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Carbonates in the Lower Cretaceous (Barremian to early Aptian) Kharaib Formation are reservoir rocks at giant oil fields in the UAE and Qatar. The Barremian Kharaib‐2 member (K60), the focus of this study, is in general composed of a regionally continuous succession of high‐energy, shallow‐water limestones bounded above and below by "dense" low‐energy mud‐rich strata. Despite several decades of research, conventional carbonate facies classification schemes and resulting facies groupings for the Kharaib‐2 member have failed to show a statistically acceptable correlation with core‐ and log‐derived petrophysical data. Moreover, sedimentary bodies potentially responsible for dynamic reservoir heterogeneities have not clearly been identified. This paper proposes a standardized facies classification scheme for the Kharaib‐2 carbonates based on vertical facies proportion curves (VPCs) and variogram analyses of core data to construct stratigraphic correlations at both field and regional scales. Data came from 295 cored wells penetrating the Kharaib‐2 member at ten fields in the on‐ and offshore UAE. Thin, dense intervals separating reservoir units were adopted as fourth‐order transgressive units and were used for stratigraphic correlation. Field‐scale probability maps were used to identify sedimentary bodies such as shallow‐water rudistid shoals. Regional stratigraphic correlations of the Kharaib‐2 member carbonates based on the VPCs identified variations in depositional environments, especially for the lower part of the reservoir unit; depositional facies at fields in the SE of the UAE were interpreted to be more distal compared to those at offshore fields to the NW. At a field scale, the VPCs failed to identify significant lateral variations in the carbonates. However, variogram analyses of cored wells showed spatial concentrations of specific facies in the inner ramp domain which could be correlated with high‐energy depositional bodies such as shoals dominated by rudist debris. The bodies were sinusoidal in plan view with lengths of up to 8 km and widths of ca. 1 km. Although similar‐shaped bodies with these dimensions have been reported from other carbonate depositional systems, they have not previously been reported in the Kharaib Formation. At a regional (inter‐field) scale, the stratigraphic correlation of standardized sedimentary facies remains problematic; however, mapping of facies associations and their relative proportions relative to their environments of deposition demonstrated new patterns for the stratigraphic architecture of the Kharaib‐2 member in the UAE. [ABSTRACT FROM AUTHOR]

The sedimentary column at the Rechitsa oilfield in the Pripyat rift basin, Belarus, is dominated by an Upper Devonian synrift succession. The succession includes uppermost Frasnian and mid‐Famennian salt units which are about 1000 m and 2000 m thick respectively. Reservoir rocks consist of sandstones and carbonates in the intra‐, inter‐ and sub‐salt successions. In this paper, the geochemical analysis of 15 oil samples from different stratigraphic intervals at the Rechitsa field is used as a basis for reservoir characterisation. Geochemical studies included biomarker and stable C, N and S isotope analyses. Four genetic oil groups were identified and are referred to as Groups A to D. Oils in Group A came from upper intra‐ and inter‐salt reservoir rocks; the oils are early mature, enriched in heavy (C36+) hydrocarbons, heteroatoms, aryl‐isoprenoids and gammacerane, with low Pr/Ph = 0.6 and a sulphur isotope composition averaging 22.7‰ CDT. Oils in Group B were from sub‐salt reservoirs and are at peak maturity with Pr/Ph = 1, an increased proportion of C27 regular steranes, and a sulphur isotope composition of 8.1‰ CDT. The single oil sample in Group C was from a Proterozoic reservoir. The oil was overmature with a low content of heavy fractions, heteroatoms and steranes; its hopanes composition indicated that it was generated by the same source rock as the oils in Group B. Oils in Group D came from inter‐salt reservoir rocks and were composed of a mixture of Groups A and B oils in roughly equal proportions, as indicated by their average isotope, molecular and biomarker compositions. Observed differences in oil composition were explained in terms of contributions from at least two different source rocks together with variations in source rock maturity. Group A oils were interpreted to have been generated by Famennian carbonate‐rich source rocks containing dominantly marine and bacterial organic matter deposited in an anoxic evaporitic setting. Source rocks for Groups B and C oils were suggested to be composed of OM‐rich marine shales of Frasnian age or older. The geochemical characteristics of the Devonian oils from Rechitsa field, and the oil‐oil and oil‐ source rock correlations reported, will contribute to a better understanding of the petroleum system in the Pripyat Basin although direct oil‐ source rock correlations are not yet available. The presence of at least two source rocks for the Rechitsa oils has been suggested, respectively comprising carbonates in the inter‐salt succession and marine shales and/or carbonates in the sub‐salt succession. The main controls on oil composition in the Devonian reservoir units were the varying contributions from the different source rocks and differences in source rock thermal maturity associated with variations in burial depth and tectonics, together with the stratigraphic distribution of reservoir units which was in turn controlled by the presence of the thick Frasnian and Famennian salt units. [ABSTRACT FROM AUTHOR]

The Zagros foldbelt – foreland system in SW Iran is a prolific hydrocarbon province with known reserves of more than 90 billion brl of oil and 800 TCF of natural gas. Establishing the structural style of folding in the Zagros area presents a major challenge due both to the geographical extent of the foldbelt, which is some 1600 km long in total, and the presence of marked lateral variations in fold style related to the complex regional tectonic history. In addition, while numerous high‐quality structural studies of the Zagros have been completed over the last 20 years, they support a variety of different interpretations and are therefore $$difficult to synthesize. In this paper, we review the general structural style of the Zagros fold‐and‐thrust belt in SW Iran, and in particular the style of folding in the Lurestan arc, Dezful embayment, Izeh Zone and Fars arc. We summarise relationships between folding in these areas and fracture development, and investigate the timing of folding and the interaction between NW‐SE oriented "Zagros" folds and north‐south oriented "Arabian" folds. Finally, we briefly assess the implications of fold style for petroleum systems in the Zagros area. Although no new data are presented in this paper, a series of unpublished maps are used to illustrate the main results and include: a map showing the extent of the main detachment levels across the Lurestan, Dezful and Fars structural domains; two palaeotectonic maps (for Late Cretaceous – Paleocene and Miocene – Pliocene times, respectively), showing the position of the deformation fronts of the Zagros and the North Oman thrust systems and their potential spatial and temporal relationship with folding; and a set of four maps showing the distribution of reservoir rocks which are grouped by age into the Permian – Triassic Dehram Group, the Late Jurassic – Early Cretaceous Khami Group, the Late Cretaceous Bangestan Group, and the Oligocene – Miocene Asmari Formation. In addition, for the Lurestan, Dezful and Fars structural domains, a series of regional cross‐sections at the same scale are presented and discussed. Most of the data in this review paper were acquired in order to gain an improved understanding of the petroleum systems in the Zagros area; however the data are used here to investigate a range of interacting processes including tectonics, sediment deposition and subsurface fluid flow in the development of the fold‐and‐thrust belt and its associated foreland basins. The resulting synthesis is intended to provice a starting point for future tectonostratigraphic and hydrocarbon‐related studies which will make use of both existing and new multidisciplinary techniques to constrain the results. The knowledge acquired and the techniques used will be of benefit in future challenges including the identification of subsurface reservoirs suitable for the permanent storage of CO2 to mitigate the effects of climate change. [ABSTRACT FROM AUTHOR]

New stable carbon isotope and biomarker data for oils and source rock extracts from the Lusitanian Basin, Portugal, were studied in order to investigate the petroleum systems which are present there. The new analytical data was combined with data presented in previous publications, and oil‐oil and oil‐ source rock correlations were carried out. Three genetic groups of oils (Groups 1, 2 and 3), belonging to three different petroleum systems, were identified: Group 1 oils occur in the northern sector of the Lusitanian Basin and were generated by the Coimbra Formation (Sinemurian) source rock. Reservoir rocks for oils in this group are the Coimbra, Água de Madeiros (upper Sinemurian – lower Pliensbachian), Boa Viagem (Kimmeridgian –Tithonian) and Figueira da Foz (upper Aptian – Cenomanian) Formations. Other potential source rocks in the northern sector of the basin, such as the Polvoeira Member of the Água de Madeiros Formation and the Marly Limestones with Organic Facies (MLOF) Member of the Vale das Fontes Formation (Pliensbachian), had biomarker characteristics which differed from those of the Group 1 oils and did not therefore generate them. Group 2 oils occur in the central and southern sectors of the basin. The source rock is the Cabaços Formation (middle Oxfordian), and reservoir rocks are the Montejunto (middle‐upper Oxfordian) and Abadia (Kimmeridgian) Formations. Group 3 is represented by an oil sample from the central sector of the Lusitanian Basin. Both the source rock and the reservoir rock for the oil are the Montejunto Formation. Geochemical data combined with the regional tectono‐stratigraphic history suggest that the generation‐migration‐accumulation of most of the oil (critical moment) in the Coimbra – Coimbra ‐ Água de Madeiros ‐ Boa Viagem ‐ Figueira da Foz (!) petroleum system occurred in the early Campanian. For the Cabaços – Montejunto ‐ Abadia (!) and Montejunto – Montejunto (!) petroleum systems, the critical moment occurred in the late Cenomanian. [ABSTRACT FROM AUTHOR]

Lower Cretaceous carbonates of the Fahliyan Formation form prolific reservoir rocks at oilfields in the Dezful Embayment, central Zagros fold‐thrust belt, SW Iran. The carbonates have undergone significant diagenetic alteration in phases which can in general be linked to the pre‐, syn‐ and post‐tectonic evolution of the fold‐thrust belt. This paper investigates the impact of diagenetic processes on the reservoir quality of the carbonates using integrated petrographic, geochemical and sedimentological analyses of subsurface and outcrop samples of the formation. Diagenetic alterations include: (i) pre‐tectonic eogenesis in the marine and shallow‐burial realm, which resulted in micritization of allochems and cementation by equant and isopachous calcite rims and framboidal pyrite together with limited dolomitization and dissolution of metastable bioclasts. The isotopic compositions of micrite and early calcite cement depart from postulated values of Lower Cretaceous marine carbonates, signifying early stabilization of precursor metastable carbonate minerals and the possible effects of the incursion of meteoric waters and/or increasing burial temperatures; (ii) mesogenesis during the subsequent syn‐tectonic phase, which included Late Cretaceous ophiolite obduction at the northern margin of the Arabian Plate and the later Zagros orogeny in the Miocene‐Pliocene. Diagenetic modifications included the emplacement of hydrocarbons, the development of stylolites and fractures, and the precipitation of saddle dolomite, replacive rhombic dolomite, discrete pyrite, microcrystalline quartz, kaolin and anhydrite. The average stable isotope compositions of saddle dolomite (δ18O: ‐6.9 ‰ ±.9 and δ13C 0.5 ‰ ± 1.6, respectively) also reflects the influence of high temprature basinal fluids; and (iii) "late" (telogenetic, post‐tectonic) uplift‐related modification starting in the Pliocene, when the incursion of meteoric waters resulted in the formation of vugs, the calcitization of dolomite, and cementation by fracture‐filling blocky calcite. The negative δ18O and δ13C stable isotope values (average: ‐5.5 ‰ ± 1.5; and ‐3.6 ‰ ± 5.9, respectively) of late blocky calcite cement suggest the incursion of meteoric water into the system. This study demonstrates that diagenetic processes in carbonates in the Fahliyan Formation, which exerted a significant control on the distribution of secondary porosity, can be related to the tectonic evolution of the central Zagros fold‐thrust belt. Thus, constraining the diagenetic history of carbonate successions within the context of their wider tectonic evolution is important for the prediction of the spatial and temporal distribution of reservoir quality. [ABSTRACT FROM AUTHOR]

Oil in the Jarvis structure underlying the main Upper Jurassic reservoir at the Ettrick oilfield (Outer Moray Firth, UK northern North Sea) is present in Upper Permian (Zechstein) carbonates. The origin of this "Jarvis oil" is investigated in this paper using a multidisciplinary approach based on data from well‐logs and cores from wells 20/02‐2 and 20/02‐3. Reservoirs at the Jarvis structure consist of carbonates in the upper part of the Halibut Carbonate Formation (Ca2) and in the Carbonate Member of the Turbot Anhydrite Formation (Ca3). These carbonates are typical Zechstein dolomites composed of a range of facies from mudpackstones with storm beds deposited at moderate water depths to shoreface bioclastic‐oolitic packstones to shallow‐subtidal and intertidal microbial laminites. Interbedded anhydrites replace sabkha and lagoonal selenitic gypsum. Several shallowing‐upward units are recognised. Molecular analysis of the Jarvis oil, and comparisons with biomarker and other geochemical data from extracts of Zechstein cores and published data from different source rocks from the North Sea area, suggest that the oil was generated by marine, OM‐rich shales in the Upper Jurassic Kimmeridge Clay Formation. The oil was generated at peak oil window maturity and is characterised by high Pr/Ph, BNH/H and DBT/P ratios, and abundant C28 steranes and C28+29 monoaromatic and C26R + C27S triaromatic steroids. The molecular composition of organic material in extracts of core samples of Zechstein carbonates from wells in the Jarvis structure differs significantly from that of the Jarvis oil. Biomarkers such as BNH are absent in the core extracts, and there are different distributions and abundances of saturated and aromatic hydrocarbons, likely controlled by thermal maturity. [ABSTRACT FROM AUTHOR]

The so‐called East Siberian "Basin" extends over an ancient continental block, the Siberian Platform, and is made up of a number of smaller‐scale basement arches and basins with a variable sedimentary cover of mostly Proterozoic and Palaeozoic ages. The basin hosts the oldest large‐scale petroleum systems known. Proterozoic ("Riphean": 1650‐650 Ma) marine source rocks, which were deposited on the passive margins which surrounded much of the Platform, generated hydrocarbons as they were buried, folded and thermally matured during a series of mostly Late Proterozoic to Cambrian continental collisions, with the final collision taking place in the Early Cretaceous along the northeastern (Verkhoyan) margin. The hydrocarbons were transported by long‐distance migration to reservoirs in the sedimentary successions which drape basement uplifts, there forming giant oil and gas accumulations which were sealed by extensive Cambrian evaporites. Subsequent uplift and unroofing, especially in the north and east of the Platform where the seal is not present, led to degradation of the oil to leave giant accumulations of bitumen, defined here as petroleum with an API gravity of less than 10° which is immobile under reservoir conditions. A significantly younger petroleum system, which may still be active, is present in the Vilyui Basin in the NE of the Siberian Platform. This basin was initiated as a mid‐Devonian rift and has a later Palaeozoic and Mesozoic fill. Bitumen accumulations in the East Siberian Basin occur mainly in Precambrian, Cambrian and Permian reservoir rocks, and began to form from precursor oils during the Permian. Around twenty‐five named fields have been described, many of which comprise portions of more extensive belts of bitumen occurrence. Although geological mapping of natural resources in the East Siberian Basin has been carried out since the 19th century, the region remains under‐explored and none of the bitumen accumulations has yet been developed. An attempt is made in this paper to catalogue and map all recorded occurrences of bitumen throughout the East Siberian Basin. Regional geological studies have been conducted in order to understand the origin and habitat of each occurrence. So far as possible, data on the areal extent and stratigraphic thickness of each bitumen occurrence has been collated, together with data on bitumen saturations and quality. These data were used to calculate resource volumes for each accumulation from first principles. Thus the total bitumen resources within the East Siberian Basin have been calculated as 24,640 MM (million) tonnes. Disregarding accumulations regarded as either of insufficient resource‐density or too small to merit consideration, this figure has been reduced to 14,760 MM tonnes. Recoverable reserves, by analogy with comparable resources worldwide, are calculated as 6100 MM tonnes (approximately 33,900 MM brl) [ABSTRACT FROM AUTHOR]

The sedimentology, petrography and reservoir potential of Pliocene sandstones within the Upper Red Series in the offshore LAM field, Western Turkmenistan, have been examined. Depositional settings are interpreted within the framework of the Red Series palaeoenvironments across the entire Turkmen sector of the Apsheron‐Prebalkhan uplift zone, including its onshore extension to the east. Examination of 81 m of core from three separate intervals suggests that the Red Series in the LAM field is the product of a fluvial‐dominated delta system with associated floodplain deposits, periodically flooded by the saline waters of the South Caspian Lake. Relatively thick sandstones, up to around 5 m thick, are interpreted as channel and point‐bar deposits of a meandering river system, with thinner and finer‐grained sandstones and siltstones inferred to be crevasse‐splay and interdistributary floodplain deposits. Floodplain mudstones display signs of desiccation, soil formation, plant rootlets and occasional thin layers of anhydrite. Intervals with marine trace‐fossil assemblages record incursions of saline‐lake waters. Conglomeratic layers at the base of thicker mudstone intervals may be associated with abrupt transgressions of the lake. The best reservoir qualities are associated with the fluvial channel and point‐bar sandstones. Crevasse‐splay and other overbank sandstones are of poorer quality, while intercalated floodplain to lacustrine claystone/siltstone units may constitute local seals. Eighteen sandstone plug samples from the cored intervals were examined in thin‐section and by XRD and SEM to assess how mineralogy, grain size and diagenesis affect reservoir quality. The samples consist predominantly of lithic arkoses and feldspathic litharenites; higher porosities, and therefore better reservoir potential, are associated with the feldspathic litharenites. Primary controls on porosity include compaction, clay‐matrix content and calcite cementation. XRD data reveal the presence of illite, illite‐smectite and chlorite. The presence of swelling clays has been the main cause of formation damage in the field. The interpretation of meandering fluvial channels here is thought to represent the first published account of such channels within Pliocene reservoir rocks in the north of the South Caspian Basin. Previous accounts of the Red Series sandstones deposited onshore to the east have indicated deposition within braided channels of the palaeo‐Amu Darya river delta plain, and alluvial‐fan deposits sourced from uplands to the north. Deposition of the equivalent Productive Series by the palaeo‐Volga in the Azerbaijan sector to the west has also been interpreted as having taken place within braided systems, although mixed or suspended‐load fluvial channels ascribed to the contemporary Kura delta farther south may have been associated with a meandering system. Two palaeogeographic maps are presented to illustrate depositional environments for the Red Series during relative high‐ and low‐stands of the South Caspian Lake. The maps cover the area where the Productive Series of Azerbaijan passes into the Red Series of Western Turkmenistan. [ABSTRACT FROM AUTHOR]

Lower Cretaceous carbonates in the pre‐salt succession in the Santos Basin, eastern Brazil, are highly heterogeneous in terms of their reservoir characteristics as a result of depositional and diagenetic factors. Electrofacies have widely been used for reservoir zonation and, when allied with computer‐based methods such as neural networks, may help with the study of such complex reservoir rocks and with the identification of high‐quality reservoir zones. In this work, an unsupervised artificial neural network known as a self‐organizing map (SOM) was used to carry out a zonation of the pre‐salt carbonates in the Aptian Barra Velha Formation, the main reservoir unit in the Santos Basin. Available data included gramma‐ray, neutron porosity, resistivity deep, sonic, density, photoelectric factor, total porosity and effective porosity profiles from 21 wells together with mineralogical models. Core descriptions and thin section images were used as additional data for the lithological characterization of the electrofacies and consequently for reservoir zonation. A total of four electrofacies were defined from the SOM application, and five reservoir zones were identified. The characterization of the reservoir zones also considered the structural locations of the wells based on the relative depth to top‐ Barra Velha Formation; well locations were classified as structurally high, intermediate or low. Based on the reservoir zone characteristics, the results could be correlated with zonations in previous studies. A general tendency was noted for there to be an increase of finer‐grained sediments in the formation in wells located in structural lows; packstone and mudstone facies were prevalent in these wells and were in general characterized as poor‐quality reservoir rocks. By contrast, the shrubstones and grainstones which were more frequent in structurally high wells comprised higher quality reservoir rocks. The basal reservoir zone showed wide lithological variation compared to the overlying reservoir zones. Grainstone‐dominated facies were identified in the middle of the formation, and the uppermost reservoir zones were characterized by an upward increase in shrubstones and reworked grainstones which in general pointed to better quality reservoirs. [ABSTRACT FROM AUTHOR]

In order to facilitate the search for new play concepts and exploration opportunities, a sequence stratigraphic synthesis of the Cenomanian–Turonian interval of the Arabian Plate has been compiled. The synthesis is based on published datasets which have been analysed within a temporal framework constrained by biostratigraphy and isotope stratigraphy. The high stratigraphic resolution allows the palaeogeography of the study area to be mapped within 3rd order depositional sequences, and the relative influence of eustacy and tectonics on basin development to be evaluated. This significantly improves the prediction of stratigraphic architecture and depositional morphology at the scale of the entire tectonic plate. Conceptual models informed by outcrop and subsurface observations have been applied to characterize the development of intrashelf basins in depositional settings that are either isolated from siliciclastics (symmetric intrashelf basin model) or influenced by siliciclastics (asymmetric intrashelf basin model). The application of a sequence stratigraphic model across regional well log transects facilitates an understanding of stratigraphic architecture and acts as an important control for the generation of a new suite of gross depositional environment (GDE) maps. These maps characterize the palaeogeography at a previously unprecedented resolution and scale during both periods of high relative sea level (maximum flooding surface and highstand systems tract) and low relative sea level (lowstand systems tract). The maps are complemented by sequence isopachs which reveal changes in accommodation through time and space. This approach helps characterize the preserved distribution and stratigraphic configuration of petroleum systems elements. In the Shilaif (UAE), Natih (Oman) and Sarvak (Iran) intrashelf basins, condensed, organic‐rich carbonate source rocks were deposited in restricted, anoxic conditions. These basins resulted from differential aggradation of the carbonate platform during the transgressive systems tract. Grainy, rudist‐debris –rich carbonate reservoir rocks developed along the margins of the intrashelf basins during highstand progradation. Claystones in the overlying sequence may form intraformational seals and were deposited during retrogradation of the shoreline associated with sea‐level rise. By contrast in the Najaf intrashelf basin (Iraq), there is a significant siliciclastic component sourced from the Arabian Shield. This influx resulted in a mixed carbonate‐siliciclastic ramp depositional system on the proximal, western margin of the basin, and an apparent absence of organic‐rich intervals within the central basin succession. Grainy carbonate reservoir rocks are restricted to the eastern margin and are charged by older source rocks within the underlying stratigraphy. The GDE maps record the configuration of these petroleum systems elements within the Cenomanian–Turonian interval and form the basis for play screening. The Cenomanian–Turonian interval is punctuated by the major mid‐Turonian unconformity which is a tectonostratigraphic boundary of considerable geological and economic significance. In the southern and eastern part of the Arabian Plate, this unconformity has a differential erosion profile that facilitates a subcrop play with exploration potential. Identifying subtle stratigraphic traps is challenging, but by combining GDE facies with the mapped preservation limit for each sequence, it is possible to identify areas where rudist‐rich reservoir facies with potential karst enhancement are overlain by a regional claystone seal, high‐grading areas with subcrop trap potential. [ABSTRACT FROM AUTHOR]

Crude oil reserves in tight Middle and Lower Jurassic reservoirs are of increasing exploration interest in the central Sichuan Basin, SW China. However, the origin of these "tight oils" is poorly understood. In this study, sixteen samples of light oils/condensates from tight Middle and Lower Jurassic reservoir rocks were analysed using gas chromatography (GC) and isotope ratio mass spectrometry to investigate the oils' origin and to classify them into genetic families. The tight oils can be divided into two families. Family I oils occur in the Gongshanmiao oilfield where reservoir units comprise the Da'anzhai Member of the Lower Jurassic Ziliujing Formation, the Lower Jurassic Lianggaoshan Formation, and the First Member of the Middle Jurassic Shaximiao Formation. Family I oils are characterized by relatively low values of the methylcyclohexane (MCH) and cyclohexane (CH) indexes, low values of Mango's parameter K2 for light hydrocarbon composition, and relatively negative δ13C values ranging from ‐30.8‰ to ‐28.9‰. Family I oils are inferred to be self‐sourced by lacustrine shales in the Da'anzhai Member and the Lianggaoshan Formation in the study area, both of which are rich in sapropelic organic matter. These source rocks also charged reservoirs in the First Member of the Shaximiao Formation. By contrast, the newly discovered Family II oils, which occur at the Jinhua oilfield and the as‐yet undeveloped Qiulin and Bajiaochang structures, are reservoired in the Second Member of Shaximiao Formation. Family II oils have higher values of the MCH index, CH index and Mango's K2 parameter, and δ13C values varying from ‐27.5‰ to ‐25.4‰. These oils have similar light hydrocarbon compositions and δ13C values to oils derived from source rocks in the Upper Triassic Xujiahe Formation which contain dominantly humic organic matter. Family II oils are therefore inferred to be derived from the coaly mudstones in the Xujiahe Formation. The different compositions of the tight oils in the First and Second Members of the Shaximiao Formation appear to be controlled by the distribution and thickness of source rocks in the study area. Thus, the Gongshanmiao oilfield where Family I oils occur in the First Member is close to the depocentre of source rocks in the Da'anzhai Member and Lianggaoshan Formation. These source rocks are inferred to have charged the First Member reservoirs which may also be present in nearby oil‐ and gas‐bearing structures such as Nanchong and Yingshan. By contrast, Family II oils occur in tight reservoirs in the Second Member in areas with thick successions of Upper Triassic Xujiahe Formation mudstone source rocks, such as the Jinhua oilfield. In areas where both source rocks are present such as the Zhongtaishan and Lianchi oilfields, Shaximiao Formation reservoirs appear to contain both Family I and Family II oils. [ABSTRACT FROM AUTHOR]

Hydrocarbon reserves of the order of 1140 MM brl oe have been identified in the northern foreland of the eastern Greater Caucasus, principally in the Terek‐Caspian fold‐and‐thrust belt and the Prikumsk Swell in the north of the Terek‐Caspian foredeep. Despite the great economic significance of these areas and their long exploration history, the origin of the hydrocarbons is still poorly understood. In the present paper, geochemical data from 73 oil samples representing 28 fields are used to investigate the presence of oil families and to correlate the oils with potential source rocks. Biomarker composition of oils in Cretaceous and Miocene reservoirs in the Terek‐Caspian fold‐and‐thrust belt is mainly controlled by reservoir depth (100‐5700 m) and maturity (0.70‐1.15 %Ro), and it is therefore difficult to separate maturity and facies effects. For example, a downward increase in diasterane/sterane ratios may indicate a change in source rock facies or may be attributed to increasing maturity. Some shallow oils are biodegraded. The presence of short‐chain n‐alkanes in biodegraded oils indicates recent hydrocarbon migration. Biomarker data (e.g. the presence of oleanane) and compound‐specific isotope data suggest that the Khadum Formation in the lower part of the Maikop Group is the main source rock. However data from Cretaceous and Paleogene organic‐rich rocks, which may also have contributed to the accumulated oils, are urgently needed in order to quantify their possible input. In the Prikumsk Swell, at least two oil families, characterized by low and high C28/C29 sterane ratios respectively, can be distinguished in reservoir rocks of Triassic to Cretaceous age. Most oils are characterized by low C28/C29 sterane ratios and the absence of oleanane ("Group B oils"). These characteristics suggest a pre‐Upper Cretaceous source for the oils, which is also supported by the geological setting. Hierarchical cluster analysis suggests the presence of four sub‐groups (Sub‐Groups B1 to B4). Typically, biomarker ratios in oils in Cretaceous reservoirs are more uniform than those in Triassic and Jurassic reservoirs. Potential source rocks include Lower Triassic deep‐water clayey limestones and shales as well as Middle Jurassic and Aptian‐Albian marine shales. Three oil samples from Triassic and Cretaceous reservoirs form a separate oil family ("Group A"), which is genetically related to oils from the Terek‐Caspian fold‐and‐thrust belt. Group A oils have high C28/C29 sterane ratios and in general contain at least some oleanane. A contribution by Cenozoic source rocks to Group A oils is likely. [ABSTRACT FROM AUTHOR]

Net erosion, the difference between the present‐day and maximum burial depths of a reference unit, may have a major impact on hydrocarbon prospectivity in a sedimentary basin. Erosion may affect all the components of a petroleum system, from source rock to reservoir to seal. In most cases, vitrinite reflectance (VR), temperature and sonic velocity data, which are often readily available, can be used to determine net erosion in a region based on the thermal and mechanical evolution of sedimentary layers with burial. This paper revisits these methods and discusses the determination of net erosion from these datasets. Furthermore, it is shown that a closer look at the data is warranted if the estimates derived from complementary VR/temperature and velocity datasets significantly diverge. Such differences can be reconciled by critically examining the datasets and the regional geology, resulting in erosion estimates from both datasets which are within 100 m of each other. Lastly, a fully automated, process‐driven method combined with multi‐objective optimization algorithms and that takes all three datasets into account is showcased while determining net erosion for three wells located in the Norwegian Barents Sea. One of the benefits of this method is that it explores a wide range of likely scenarios that would best match the different datasets. Furthermore, the method can also automatically flag datasets that are inconsistent with each other by returning an overall low fit score. These datasets can then be critically examined to determine their reliability and to arrive at a more consistent erosion estimate, reducing the error margin to about 100 m. [ABSTRACT FROM AUTHOR]

The only produced offshore gas field in Bangladesh, known as the Sangu field, is located in the Hatiya Trough in the east of the Bay of Bengal, and has estimated total reserves of about 1055 BCF GIIP. The early shut‐down of the field in October 2013 may have resulted in significant volumes of recoverable gas being left in the subsurface over a depth range of 1893 m to 3640 m. In this paper, seismic and well log data were analyzed and interpreted in order to investigate the structure and stratigraphy of the Sangu field, together with the lithology, extent and petrophysical properties of the reservoir. The general lithostratigraphy at Sangu has some similarity to that of the Surma Basin of the Bengal Foredeep. Reservoir rocks consist of Miocene and Pliocene deltaic sandstones and deep‐water clastics. The source rock is the Miocene Bhuban Shale which is mature for gas generation in the Hatiya Trough. Three Neogene seismic stratigraphic megasequences were recognised at Sangu and are interpreted to have been deposited respectively in fluvial, delta front and shelf slope or marginal marine settings. Based on an analysis of wireline logs from wells Sangu‐1 and Sangu‐5 and on seismic‐to‐well ties, a series of reservoir units referred to (from the base up) as the T1 (E, D, C, A&B), Supra‐T1, T2 and T3 have been identified. Petrophysical analyses showed that the average total porosity of these reservoir units is >13%, the permeability is in general less than10 mD, and the gas saturation ranges from 24% to 80%. Mapping of the reservoirs shows that the structure at Sangu is an asymmetric anticline with a NNW‐SSE axial trend. Amplitude data have allowed the delineation of two other potential reservoir zones in the field at depths of 2900‐3000 m and 3550‐3750 m. The study will contribute to future offshore gas exploration and development in the Bay of Bengal region based on the geological and geophysical characteristics of the reservoirs delineated. [ABSTRACT FROM AUTHOR]

The Bongor Basin in southern Chad is an inverted rift basin located on Precambrian crystalline basement which is linked regionally to the Mesozoic – Cenozoic Western and Central African Rift System. Pay zones present in nearby rift basins (e.g. Upper Cretaceous and Paleogene reservoirs overlying Lower Cretaceous source rocks) are absent from the Bongor Basin, having been removed during latest Cretaceous – Paleogene inversion‐related uplift and erosion. This study characterizes the petroleum system of the Bongor Basin through systematic analyses of source rocks, reservoirs and cap rocks. Geochemical analyses of core plug samples of dark mudstones indicate that source rock intervals are present in Lower Cretaceous lacustrine shales of the Mimosa and upper Prosopis Formations. In addition, these mudstones are confirmed as a regional seal. Reservoir units include both Lower Cretaceous sandstones and Precambrian basement rocks, and mature source rocks may also act as a potential reservoir for shale oil. Dominant structural styles are large‐scale inversion anticlines in the Lower Cretaceous succession whilst underlying "buried hill" ‐type basement plays may also be important. Accumulations of heavy to light oils and gas have been discovered in Lower Cretaceous sandstones and basement reservoirs. The Great Baobab field, the largest discovery in the Bongor Basin with about 1.5 billion barrels of oil in‐place, is located in the Northern Slope, a structural unit near the northern margin of the basin. Reservoirs are Lower Cretaceous syn‐rift sandstones and weathered and fractured zones in the crystalline basement. The field currently produces about 32,000 barrels of oil per day. [ABSTRACT FROM AUTHOR]

This study reports on the organic geochemical characteristics of high‐TOC shales in the Upper Triassic Zangxiahe Formation from a study area in the north of the Northern Qiangtang Depression, northern Tibet. A total of fifty outcrop samples from the Duoseliangzi, Zangxiahe South and Zangxiahe East locations were studied to evaluate the organic matter content of the shales and their thermal maturity and depositional environment, and to assess their hydrocarbon generation potential. Zangxiahe Formation shales from the Duoseliangzi profile have moderate to good source rock potential with TOC contents of up to 3.4 wt.% (average 1.2 wt.%) and potential yield (S1+S2) of up to 1.11 mg HC/g rock. Vitrinite reflectance (Ro) and Tmax values show that the organic matter is highly mature, corresponding to the condensate/wet gas generation stage. The shales contain mostly Types II and I kerogen mixed with minor Type III, and have relatively high S/C ratios, high contents of amorphous sapropelinite, low Pr/Ph ratios, high values of the C35 homohopane index (up to 3.58%), abundant gammacerane content, and a predominance of C27 steranes. These parameters indicate a saline, shallow‐marine depositional setting with an anoxic, stratified water column. The source of organic matter was mainly aquatic OM (algal/bacterial) with subordinate terrigenous OM. Zangxiahe Formation shale samples from the Zangxiahe East and Zangxiahe South locations have relatively low TOC contents (0.2 to 0.8 wt.%) with Type II kerogen, suggesting poor to medium hydrocarbon generation potential. Ro and Tmax values indicate that organic matter from these locations is overmature. The discovery of organic‐rich Upper Triassic shales with source rock potential in the north of the Northern Qiangtang Depression will be of significance for oil and gas exploration elsewhere in the Qiangtang Basin. Future exploration should focus on locations such as Bandaohu to the SE of the study area where the organic‐rich shales are well developed, and where structural traps have been recorded together with potential reservoir rocks and thick mudstones which could act as seals. [ABSTRACT FROM AUTHOR]

The Ca Voi Xanh (CVX) gas field is located offshore Vietnam along the eastern margin of the southern Song Hong Basin. Reservoir rocks are carbonates of Middle Miocene (Langhian and Serravallian) age which developed on an isolated platform (length approximately 100 km, and width approximately 15 km) on top of the Triton Horst structural high. Shallow‐water corals and large and small benthic foraminifera are the main faunal constituents of the Langhian carbonates, whereas overlying Serravallian carbonates, the principal reservoir at CVX, are dominated by deeper‐water coralline red algae (rhodoliths) and large benthic foraminifera (LBF). The Serravallian carbonates consist of rhodolith‐LBF grainstones and packstones to mud‐lean packstones. Langhian carbonates consist of coral‐LBF grainstones‐packstone/rudstones. This paper documents the workflow used to develop an integrated sequence‐stratigraphic and reservoir rock‐type framework for the Ca Voi Xanh reservoir, and the impact of this work on reservoir quality prediction and modelling. Sequence stratigraphic interpretations of the Serravallian carbonates are based on data from three wells including detailed sedimentological core descriptions tied to well‐log character. The carbonate succession consists of three third‐order depositional sequences (Ser1, Ser2 and Ser3). Two well‐developed exposure surfaces can be identified: the base‐Serravallian sequence boundary (Ser1 SB), and the base‐Tortonian sequence boundary (Tor1 SB). The Serravallian shows an overall shallowing‐upward trend from carbonates with more horizontally‐oriented coralline red algae (encrusted and bored pavements/hardgrounds) in the lower part of the section, to carbonates with large, roundish irregular rhodoliths towards the upper part. Petrographic thin section, stable isotope (oxygen and carbon), and fluid inclusion analyses confirm a freshwater (vadose and phreatic) diagenetic overprint of the carbonates below the exposure surfaces (sequence boundaries). Partial dolomitization of the Serravallian carbonates was observed at Wells‐2 and ‐3 in the CaVoi Xanh field. Dolomite formation could be related to hydrodynamic fluid interactions associated with the development of a freshwater lense during the top‐Serravallian sea‐level fall (Tor1 SB), favoring dolomitization by sea water during the subsequent sea‐level rise. Alternatively, dolomitization could be related to CO2 and hydrocarbon charging, causing secondary leaching of the Mg‐rich coralline red algae and large benthic foraminifera, leading to an enrichment of the water with Mg‐ions and thus favoring downward dolomitization. A reservoir rock type (RRT) scheme was developed for the Langhian and Serravallian carbonates at the Ca Voi Xanh field based on a combination of depositional environment interpretations together with diagenetic characteristics and reservoir parameters (porosity and permeability).The Langhian is characterized by two RRTs depending on the degree of cementation (RRT‐3L) and dissolution (RRT‐5L). Serravallian RRTs are separated into dominantly packstone (RRT‐1) and dominantly grainstone textures (RRTs‐2, ‐3, ‐5 and ‐6). RRTs with grainstone texture show varying degrees of cementation (RRTs‐2 and ‐3) and dissolution (RRTs‐5 and ‐6). Early diagenetic dolomitization (RRT‐4) preferentially affects packstones (RRT‐1) but also grainstones (RRT‐2, ‐3 and‐5). The geologic (static) model consists of both matrix and non‐matrix components. Sequence stratigraphic concepts in combination with seismically‐derived palaeo‐reconstructions were used to guide the vertical and lateral distribution of reservoir rock types, which comprise the matrix component of the geological model. Different karst geometries and features consistent with known hydrogeologic processes were identified in the seismic discontinuity (variance) cube, and were used to interpret karst regions with different degrees (and/or types) of karst/fractures. These karst regions were used to populate the non‐matrix component of the geologic model along the Ser1 and Tor1 sequence boundaries. [ABSTRACT FROM AUTHOR]

Upper Barremian – Lower Aptian inner platform "Urgonian" limestones in the Mont de Vaucluse region, SE France, consist of alternating metre‐scale microporous and tight intervals. This paper focuses on the influence of structural deformation on the reservoir properties of the Urgonian limestone succession in a study area near the town of Rustrel. Petrographic, petrophysical and structural data were recovered from five fully‐cored boreholes, from the walls of a 100 m long underground tunnel, and from a 50 m long transect at a nearby outcrop. The data allowed reservoir property variations in the Urgonian limestones to be studied from core to reservoir scale. Eleven Reservoir Rock Types (RRTs) were identified based on petrographic features (texture, grain size), reservoir properties (porosity, permeability), and the frequency of structural discontinuities such as fractures, faults and stylolites. Tight and microporous reservoir rock types were distinguished. Tight reservoir rock types were characterised by early cementation of intergranular pore spaces and by the presence of frequent structural discontinuities. By contrast microporous reservoir rock types contained preserved intragranular microporosity and matrix permeability, but had very few structural discontinuities. Observed vertical alternations of microporous and tight rock types are interpreted to have been controlled by the early diagenesis of the Urgonian carbonates. Deformation associated with regional‐scale tectonic phases, including Albian – Cenomanian "Durancian" uplift (∼105 to 96 Ma) and Pyrenean compression (∼55 to 25 Ma), resulted in the modification of the initial petrophysical properties of the Urgonian limestones. An early diagenetic imprint conditioned both the intensity of structural deformations and the associated circulations of diagenetic and meteoric fluids. Evolution of the Reservoir Rock Types is therefore linked both to the depositional conditions and to subsequent phases of structural deformation. [ABSTRACT FROM AUTHOR]

SW Iran and the adjacent offshore are prolific petroleum‐producing areas with very large proven oil and gas reserves and the potential for significant new discoveries. Most of the oil and gas so far discovered is present in carbonate reservoir rocks in the Dehram, Khami and Bangestan Groups and the Asmari Formation, with smaller volumes in the Dashtak, Neyriz, Najmeh, Gurpi, Pabdeh, Jahrum, Shahbazan, Razak and Mishan (Guri Member) Formations. The Permo‐Triassic Dehram Group carbonates produce non‐associated gas and condensate in Fars Province and the nearby offshore. The Jurassic – Lower Cretaceous Khami Group carbonates are an important producing reservoir at a number of offshore fields and in the southern Dezful Embayment, and are prospective for future exploration. Much of Iran's crude oil is produced from the Oligo‐Miocene Asmari Formation and the mid‐Cretaceous Sarvak Formation of the Bangestan Group in the Dezful Embayment. This review paper is based on data from 115 reservoir units at 60 oil‐ and gasfields in SW Iran and the adjacent offshore. It demonstrates that the main carbonate reservoir units vary from one‐another significantly, depending on the particular sedimentary and diagenetic history. Ooidal‐grainstones and rudist‐ and Lithocodium‐bearing carbonate facies form the most important reservoir facies, and producing units are commonly dolomitised, karstified and fractured. In general, reservoir rocks in the study area can be classified into six major types: grainstones; reefal carbonates; karstified, dolomitised and fractured carbonates; and sandstones. The stratigraphic distribution of these reservoir rocks was principally controlled by the palaeoclimatic conditions existing at the time of deposition. A comparative reservoir analysis based on core data shows that dolomitised and/or fractured, grain‐dominated carbonates in the Dehram Group, Lower Khami Group and Asmari Formation typically have better reservoir qualities than the Cretaceous limestones in the Upper Khami and Bangestan Groups. [ABSTRACT FROM AUTHOR]

This paper investigates reservoir quality development in tight Upper Carboniferous fluvial sandstones (Westphalian C/D) in the Lower Saxony Basin, NW Germany. The study integrates data from three outcrops (Piesberg, Woitzel and Hüggel) in the south of the basin with that from two wells (Wells A and B) located at gas fields approximately 50 km to the north. Petrographic and petrophysical data are related to the diagenetic evolution of the sandstones and the burial and structural history of the Lower Saxony Basin. The outcrop and subsurface data sets are compared in order to investigate the factors controlling reservoir quality evolution. Upper Carboniferous fluvial sandstones from the Woitzel and Hüggel outcrops and from Wells A and B have similar matrix permeabilities (0.01 to 10 mD), but matrix porosities vary between Well A (average 6%), Well B (average 10%), Woitzel (average 15%), and Hüggel (average 19%). Permeability reduction during burial is related to the formation of clay mineral cement, which was mainly controlled by variations in both the palaeo‐climate and in the sandstones' depositional composition. Matrix porosity was controlled by local differences in burial history related to basin inversion tectonics. The greater amount of inversion‐related uplift at Well B (about 2.8 km) resulted in lower thermal exposure of the Westphalian sandstones at this location, which thus show higher matrix porosities than the sandstones at Well A which were uplifted by only about 1.2 km. Further increases in porosity in the outcrop sandstones may be related to the dissolution of carbonate cement during late‐stage uplift in near‐surface conditions. Upper Carboniferous fluvial sandstones from the Piesberg quarry show the poorest reservoir characteristics compared to the samples from the subsurface and the other outcrops, with matrix porosities averaging 6% and permeabilities <0.01 mD. Reservoir quality reduction was controlled by thermal anomalies associated with a large fault at the Piesberg quarry. By contrast, a few outliers in the sample data sets from Well B and the Piesberg quarry, which have permeabilities of more than 100 mD, show that faulting or natural fracturing may enhance reservoir quality within a particular area. Faults/fractures may act as potential migration pathways for leaching fluids, or may provide fracture‐permeability systems with production potential. Depositional setting, burial‐related diagenetic processes and structural characteristics in the Lower Saxony Basin need to be carefully evaluated in order to provide an improved understanding of the reservoir quality of the Upper Carboniferous sandstones. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

The Oligocene – Miocene Maikop Series is a world‐class source interval and is the most important source rock for the petroleum systems of the South Caspian Basin and surrounding region. The Maikop is a thick (up to 3 km) succession of silty mudstones with intervals of high organic carbon content. However correlation of organic‐rich intervals within the South Caspian Basin and beyond to basins of the Eastern Paratethys is problematic. Current age constraints are based primarily on microfaunal assemblages, but the assemblages are lacking in precision and are sparsely dispersed. This study provides a numerical age datum for Maikopian strata that may be used to improve correlation of organic‐rich intervals both locally and regionally. The age date obtained was produced via Re‐Os isotope geochronology. Of the five sample suites analyzed, one Re‐Os data‐set yielded an isochron of 17.2 ± 3.2 Ma. Re‐Os data sets that failed to produce statistically meaningful isochrons provide qualitative age constraints by comparing calculated initial 187Os/188Os ratios from these samples to187Os/188Os ratios in seawater through time. [ABSTRACT FROM AUTHOR]

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/m2, 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/m2, 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. [ABSTRACT FROM AUTHOR]

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 Tmax 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 VRo 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 C29 steranes over C27 and C28 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. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

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”. [ABSTRACT FROM AUTHOR]

Although a number of significant oil and gas discoveries have been made within the Western Black Sea and the surrounding area, only sparse data about migration mechanisms are available. In this paper, biomarker and isotope data from five oilfields and one oil show located offshore Bulgaria and Romania (in the western Black Sea), and from one field onshore Georgia (at the margin of the eastern Black Sea), were compared with geochemical data from potential source rock intervals from borehole samples. The source rock data came from offshore Bulgaria and outcrop samples from onshore Georgia. The biomarker data indicates that all the oils analysed were generated by source rocks of Late Cretaceous or Cenozoic age. In the Western Black Sea sub‐basin, the most likely source rocks are Oligocene to Lower Miocene shales of the Maikop Group. Compound‐specific isotope data indicate that Lower Oligocene source rocks are the most significant although a contribution by Lower Miocene diatom‐rich source rocks cannot be excluded. For an oil sample from the Shromisubani field onshore Georgia, isotope data from individual n‐alkanes together with biomarker data indicates that the oil contains a mixture of hydrocarbons generated from the Middle Eocene Kuma Formation and the Oligocene part of the Maikop Group. Oligocene and Miocene source rocks are immature at the shelfal locations where the oil samples were recovered. Charge for these hydrocarbon accumulations is interpreted to have been provided by long‐distance lateral migration from source kitchens in more central parts of the Black Sea basin, where Oligocene and (some) Miocene source rocks are within the oil and gas window. The results of this study highlight the prospectivity of recently‐discovered deep‐water plays, and significantly de‐risk future deep‐water projects within the Black Sea area. [ABSTRACT FROM AUTHOR]

Two separate petroleum systems have been identified in the Austrian sector of the North Alpine Foreland Basin: a lower Oligocene – Cenomanian/Eocene oil and thermogenic gas system; and an Oligocene‐Miocene microbial gas system. Recent studies by both academic and industry‐based research groups have resulted in an improved understanding of these petroleum systems, which are reviewed in this paper. Lower Oligocene organic‐rich intervals (up to 12 %TOC; HI: 400–600 mgHC/gTOC), capable of generating slightly more than 1 t of hydrocarbons/m2, are the source rocks for the thermogenic petroleum system in the Austrian sector of the North Alpine Foreland Basin. The present‐day distribution of this source rock is controlled by submarine mass movements which removed a large part of the organic‐rich interval from its depositional location during the late early Oligocene. The transported material was redeposited in locations to the south which are at the present day buried beneath Alpine thrust sheets. In addition, source rock units were incorporated into Molasse imbricates during Alpine deformation. Hydrocarbon generation began during the Miocene, and the oil kitchen was located to the south of the Alpine thrust front. Hence, lateral migration over distances of up to 50 km was required to charge the mainly Eocene and Cenomanian non‐ and shallow‐marine sandstone reservoir units. Hydrocarbons are in general trapped in structures related to east‐west trending normal faults, and differences in source rock facies resulted in the development of separate western and eastern oil families. Surprisingly, with the exception of some fields in the eastern part of the study area, associated gas contains varying (and sometimes very high) percentages of primary and secondary microbial methane. The composition of oil in some fields is influenced by both biodegradation and water washing. Post‐Miocene uplift in the Austrian sector of the basin had further effects on biodegradation and the consequent formation of secondary microbial gas, and also resulted in re‐migration. The upper Oligocene to lower Miocene succession (Puchkirchen Group, Hall Formation) provides both source and reservoir rocks for the microbial petroleum system in the Austrian sector of the North Alpine Foreland Basin. TOC contents (<1.0 %) and HI values (<140 mgHC/gTOC) of pelitic source rocks are typically low. Microbial gas was generated shortly after deposition during early diagenesis and was subsequently fixed in gas hydrates. Basin subsidence and high sedimentation rates resulted in decomposition of the hydrates below their stability zone, and reservoirs were filled during the early Miocene. Subsequent mixing of microbial gas with thermogenic gas and condensates is widespread. However, biodegradation has prevented precise determination of the fraction of thermogenic hydrocarbons present in gas samples. Reservoir sandstones were deposited within a deep‐marine channel belt along the axis of the North Alpine Foreland Basin, and reservoir quality depends on the precise position within this belt. In the study area, gas is trapped in compaction anticlines or at channel margin pinch‐outs and additional traps are formed by imbrication structures. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

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/m2). 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/m2. 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/m2. 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/m2 in the North Caucasus area and 4 tHC/m2 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/m2, 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. [ABSTRACT FROM AUTHOR]

This study presents a preliminary assessment of the petroleum potential of the Meso-Neoproterozoic Mbuji-Mayi Supergroup in the Sankuru-Mbuji-Mayi-Lomami-Lovoy Basin in the southern-central Democratic Republic of Congo. This basin is one of the least explored in Central Africa and is a valuable resource for the evaluation of the petroleum system in the greater Congo Basin area. Highly altered carbonates (potential reservoir rocks) and black shales (potential source rocks) are present in the Mbuji-Mayi Supergroup, which can be divided into the BI and overlying BII groups (Stenian and Tonian, respectively). For this study, samples of the BIe to BIIe subgroups from five boreholes and two outcrops were evaluated with petrographic, petrophysical and geochemical analyses. Carbonates in the BIe to BIIe subgroups with reservoir potential include oolitic packstones and grainstones, stromatolitic packstones and boundstones, various dolostones, and brecciated and zoned limestones. Thin section studies showed that porosity in samples of these carbonates is mainly vuggy and mouldic with well-developed fractures, and secondary porosity is up to 12%. Black shales in the BIIc subgroup have TOC contents of 0.5-1%, and the organic matter is interpreted to have been derived from precursor Type I / II kerogen. The thermal maturity of asphaltite in carbonate samples is indicated by Raman spectroscopy-derived palaeo-temperatures which range from ∼150 to ∼260°C, which is typical of low-grade metamorphism. Raman reflectance (RmcRo%) values on asphaltite samples were between 1.0 and 2.7%, indicating mature organic matter corresponding to the oil and wet gas windows. Source rock maturation and primary oil migration are interpreted to have occurred during Lufilian deformation (650-530 Ma). The solid asphaltite present in fractures in the dolostones of the BIIc subgroup may represent biodegraded light oil from an as-yet unknown source which probably migrated during the Cambrian-Ordovician (∼540-480 Ma). This migration event may have been related to the effects of the peak phase of Lufilian deformation in the Katanga Basin to the SE. This study is intended to provide a starting-point for more detailed evaluations of potential hydrocarbon systems in the Sankuru-Mbuji-Mayi-Lomami-Lovoy Basin and the adjacent greater Congo Basin area. [ABSTRACT FROM AUTHOR]

Carbonate ramp reservoirs may show a much higher degree of complexity than the schematic and often layer-cake type depositional models which are widely used in exploration and reservoir characterisation, especially in three dimensions. This complexity was investigated in an outcrop study of the Ladinian (Middle Triassic) Quaderkalk Formation (Upper Muschelkalk) from SW Germany. The formation was deposited on an epicontinental, gently inclined carbonate ramp in the regressive part of a third-order depositional sequence and represents a sub-seismic-scale coquina-dominated shoal reservoir analogue. In the study area, coquina carbonates make up a complex system of four stratigraphically separated shoal complexes. The present paper investigates the 1-D to 3-D facies distribution, reservoir architecture and sequence stratigraphic evolution of the largest shoal complex of the Quaderkalk Formation, the Oberer Hauptquader. The object of this outcrop analogue study was to improve the understanding of internal reservoir heterogeneities (such as connectivity and continuity) in similar carbonate shoal complexes in the subsurface. To that end, detailed analyses of 71 quarry outcrop and core samples were carried out, together with the study of more than 400 thin sections, the 2-D analysis of three quarry wall panels and regional-scale 2-D correlations, and facies mapping. This investigation documents significant sedimentological heterogeneities at different scales within the studied shoal reservoir analogue. Instead of a continuous facies belt, a number of separate potential reservoirs form a shoal complex 'mosaic'. Shoal development is controlled by sequence stratigraphic architecture, mainly by cycles which were responsible for shoal expansion during times of regression (forming potential reservoir-volume) and shoal drowning during times of transgression (forming seals and potential stratigraphic traps). Within the individual shoal complexes, thickness and lithofacies types show gradational lateral changes. Correspondingly, lithofacies associations within the studied shoal analogue are not defined by sharp boundaries. Thus the present 'shoals' do not in fact represent discrete 'bodies', as often depicted in reservoir models and as commonly used in reservoir simulation. In addition, shoal-internal sedimentological heterogeneities (potential flow baffles in the subsurface) are strongly influenced by a combination of small-scale cyclicity and event-type deposition. This study therefore demonstrates the need for sedimentological studies of reservoir heterogeneities at various scales in order to decrease uncertainties and risks in exploration and production. [ABSTRACT FROM AUTHOR]

Reconstruction of the burial history and thermal evolution of the Cretaceous - Tertiary Termit Basin, a sub-basin within the larger Eastern Niger Basin of Niger, indicates spatially and temporally variable conditions for organic matter maturation during the basin's multi-phased evolution. Three episodes of tectonic subsidence which correspond to the observed fault mechanical stratigraphy within the Termit Basin are identified: Late Cretaceous, Maastrichtian to early Paleocene, and Oligocene. These episodes fall within the regional tectonic phases of the West African Rift System delineated by previous studies. The basin exhibits substantial heterogeneity in the magnitude of the tectonic episodes and in consequent thermal maturities. For this paper, 1D burial and thermal histories of eight widely dispersed wells in the Agadem permit area in the SW of the Termit Graben were modelled to investigate the maturation of organic matter in source rocks ranging from Santonian to Oligocene in age. The kinetic modelled maturities match with maturities based on Rock-Eval Tmax values for four wells if present-day heat flows are elevated. Future exploration strategies in the Termit Basin should take into consideration these heterogeneities in thermal histories and tectonic pulses, which may lead to the development of hydrocarbon accumulations with different oil-gas compositions in different reservoir compartments. [ABSTRACT FROM AUTHOR]

Reservoir rocks at Gomba oilfield, located in the Hungarian Paleogene Basin, include fractured and karstified Triassic carbonates with significant fluid storage potential. However little information is available about the fracture network in these carbonates which has led to production problems at Gomba. The purpose of this study is to investigate the relationship between the spatial distribution of high porosity zones in the carbonates and the microfracture system. For this evaluation, individual fractures were studied and used in a discrete fracture network (DFN) modelling exercise at two wells, Gomba-1 and Gomba-3. The investigation took place at two different scales. Fracture length and aperture distributions were derived at the micro-scale (mm to cm), whereas fracture density and fracture orientation data were investigated at the reservoir scale. The results of both investigations were taken into consideration in the modelling. The results of the fracture network models were compared to reservoir lithologies which ranged from fractured carbonates to collapse breccias. Based on the results, it appears that the porosity associated with a significant proportion of the fractures was increased as a result of dissolution. Fracture distribution was not uniform along the studied well paths, and fracture orientation was chaotic at particular depth intervals. On the basis of the DFN models, three different fractured zones are predicted to occur in the reservoir, but only two of the zones have significant fracture porosity. Comparing these results with petrographic observations, an epigene karst phase is proposed which is older than (or the same age as) the time of hydrocarbon migration; karst-related voids were therefore important pathways for fluid migration. The void system and karst caverns partly collapsed during subsequent burial, resulting in karst-related traps. By analogy with modern cave systems, the karst cavern zones at Gomba probably extend horizontally rather than vertically, and are oriented NE-SW parallel to major structural lineaments. [ABSTRACT FROM AUTHOR]

Twenty-seven oil samples from Cretaceous, Eocene and Rupelian reservoir rocks in the Alpine Foreland Basin (Austria) were analysed to evaluate the composition of diamondoid hydrocarbons using gas chromatography - triple quadrupole mass spectrometry. The oils were generated from marly and shaly Oligocene source rocks buried beneath the nappes of the Alpine foldbelt to the south of the study area. Diamondoid hydrocarbons were detected in the saturated fraction of all the analysed oils. A biodegraded oil sample from a shallow reservoir in the NE part of the study area showed an enrichment in diamondoids due to the molecule's high resistance to microbial degradation. Variations in the organic matter type of the source rock facies and differences in maturity are known to influence the composition of diamondoids. However in this study, biomarker-derived maturity parameters do not show a convincing correlation with diamondoid maturity parameters. Moreover, no cracking trend based on biomarkers and diamondoid concentrations was observed. The results indicate that the composition of diamondoids in oils from the Austrian part of the Alpine Foreland Basin is mainly controlled by heterogeneities in the Lower Oligocene source rocks, including the occurrence of a redeposited source rock succession in the western part of the study area. By contrast, EAI-1 (the ethyladamantane index) shows a good correlation with various maturity parameters and seems to be independent of source rock facies. [ABSTRACT FROM AUTHOR]

This rift basin is related to producing basins in Chad and Niger which contain proven Lower Cretaceous lacustrine shale source rocks. Deep-marine Oligocene shales may have source rock potential and Miocene fractured turbidite sandstones may represent a reservoir target. Within the CT succession are anoxic source rocks deposited in intrashelf basins, while bioclastic grainstones deposited on basin margins form high quality reservoir rocks. [Extracted from the article]

A thickness of more than 1500m of Palaeozoic (pre-Khuff) siliciclastic strata were encountered in three deep wells (Matbakh A, and Dukhan A and B) drilled in the State of Qatar. These sedimentary rocks have no formal entries in the Qatari Geologic Lexicon and were not included in sequence stratigraphic schemes of the Arabian Plate region. The rocks are investigated here using cores, well logs and other materials. The pre-Khuff succession has been divided from the base up into the Qasim, Qusaiba, Sharawra, Tawil and Unayzah Formations based on age, stratigraphic status, lithology, sedimentary structures and correlation with the Saudi stratigraphic nomenclature. The succession is divided into a series of third-order sequences based on the identification of the principal maximum flooding surfaces. Deposition is interpreted to have occurred in a wide range of environments ranging from fluvial to shallow-marine but with the absence of the glacial facies which are prevalent in the equivalent Saudi section. Core and log analyses indicate that the Qusaiba Formation represents an important source rock which became mature for hydrocarbon generation during the Late Permian; it generated oil until the Late Jurassic and then began to expel gas and condensates, continuing until the present day. Both the Qasim and Sharawra Formations may include potential reservoir rocks which merit further study. The new nomenclature reported here will assist with the understanding of the Palaeozoic palaeogeography across the Arabian Peninsula and will help to delineate reservoir rocks in the Qatari Palaeozoic succession. [ABSTRACT FROM AUTHOR]

Sandstones in the Lower Cretaceous Lower Goru Formation in the Lower Indus Basin, Pakistan, are important reservoir rocks for oil, gas and gas-condensates. For this study, nine metres of core from depths of more than 3400m from well X-1 in the north-central part of the basin were analysed for major variations in porosity and permeability in two Lower Goru sandstone units referred to as the Basal and Massive Sands. The Lower Goru Basal Sand was deposited in lower shoreface to inner shelf settings at the well location, while the Massive Sand was deposited in a middle to lower shoreface setting. In both units, intervals with moderate to good (> 15%) porosities alternate with intervals with very low porosity (<5%), and similar variations in core permeability were observed. In this paper, the reasons for this reservoir quality variation at well X-1 are investigated. Specifically, the study addresses the influence of different clay types on reservoir porosity and permeability within the Lower Goru sands and the distribution and impact of hard cements such as calcite and quartz. A range of petrographical data is integrated including thin sections, whole rock and clay XRD results and SEM images, which together provide some insights into the causes of reservoir quality variation and into the paragenetic relationships between the authigenic minerals. Chlorite grain coats are present in the higher-porosity sandstones and are interpreted to have inhibited the formation of quartz overgrowths. Dissolution of feldspar and volcanic rock fragments in both the Basal and Massive Sands has contributed to an increase in overall porosity at well X-1. Relatively low porosity intervals in the Massive Sand are associated with the absence of chlorite grain coats and the presence of abundant quartz overgrowths. By contrast, low porosity intervals in the Basal Sand have undergone early poikilotopic calcite cementation. The formation of authigenic illite resulted in a significant decrease in permeability in both the Basal and Massive Sands. Chlorite and kaolinite also reduced the permeability. The chlorite originated mainly from the dissolution of volcanic rock fragments or from precursor depositional berthierine clay. The transformation of K-feldspar to illite is suggested to be the main reaction responsible for the formation of both authigenic illite and quartz overgrowths in the two reservoir units; the observed pressure solution will also have contributed to development of quartz overgrowths. [ABSTRACT FROM AUTHOR]

Basaltic lava flows and ignimbrite units around Puerto de Santiago, SW Tenerife, were investigated as potential analogues for hydrocarbon-bearing volcanic reservoir rocks. Conventional helium porosity and air permeability measurements together with the results of a micro-focus X-ray computed tomography study were integrated with field observations on flow morphology and the continuity of defined internal lava flow zones. Individual lava flows typically comprise distinct tops, cores and bases, with lava piles showing repeated cycles of these three internal zones. Reservoir quality is best in the flow tops (mean ϕ = 23.14%, k = 5.622mD) where vesicular porosity dominates. Flow cores are relatively tight with primary porosity mainly controlled by cooling joints, fractures and intercrystalline microporosity (mean ϕ = 2.40%, k = 0.001mD). Flow bases show variable reservoir potential due to the presence of breccia and/or vesiculation (mean ϕ = 11.77%, k = 0.001mD). By contrast, ignimbrites show the highest porosities but have low permeabilities (mean ϕ = 35.64%, k = 0.0056mD). In all cases, the primary porosity and permeability may have been modified to create additional secondary porosity and permeability as a result of fracturing and mineral dissolution during burial or weathering, although porosity may also be occluded through the precipitation of secondary minerals or the alteration of primary minerals. The new porosity data presented demonstrates that pyroclastics and basaltic lava flow tops have the best reservoir properties, with the flow tops having sufficient porosity and permeability to transmit fluids and gas. In contrast, flow cores are relatively tight (impermeable), and would act as seals to potential hydrocarbon accumulations when fractures and cooling joints are absent. The reservoir potential can be high where vesicles and fractures are present (i.e. in lava flow tops), although there is uncertainty whether flow tops could be connected to each other vertically to form a potentially exploitable hydrocarbon reservoir. Although in some areas such volcanic rocks can be primary targets for hydrocarbon exploration (e.g. onshore China), in many others they are considered to be a secondary target, adding incremental resources to hydrocarbons produced from more conventional sandstone and carbonate reservoirs. [ABSTRACT FROM AUTHOR]

Lower Cretaceous meandering and braided fluvial sandstones of the Nubian Formation form some of the most important subsurface reservoir rocks in the Sirt Basin, north-central Libya. Mineralogical, petrographical and geochemical analyses of sandstone samples from well BB6-59, Sarir oilfield, indicate that the meandering fluvial sandstones are fine- to very fine-grained subarkosic arenites (av. Q91F5L4), and that braided fluvial sandstones are medium- to very coarse-grained quartz arenites (av. Q96F3L1). The reservoir qualities of these sandstones were modified during both eodiagenesis (ca. <70°C; <2 km) and mesodiagenesis (ca. >70°C; >2 km). Reservoir quality evolution was controlled primarily by the dissolution and kaolinitization of feldspars, micas and mud intraclasts during eodiagenesis, and by the amount and thickness of grain-coating clays, chemical compaction and quartz overgrowths during mesodiagenesis. However, dissolution and kaolinitization of feldspars, micas and mud intraclasts resulted in the creation of intercrystalline micro- and mouldic macro-porosity and permeability during eodiagenesis, which were more widespread in braided fluvial than in meandering fluvial sandstones. This was because of the greater depositional porosity and permeability in the braided fluvial sandstones which enhanced percolation of meteoric waters. The development of only limited quartz overgrowths in the braided fluvial sandstones, in which quartz grains are coated by thick illite layers, retained high porosity and permeability (12-23% and 30-600 mD). By contrast, meandering fluvial sandstones underwent porosity loss as a result of quartz overgrowth development on quartz grains which lack or have thin and incomplete grain-coating illite (2-15% and 0-0.1 mD). Further loss of porosity in the meandering fluvial sandstones occurred as a result of chemical compaction (pressure dissolution) induced by the occurrence of micas along grains contacts. Other diagenetic alterations, such as the growth of pyrite, siderite, dolomite/ankerite and albitization, had little impact on reservoir quality. The albitization of feldspars may have had minor positive influence on reservoir quality through the creation of intercrystalline micro-porosity between albite crystals. The results of this study show that diagenetic modifications of the braided and meandering fluvial sandstones in the Nubian Formation, and resulting changes in reservoir quality, are closely linked to depositional porosity and permeability. They are also linked to the thickness of grain-coating infiltrated clays, and to variations in detrital composition, particularly the amounts of mud intraclasts, feldspars and mica grains as well as climatic conditions. [ABSTRACT FROM AUTHOR]

Finally, B Tari I et al i . b (paper 8, pp 413-434) investigate the Eocene volcaniclastic sandstones which constitute a reservoir in the Upper Kura Basin and in particular at Samgori, the largest field in Georgia. The following three papers are based on organic-geochemical studies: B Sachsenhofer I et al i . b (paper 4, pp. 287-316) review petroleum systems and oil families in the Rioni and Kura Basins of Georgia using both previously-published and new data; B Yandarbiev I et al i . b (paper 5, pp 317-348) investigate the geochemistry of oils from the foreland to the NE of the Greater Caucasus and correlate them with potential source rocks; and B Aghayeva I et al i . b (paper 6, pp 349-384) focus on the analysis of source rocks in a study area in onshore eastern Azerbaijan. The papers in this thematic issue are devoted to aspects of the petroleum systems in the wider Greater Caucasus area extending over parts of southern Russia, Georgia and Azerbaijan (Fig. [Extracted from the article]

The Embla field, located in the Greater Ekofisk area (Norwegian North Sea), produces oil from Palaeozoic reservoir rocks comprising moderately to well sorted micaceous sandstones and silty mudstones. The reservoir is divided into 'upper' and 'lower' sandstones by a mudstone/siltstone succession, and is overlain by the Jurassic Tyne Group. Below are Palaeozoic mudstones and fractured rhyolites. Bitumen coatings on sand grains and in the fractured rhyolites have been recorded at Embla, and the bitumen may modify the dynamic response of the reservoir during production. In this paper, the organic geochemistry of core extracts and DST oil from well 2-7/26S were analysed by Iatroscan TLC-FID, GC-FID and GC-MS in order to investigate heterogeneities in petroleum composition, thermal maturity and biodegradation between the lower and upper sandstones and the fractured rhyolites, and to investigate the trap filling history. The geochemical data suggest that the reservoir at Embla has received two pulses of oil. The first oil pulse represents a palaeo-filling event which is interpreted to have charged the reservoir around the end of the Triassic. This oil was biodegraded in the reservoir which must therefore have been uplifted to depths of less than ca. 2km (equivalent to ca. 70°C). Because of later burial, the reservoir is at a depth of more than 4km at the present day. This palaeo-oil is compositionally different to most North Sea oils, and may be derived from a source rock containing Type II kerogen. The second more recent oil pulse, comprising 'Ekofisk' type oil, started to refill the Embla structure when the Kimmeridge-equivalent Mandal Formation became thermally mature around the end of the Cretaceous. This second oil migrated along the Skrubbe Fault. Extracts from the upper and lower sandstones are medium to highly mature and show different biomarker and aromatic maturity signatures. The bitumen from the lower sandstone is more mature as indicated by ratios of diasteranes/(diasteranes + regular steranes), 20S/(20S + 20R) steranes, and calculated vitrinite reflectances. Bitumen from rhyolite samples shows the lowest maturity. This suggests that the oil trapped in the fractured rhyolites represents the early oil pulse which did not undergo in-reservoir cracking or biodegradation after its emplacement. [ABSTRACT FROM AUTHOR]

High resolution petrophysical analyses were carried out on Urgonian (Lower Cretaceous) carbonates from outcrops in Provence, SE France. Porosity and permeability were measured on 541 plug samples selected from grain-supported carbonates analogous to those in the age-equivalent Shu'aiba and Kharaib Formation reservoirs in the eastern Arabian Plate. The sampling strategy allowed property heterogeneities from centimetre to kilometre scales to be investigated, as well as correlations between porosity and permeability in several different reservoir rock types. Property spatial modelling sensitivity analyses were also undertaken. The relative abundance of microporosity, grain size and sedimentary-diagenetic anisotropy were the main geological parameters which controlled the petrophysical characteristics of the grainstones studied. Increasing microporosity decreased permeability but resulted in an increase in the homogeneity of the reservoir rocks and therefore in their predictability. An increase in grain size, from fine sand to gravel, and in the amount of intergranular pores, enhanced permeability significantly but resulted in a decrease in the homogeneity (and therefore predictability) of the reservoir rock. At a plug scale, poro-perm relationships are very good and can be used predictively for fine grainstones dominated by microporosity; but relationships are moderate to weak for coarse rudstones with mixed pore types, including intraskeletal pores. In grainstone units, weak sedimentary anisotropy, such as decametre-scale cross-bedding, did not prevent the prediction of the horizontal property distribution from vertical data over a few hundreds of metres. In these units, the lateral correlation of rock properties follows periodic variograms with a 7 m wavelength. The lateral distribution of properties in coarse-grained and heterogeneous rudstones with complex pore types and intense sedimentary heterogeneities, such as channel structures, was however more difficult to predict from a vertical data set. Upscaling poroperm data from plug scale to reservoir scale is linear in the case of grainstones with intergranular microporosity, but is non-linear in the case of skeletal rudstones with coarser pore types including skeletal porosity. [ABSTRACT FROM AUTHOR]

The sulphur, paraffin, resin and asphaltene contents of over 7,100 Cenozoic, Mesozoic and Palaeozoic oils were analysed and were tentatively correlated with reservoir rock age. The data came from 90 oil-bearing basins worldwide. Oil compositions appear to show cyclical changes throughout the Phanerozoic, and these changes can be related to orogenic cycles and marine transgressions and regressions. [ABSTRACT FROM AUTHOR]

The article discusses various reports published within the issue including one about the petroleum systems in the Austrian portion of the North Alpine Foreland Basin, another about source rock geochemistry and basin modelling in the western Black Sea, and one about the Maikopian source rocks.