, however, that sub‐division and basin‐wide correlation of such intervals can be achieved by organic geochemical analyses. Oil shales and organic‐rich mudstones in Units 1 and 3 of the Shimengou Formation Shale Member are excellent oil‐prone source‐rocks with a Source Potential Index of 3.2 t HC/m 2 . Considering the large area covered by the Shimengou Formation in the northern Qaidam Basin (∼34,000 km 2 ), the results of this study highlight the regional significance for future petroleum exploration. They indicate that variations in organic productivity and dilution by minerals are key factors controlling the abundance and type of organic matter in the formation. An understanding of these factors will assist with the identification of exploration targets.
Palaeo‐exposure surfaces within and at the top of the carbonate‐dominated Aptian Dariyan Formation have been poorly studied in the Iranian sector of the Persian Gulf. This paper presents an integrated sedimentological and geochemical study of the Dariyan Formation at four oil and gas fields located in the western, central and eastern parts of the Gulf. Facies stacking patterns in general indicate shallowing‐upwards trends toward the exposure surfaces, which are interpreted to correspond to unconformities. The Dariyan Formation in the study area is divided into upper and lower carbonate units by a deep‐water, high‐gamma shale‐marl interval. At fields in the western and central Gulf, significant diagenetic changes were recorded in the top of the upper carbonate unit, including meteoric dissolution and cementation, brecciation and paleosol formation. An exposure surface is also present at the top of the lower carbonate unit in all the fields in the study area, and is associated with meteoric dissolution and cementation of grain‐dominated facies. Age calibration of studied intervals was carried out using microfossil assemblages including benthic and planktonic foraminifera. Negative excursions of both δ 18 O (−10‰ VPDB) and δ 13 C (−0.66‰ VPDB) were recorded in weathered intervals located below the unconformity surfaces. A sequence stratigraphic framework for the Dariyan Formation was established by integrating sedimentological, palaeontological and geochemical data. The δ 13 C curve for the formation in the Iranian sector of the Persian Gulf can be correlated with the reference curve for the northern Neotethys and used as a basis for regional stratigraphic correlation. Where the top‐Aptian unconformity is present, it has resulted in an enhancement of the reservoir characteristics of the underlying carbonate succession. Accordingly, the best reservoir zones in the Dariyan Formation occur in the upper parts of the lower and upper carbonate units which are bounded above by significant palaeo‐exposure surfaces.
A detailed organic geochemical evaluation of potential source rock samples (n = 350) collected from outcrops and wells in the Cenozoic Moghan Basin, NW Iran, was undertaken using whole rock (Rock‐Eval pyrolysis, organic petrography) and extract (GC and GC‐MS) analyses. The studied intervals consist of Eocene to Miocene shale/sandstone successions interpreted to have been deposited in nearshore marine conditions. Three potential source rock intervals were investigated: the Salm Aghaji Formation (lower Middle Eocene), the lower member of the Ojagheshlagh Formation (upper Middle Eocene), and the Ziveh Formation (Oligo‐Miocene). The results were used to evaluate the samples' petroleum potential and thermal maturity. A range of maturity parameters indicate that these source rocks are in the early oil generation window in the study area, and outcrop samples are less mature than subsurface samples. Rock‐Eval T max values for the outcrop and subsurface samples range from 410–442 °C and 438–445 °C, respectively. At a regional scale, there is an eastwards increase in thermal maturity which reaches the main oil window (ca. 3000 m) in the east of the Moghan Basin, as indicated by both VR o measurements and maturity‐sensitive biomarkers. Fair to moderate TOC contents (averaging 0.72, 0.99 and 0.78 wt.%) were recorded respectively for the Salm Aghaji, Ojagheshlagh and Ziveh Formations. Average HI values of less than 200 mg HC/g TOC (131, 178 and 104 respectively for the three formations) indicate the dominance of Type III kerogen. This is consistent with detailed molecular parameters which show a dominance of C 29 steranes over C 27 and C 28 homologues. These observations are interpreted to indicate a nearshore marine depositional environment with an abundant terrigenous organic matter input. However, HI values of several samples fall into the range of 250 to 650 mg HC/g TOC showing the local presence of Type II kerogen. Thus the geochemistry and maturity results from this study suggest that shale‐rich intervals in the Salm Aghaji, Ojagheshlagh and Ziveh Formations may be potential source rocks for the oil shows which have been recorded in wells in the Moghan Basin.
This paper presents a new interpretation of the Levant margin, offshore Lebanon, with a review of Lebanese onshore geology and a new evaluation of the petroleum systems of the Eastern Mediterranean. Here, we divide the Lebanese onshore and offshore into four domains: the distal Levant Basin, the Lattakia Ridge, the Levant margin, and the onshore. Each domain is characterised by a particular structural style and stratigraphic architecture, resulting in different source‐reservoir‐trap configurations. This new division draws attention to specific areas of exploration interest in which there are distinct petroleum systems. Following a review of previously published data, this study presents new results from stratigraphic, structural and geochemical investigations. The results include a new interpretation of the Levant margin, focussing on the carbonate‐dominated stratigraphy of this area and its petroleum potential. New petroleum systems charts are presented for each of the four domains to refine and summarize the updated geological knowledge.
Cementation is a primary factor reducing the porosity of carbonate rocks. It is a challenge to accurately model cementation for reservoir quality prediction because cementation is often a syndepositional process. In addition, cementation requires fluid flow to transport chemical species for precipitation within the pore spaces in a sediment. The development of fully‐coupled depositional‐hydrogeochemical models for cementation prediction is desirable, but the parameters which control the extent of cementation need to be identified and evaluated. This study uses petrographic data from 583 carbonate samples from 15 wells in an Upper Jurassic (Kimmeridgian) reservoir at a giant oilfield in eastern Saudi Arabia to investigate the controlling effects of micrite content on cementation in carbonate rocks. The results indicate that the amount of cement decreases with increasing micrite content in the carbonate rocks analysed. In addition, a modified Houseknecht method has been developed to assess the relative fractions of porosity reduction in carbonate sediments due to compaction and cementation. The method highlights variations in depositional porosity for different rock textures and distinguishes microporosity from interparticle porosity. In the studied samples, the total porosity loss due to compaction and cementation is generally less than 45%, and samples lose more porosity due to compaction than cementation. The relative importance of compaction and cementation in reducing porosity is different for different rock textures: wackestones and mudstones lose porosity mostly as a result of compaction, while grainstones, mud‐lean packstones and packstones lose porosity due to both compaction and cementation.