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.
The Maikop Group and the Diatom Formation constitute the two main source rocks in the South Caspian Basin and onshore Azerbaijan where large-scale oil production began more than 150 years ago. However, the stratigraphic distribution of the source rocks and the vertical variation of source-rock parameters are still poorly understood. The aim of the present paper is therefore to investigate in high resolution the source-rock distribution in the Perekishkyul and Islamdag outcrop sections, located 25 km NW of Baku, which provide nearly complete middle Eocene and lower Oligocene to upper Miocene successions. Bulk geochemical parameters of 376 samples together with maceral, biomarker and isotope data were analysed. In addition, new Re/Os data provide independent age dating for the base of the Upper Maikop Formation (30.0 ± 1.0 Ma) and the paper shale within the Diatom Formation (7.2 ± 2.6 Ma). The presence of steradienes in high concentrations demonstrates the thermal immaturity of the studied successions, limiting the application of some biomarker ratios.
Intervals with high TOC contents and containing kerogen Type II occur near the top of the middle Eocene succession. However, because of the low net thickness, these sediments are not considered to constitute significant hydrocarbon (HC) source rocks. The Maikop Group in the Islamdag section is 364 m thick and represents lower Oligocene (upper Solenovian) to middle Miocene (Kozakhurian) levels. Samples are characterized by moderately high TOC contents (∼1.8 wt.%) but low hydrogen index (HI) values (average ∼120 mgHC/gTOC) despite a dominance of aquatic organic matter (diatoms, methanotrophic archaea and sulphate-reducing bacteria). Rhenium-osmium chronology suggests low sedimentation rates (∼25 m/Ma), which may have had a negative impact on organic matter preservation. Terrigenous organic matter occurs in variable but typically low amounts. If mature, the Maikop Group sediments at Islamdag could generate about 2.5 tHC/m2.
The Diatom Formation includes a 60 m thick paper shale interval with high TOC contents (average 4.35 wt.%) of kerogen Type II-I (HI up to 770 mgHC/gTOC). The source potential is higher (∼3 tHC/m2) than that of the Maikop Group. The organic matter is dominated by algal material including diatoms. High TOC/S ratios suggest deposition under reduced salinity conditions. Strictly anoxic conditions are indicated by the presence of biomarkers for archaea involved in methane cycling.
For oil-source correlations and a better understanding of the petroleum system, it will be necessary to distinguish oil generated by the Maikop Group from that generated by the Diatom Formation. This study shows that these oils can be distinguished based on the distribution of specific biomarkers e.g. C30 steranes, C25 highly branched isoprenoids (HBIs), and the C25 isoprenoid pent
The Terek-Caspian fold-and-thrust belt along the northern flank of the Greater Caucasus Mountain Range together with the adjacent foreland basin is one of the oldest oil-producing regions in Russia. Despite the long history of exploration, recently acquired seismic data has provided new insights about the structural architecture and evolution of this area. Its structural development during the Neogene was constrained by a syn-extensional tectonic fabric inherited from Jurassic rifting and extension of the Great Caucasus Basin. The structural framework of this basin controlled the distribution of syn-extensional deposits, and the Cenozoic reactivation of lateral ramps resulted in along-strike variations in structural style. Thus western, central and SE segments of the Terek-Caspian foldbelt are recognised and are referred to here as the Terek-Sunzha fold zone, the Dagestan Promontory, and the Maritime Zone in southern Dagestan.
Three principal episodes of Cenozoic compression in the Terek-Caspian fold-and-thrust belt took place. The first episode in the Oligocene resulted in the inversion of pre-existing normal faults with the coeval development of a foreland basin to the north of the thrust belt. The dominance of sediments of northerly provenance in the foreland basin suggests there was only moderate uplift of the Greater Caucasus at this time. However, significant uplift of the orogenic belt took place during later phases of Sarmatian (Late Miocene) and Akchagylian (Late Pliocene) compression. Erosion of the uplifting Greater Caucasus gave rise to the development of large-scale, northerly prograding clinoforms which are clearly observed on seismic profiles in the foreland basin. Shortening was largely accommodated by wedge-shaped thrusting facilitated by the presence of mechanically weak stratigraphic units.
Structural development of the Terek-Sunzha fold zone in the west of the Terek-Caspian fold-and-thrust belt was largely controlled by a Tithonian salt layer which provided an efficient basal detachment surface and which also supplied material to squeezed diapirs in front of the belt. To the east, the plan-view shape and internal architecture of the Dagestan Promontory were influenced by the areal extent of the Lower-Middle Jurassic depocentre of the palaeo-Volga delta which is up to 10 km thick. In the Maritime Zone, the style of shortening was mostly controlled by the presence of a pre-existing structural high composed of folded Palaeozoic-Triassic strata in front of the fold-thrust belt.
A relatively complete section of the Maikop Group (Oligocene – lower Miocene) is exposed along the Sulak River valley in Dagestan (NE Caucasus) and contains a depositional record for this part of the Eastern Paratethys. At the Sulak River outcrop, the Maikop Group is ca. 1200 m thick and can be divided into six lithologically-defined formations: these are from the base up the Khadum Formation (Rupelian), the Miatly Formation, the Lower Clayey Formation, the Mutsidakal Formation (Chattian), the Riki Formation and the Zuramakent Formation (lower Miocene). The Khadum Formation rests on the upper Eocene Belaya Glina Formation and the boundary is marked by a sharp lithological transition from pale-coloured, bioturbated limestones below to black organic-rich shales above.
Biostratigraphic studies of calcareous nannoplankton in samples from the Sulak River section allowed the position of the Eocene – Oligocene boundary at the base of the Maikop Group to be defined. The boundary occurs within the CP16 Zone near the division between the CP16a and CP16b subzones. This is consistent with the age of the boundary at a reference outcrop along the Kheu River in Kabardino-Balkaria in the Central North Caucasus, some 200 km west of Dagestan. A positive oxygen stable isotope anomaly occurs at the top of the Belaya Glina Formation.
Samples of the Maikop Group are characterized by variations in TOC content ranging between 0.14 and 11.06 wt. %. The highest values were measured in both carbonate- and clay-rich samples from the Khadum Formation, and the lowest (less than 0.5 wt.%) in sandstones from the overlying Oligocene Miatly, Lower Clayey and Mutsidacal Formations. Samples of the lower Miocene Riki and Zuramakent Formations have moderate TOC values (on average more than 1.5 wt.%). Results of Rock-Eval pyrolysis show that Maikop samples contain kerogen Types II and III which is distributed unevenly throughout the formations. Clay-rich rocks in the upper part of the Khadum Formation (Solenovian Member) with Type II kerogen have the greatest oil-generating potential, with initial hydrogen index values estimated at 400-600 mg HC/g TOC. The Miatly Formation sandstones and siltstones contain migrated bitumen which is recognized from increased values of Rock-Eval S1 and the high Production Index (S1/(S1+S2). Overlying Oligocene – lower Miocene rocks contain mainly Type III kerogen, although increased TOC values obtained from samples of the Riki Formation indicate that it may have minor gas source potential.
Samples of Maikop Group sediments from the Sulak section were analysed for their contents of Mo, S, Fe, Mn, V, Ni and other elements. A stagnation coefficient (Mo/Mn x 100) was calculated and was interpreted as a measure of the intensity of anoxia in the Maikop palaeobasin. Anoxic conditions are interpreted to have reached a maximum in the Rupelian and Aquitanian during deposition of the Khadum and Riki Formations respectively. However, geochemica
The Neogene Rioni and Kura foreland basins in Georgia are located between the converging Greater and Lesser Caucasus fold-and-thrust belts. The Rioni Basin continues westward into the Black Sea whereas the Kura Basin extends eastward into Azerbaijan and the Caspian Sea. “Pre-” and “post-salt” petroleum systems are distinguished in the Rioni Basin separated by an Upper Jurassic evaporite succession of regional extent. The pre-salt petroleum system in the northern Rioni Basin is still poorly understood. Bathonian shales have generated oil which has been recorded in Middle Jurassic sandstones. However, as the origin of the oil in Upper Jurassic sandstones (e.g. at the Okumi oil discovery) is still problematic, the pre-salt petroleum system remains poorly constrained. Gas-rich, high volatile bituminous coals of Bathonian age may represent a CBM play.
The post-salt petroleum system in the Rioni Basin is charged by two prolific source rock units: the Middle Eocene Kuma Formation and the Oligo-Miocene Maikop Group. The petroleum potential of the Kuma Formation, which is about 40 m thick, is classified as good to very good. The Oligocene part of the Maikop Group is several hundred metres thick and contains source rocks with up to 5 wt.% TOC in its lower part. Additional source rocks are present in Cretaceous and lower Paleogene levels. Oil is produced from fractured Upper Cretaceous carbonates in anticlinal structures below the Neogene unconformity and from Mio-Pliocene siliciclastics in fault-related anticlines. Trap formation and hydrocarbon accumulation is interpreted to have occurred since Maeotian time. Proven oil reserves are very low (∼2 million tons) and suggest low charge efficiency.
Several stratigraphic horizons containing potential source rocks are present in the Kura Basin of eastern Georgia. Although oil-source correlations have yielded unsatisfactory results, the Maikop Group is the most likely source rock, despite its relatively poor petroleum potential which is at best “fair” in the Tbilisi area in the west of the basin. Additional potential source rocks include Middle and Upper Eocene shales. Fractured Middle Eocene volcaniclastic rocks are the best producing reservoirs for hydrocarbons, but oil accumulations are also found in fractured Upper Cretaceous carbonates and in Lower and Upper Eocene, Oligocene and Neogene siliciclastics. Biomarker data suggest a Cenozoic (or Upper Cretaceous) source rock containing abundant terrigenous organic matter. Anticlines and positive flower structures related to compressional tectonics in front of the Greater and Lesser Caucasus fold-and-thrust belts form the main trap types. Samgori-Patardzeuli-Ninotsminda in the Tbilisi region is by far the largest oil field in Georgia and accounts for nearly 90% of the cumulative production of the country (28.5 million tons). The field was probably charged from a kitchen area located to the north. Strike-sl
In the broader Caucasus region, multiple extrusive volcanic units are present within the Jurassic, Cretaceous, Eocene and Miocene sedimentary successions. Partial reworking of volcanic material from various provenance areas into Eocene, Oligocene and Miocene reservoir units is commonly observed in the Eastern Black Sea and in the Rioni, Kartli and Kura Basins of onshore Georgia. Reservoir quality has in general been negatively affected by volcanic rock fragments which may have undergone complex diagenetic alteration. However, despite concerns regarding reservoir quality, oil at the Samgori field, the largest field in Georgia (∼200 MM brl recovered), is hosted in altered Middle Eocene volcaniclastic sandstones interbedded with deep-water turbidites. Previous studies of core material from numerous wells in this field showed that most of the oil is contained in altered, microfractured, laumontite-rich tuffs which have fracture and cavernous net porosities averaging 12% and average permeability of 15 mD. The laumontite tuffs comprise only up to 20% of a tuffaceous sandstone section and occur as isolated lenses or pods on a sub-seismic scale (i.e. 5-10 m thick), causing highly variable oil productivity from one well to another.
The petrographic analysis of samples of Middle Eocene volcaniclastic sandstones from outcrops in the central part of the Kartli Basin around Tbilisi broadly confirms the main conclusions of studies completed some 30 years ago which were based on the analysis of subsurface samples. However, the surface samples analysed show that zeolitization events typically did not improve, but actually reduced, reservoir quality due to extensive zeolite cementation. The poor reservoir properties of the plug samples, which are age-equivalent to the proven subsurface Middle Eocene reservoir interval, highlight fracturing as a key factor controlling the presence of exceptional producers (up to 9000 b/d) in the Samgori field complex. The study therefore underlines the critical role of fracturing of the Middle Eocene volcaniclastic reservoir sequence in the Kartli Basin.
Exploration efforts around the Greater Caucasus region started towards the end of the 19th century and established a wide range of petroleum play types in various basin segments around the orogen. All these plays are associated with the flanks of the inverted thrust-fold belt and the adjacent foreland basin systems, but display significant variation among the basin segments depending on the tectonostratigraphic units involved and the degree of exploration maturity. Whereas the same main source rocks have generated most of the hydrocarbons in all the basins (namely organic-rich shales in the Oligocene – Lower Miocene Maykop Group and the Eocene Kuma Formation), it is primarily the trapping style, both proven and speculative, which is responsible for the broad spectrum of play types observed. Eleven play type diagrams across six main petroleum provinces of the Greater Caucasus region are presented in this paper and summarize the current exploration understanding of the existing discoveries and potential new play targets. These play cartoons offer a prospect-scale summary of both mature producing and underexplored basin segments in a coherent visual manner, and are therefore intended to promote future exploration efforts in the Caucasus region. The testing of new play types requires the proper risking of the two most critical elements in the region: hydrocarbon kitchen effectiveness, and post-charge trap modification. The de-risking of these factors will require properly designed, fit-for-purpose acquisition of modern geological and geophysical data sets.
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