MIGRATED PETROLEUM IN OUTCROPPING MESOZOIC SEDIMENTARY ROCKS IN SPITSBERGEN: ORGANIC GEOCHEMICAL CHARACTERIZATION AND IMPLICATIONS FOR REGIONAL EXPLORATION

The presence of migrated petroleum in outcropping rocks on Spitsbergen (Svalbard archipelago) has been known for several decades but the petroleum has not been evaluated by modern geochemical methods. This paper presents detailed organic geochemical observations on bitumen in outcrop samples from central and eastern Spitsbergen. The samples comprise sandstones from the Lower Cretaceous Carolinefjellet Formation, the Upper Triassic – Middle Jurassic Wilhelmøya Subgroup and the Upper Triassic De Geerdalen Formation; a limestone from the De Geerdalen Formation; and carbonates from the Middle Jurassic – Lower Cretaceous Agardhfjellet Formation. In addition a palaeo‐seepage oil was sampled from a vug in the Middle Triassic Botneheia Formation. This data is integrated with the results of analyses of C₁–C₄ hydrocarbon fluid inclusions trapped in quartz and calcite cements in these samples. Organic geochemical data suggest that the petroleum present in the samples analysed can be divided into two compositional groups (Group I and Group II). Group I petroleums have distinctive biomarker characteristics including Pr/Ph ratios of about 1.3–1.5, high tricyclic terpanes relative to pentacyclic terpanes, and relatively high methyl‐dibenzothiophenes compared to methyl‐phenanthrenes. By contrast Group II petroleums have low tricyclic terpanes relative to pentacyclic terpanes and low methyl‐dibenzothiophenes compared to methyl‐phenanthrenes, and most Pr/Ph ratios range from 1.90 to 2.57. The petroleum in both groups was derived from marine shale source rocks deposited in proximal to open marine settings. Group I petroleums, present in the sandstones of the Wilhelmøya Subgroup and the De Geerdalen Formation and as a palaeo‐seepage oil in the vug in the Botneheia Formation, are likely to have been sourced from the Middle Triassic Botneheia Formation. Group II petroleums, found in the sandstone of the Carolinefjellet Formation, the limestone from the De Geerdalen Formation and in carbonates of the Agardhfjellet Formation, are inferred to have been generated from the Jurassic‐Cretaceous Agardhfjellet Formation. The analysis of biomarker and aromatic hydrocarbons in the petroleums indicate three relative maturation levels, equivalent to expulsion at vitrinite reflectances of about 0.7–0.8%R_c, 0.8–0.9%R_c and 1.0–1.6%R_c. On average, Triassic host rocks contain petroleum of higher maturity compared to the Jurassic and Cretaceous host rocks. The fluid inclusion data suggest that gaseous hydrocarbons from the sandstones of the Wilhelmøya Subgroup are thermogenic, and are of similar maturity to the petroleum in extracts from these sandstones, suggesting that the gas was generated together with oil in the oil window. By contrast the inclusion gases from carbonate rocks analysed have a mixed (thermogenic / biogenic) origin. The outcropping rocks in which these oils occur are analogous to offshore reservoirs on the Norwegian Continental Shelf. The study may therefore improve our understanding of the subsurface offshore petroleum systems in the Barents Sea and possibly also in other circum‐Arctic basins.     

ORGANIC GEOCHEMISTRY OF BARENTS SEA PETROLEUM: THERMAL MATURITY AND ALTERATION AND MIXING PROCESSES IN OILS AND CONDENSATES

The petroleum system in the Barents Sea is complex with numerous source rocks and multiple uplift events resulting in the remigration and mixing of petroleum. In order to investigate the degree of mixing, 50 oil and condensate samples from 30 wells in the SW Barents Sea were geochemically analysed by GC‐FID and GC‐MS to evaluate their thermal maturity and secondary alteration signatures. Saturated and aromatic compounds from C₁₄–C₁₈ and biomarker range (C₂₀₊) hydrocarbons were compared with light (C₄‐C₈) hydrocarbon alteration and maturity signatures from a previous study. The geochemical data demonstrate that petroleum generation occurred from the early‐ to late‐oil/condensate window, correlating to calculated vitrinite reflection values of between 0.7%R_c and 1.9%R_c. Two maturation traits are in general present in the oil samples analysed and indicate mixing of petroleum phases: a C₂₀₊ fraction which represents a possible “black‐oil ‐related” signature; and a C_20‐ fraction, which is probably a more recent oil charge. However, maturity variations are less pronounced in condensates, which in general exhibit higher generation temperatures than oils but are influenced by severe phase fractionation effects. The samples are characterised by diverse biodegradation signatures including depletion of C_15‐ saturated compounds, almost complete removal of n‐alkanes, elevated Pr/n‐C₁₇ values, high 17α(H), 25‐norhopane content, and a reverse trend in methylated naphthalene distribution. However, the presence of the more recent, unaltered light hydrocarbon charge together with the oil with a palaeo‐biodegraded signature is clear evidence that mixing has occurred. A cross‐plot of C₂₄‐tetracyclic terpane/C₃₀αβ‐hopane versus C₂₃‐C₂₉‐tricyclic terpane/C₃₀αβ‐hopane can be used to discriminate between Palaeozoic/Triassic and Jurassic‐generated petroleums in the Barents Sea region, since it appears to be maturity independent.     

PETROLEUM POTENTIAL, THERMAL MATURITY AND THE OIL WINDOW OF OIL SHALES AND COALS IN CENOZOIC RIFT BASINS, CENTRAL AND NORTHERN THAILAND

Oil shales and coals occur in Cenozoic rift basins in central and northern Thailand. Thermally immature outcrops of these rocks may constitute analogues for source rocks which have generated oil in several of these rift basins. A total of 56 oil shale and coal samples were collected from eight different basins and analysed in detail in this study. The samples were analysed for their content of total organic carbon (TOC) and elemental composition. Source rock quality was determined by Rock‐Eval pyrolysis. Reflected light microscopy was used to analyse the organic matter (maceral) composition of the rocks, and the thermal maturity was determined by vitrinite reflectance (VR) measurements. In addition to the 56 samples, VR measurements were carried out in three wells from two oil‐producing basins and VR gradients were constructed. Rock‐Eval screening data from one of the wells is also presented. The oil shales were deposited in freshwater (to brackish) lakes with a high preservation potential (TOC contents up to 44.18 wt%). They contain abundant lamalginite and principally algal‐derived fluorescing amorphous organic matter followed by liptodetrinite and telalginite (Botryococcus‐type). Huminite may be present in subordinate amounts. The coals are completely dominated by huminite and were formed in freshwater mires. VR values from 0.38 to 0.47%R_o show that the exposed coals are thermally immature. VR values from the associated oil shales are suppressed by 0.11 to 0.28%R_o. The oil shales have H/C ratios >1.43, and Hydrogen Index (HI) values are generally >400 mg HC/g TOC and may reach 704 mg HC/ gTOC. In general, the coals have H/C ratios between about 0.80 and 0.90, and the HI values vary considerably from approximately 50 to 300 mg HC/gTOC. The HI_max of the coals, which represent the true source rock potential, range from ～160 to 310 mg HC/g TOC indicating a potential for oil/gas and oil generation. The steep VR curves from the oil‐producing basins reflect high geothermal gradients of ～62°C/km and ～92°C/km. The depth to the top oil window for the oil shales at a VR of ～0.70%R_o is determined to be between ～1100 m and 1800 m depending on the geothermal gradient. The kerogen composition of the oil shales and the high geothermal gradients result in narrow oil windows, possibly spanning only ～300 to 400 m in the warmest basins. The effective oil window of the coals is estimated to start from ～0.82 to 0.98%R_o and burial depths of ～1300 to 1400 m (～92°C/km) and ～2100 to 2300 m (～62°C/km) are necessary for efficient oil expulsion to occur.     

ORGANIC GEOCHEMISTRY OF MIDDLE MIOCENE (BADENIAN – SARMATIAN) SOURCE ROCKS AND MATURATION MODELLING IN THE POLISH AND UKRAINIAN SECTORS OF THE EXTERNAL CARPATHIAN FOREDEEP

The Carpathian Foredeep to the north and NE of the Carpathian orogenic belt in SE Poland and NW Ukraine is divided into internal and external sectors. In the narrow internal foredeep, Lower and Middle Miocene shales, sandstones and interbedded evaporites are tightly folded. By contrast the external foredeep is characterized by the presence of a thick, unfolded Middle Miocene molasse succession. This ranges in thickness from a few hundred metres in the north of the external foredeep to >5000 m in the south, near the Carpathian thrust front. Middle Miocene sandstones in the external foredeep form a major reservoir for biogenic gas at fields in Poland and Ukraine. The Middle Miocene molasse succession in the external Carpathian Foredeep also contains organic-rich intervals which have source rock potential. For this paper, core samples (n = 670) of Badenian and Sarmatian mudstones from 43 boreholes in the Polish sector of the external foredeep were analysed to investigate their organic geochemistry and hydrocarbon potential. Results show that the samples analysed in general have low to fair (but locally high) total organic carbon (TOC) contents which range up 4.6 wt.% although the average is only 0.7 wt.%. Rock-Eval (S₁+S₂) values are poor to fair and the hydrogen index is also low with a mean value of less than 100 mg/g TOC. The samples analysed are dominated by gas-prone Type III kerogen and this is consistent with previous studies of time-equivalent samples from the Ukrainian part of the external foredeep. The organic matter is in general thermally immature and is interpreted to have been deposited in anoxic and/or sub-oxic conditions. However in the Polish part of the external foredeep, thermal maturities may locally reach the initial phase of the oil window where the Middle Miocene source rocks have been buried deeply beneath the Carpathian thrust front. The burial history and thermal evolution of the Middle Miocene succession were reconstructed by means of 1-D modelling at nine boreholes located in both the Polish and Ukrainian parts of the external Carpathian foredeep. The modelling indicated that Middle Miocene source rocks have only entered the initial phase of the oil window locally where they are buried beneath the flysch nappes of the Carpathian foldbelt. At these locations the generation of thermogenic gas may have begun at depths of more than 3 km. However, Middle Miocene source rocks are still immature at depths of >4000 m in some boreholes in the Ukrainian part of the study area. The absence of accumulations of thermogenic natural gas is consistent with the observed low levels of source rock maturity.     

VERTICAL VARIATIONS IN RESERVOIR GEOCHEMISTRY IN A PALAEOZOIC TRAP,EMBLA FIELD,OFFSHORE NORWAY

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.     

THE OLIGOCENE–MIOCENE MENILITE FORMATION IN THE UKRAINIAN CARPATHIANS: A WORLD‐CLASS SOURCE ROCK

This study investigates the hydrocarbon potential of Oligocene–Miocene shales in the Menilite Formation, the main source rock in the Ukrainian Carpathians. The study is based on the analysis of 233 samples collected from outcrops along the Chechva River in western Ukraine in order to analyse bulk parameters (TOC, Rock‐Eval), biomarkers and maceral composition. In Ukraine, the Menilite Formation is conventionally divided into Lower (Lower Oligocene), Middle (Upper Oligocene) and Upper (Lower Miocene) Members. The Early Oligocene and Early Miocene ages of the lower and upper members are confirmed by new nannoplankton data. The Lower Menilite Member is approximately 330 m thick in the study area and contains numerous chert beds and turbidite sandstones in its lower part together with organic‐rich black shales. The shales have a high content of silica which was probably derived from siliceous micro‐organisms. The TOC content of the shales frequently exceeds 20 wt.% and averages 9.76 wt.%. HI values range between 600 and 300 mgHC/gTOC (max. 800 mgHC/gTOC). The Middle Member contains thin black shale intervals but was not studied in detail. The Upper Member is about 1300 m thick in the study area and is composed mainly of organic‐rich shales. Chert layers are present near the base of the Member, and a prominent tuff horizon in the upper part represents a volcanic phase during shale deposition. The member grades into overlying molasse sediments. The average TOC content of the Upper Menilite succession is 5.17 wt.% but exceeds 20 wt.% near its base. Low T_max and vitrinite reflectance measurements for the Lower (419°C and 0.24–0.34 %R_r, respectively) and Upper (425°C and 0.26–0.32 %R_r, respectively) Menilite Member successions indicate thermal immaturity. Biomarker and maceral data suggest a dominantly marine (Type II) organic matter input mixed with varying amounts of land‐plant derived material, and indicate varying redox and salinity conditions during deposition. Determination of the Source Potential Index (SPI) shows that the Menilite Formation in the study area has the potential to generate up to 74.5 tons of hydrocarbons per m². The Chechva River outcrops therefore appear to have a significantly higher generation potential than other source rocks in the Paratethys realm. These very high SPI values for the Menilite Formation may explain why a relatively small area in Ukraine hosts about 70% of the known hydrocarbon reserves in the northern and eastern Carpathian fold‐thrust belt.     

SOURCE ROCK POTENTIAL OF THE UPPER JURASSIC – LOWER CRETACEOUS SUCCESSION IN THE SOUTHERN MESOPOTAMIAN BASIN,SOUTHERN IRAQ

This paper reports on the hydrocarbon potential of subsurface samples from the Upper Jurassic Lower Cretaceous succession at the Rumaila (North and South), Zubair, Subba and West Qurna oilfields in southern Iraq. A total of 37 fine‐grained core samples of the Sulaiy, Yamama, Ratawi and Zubair Formations from ten wells were analyzed. Contents of organic carbon and sulphur were measured; other analyses included Rock‐Eval pyrolysis, optical microscopy in incident light, solvent extraction and gas chromatography of non‐aromatic hydrocarbons. The results indicated that the samples from the Cretaceous succession (Yamama, Zubair and Ratawi Formations) are at moderate levels of thermal maturity, whereas samples from the Upper Jurassic – Lower Cretaceous Sulaiy Formation are at a stage of thermal maturity beyond peak oil generation. According to the results of this study, the Sulaiy Formation is an excellent highly‐mature source rock and it is probably responsible for the generation of large quantities of oil in the study area. The samples differ with respect to their organic fades and biomarker distribution, indicating that palaeo depositional conditions varied significantly.     

HYDROCARBON POTENTIAL OF THE UPPER CRETACEOUS SUCCESSION AT WELL 16/U‐1, ONSHORE QAMAR BASIN,EASTERN YEMEN

An Upper Cretaceous succession has been penetrated at onshore well 16/U‐1 in the Qamar Basin, eastern Republic of Yemen. The succession comprises the Mukalla and Dabut Formations which are composed of argillaceous carbonates and sandstones with coal layers, and TOC contents range up to 80%. The average TOC of the Mukalla Formation (24%) is higher than that of the Dabut Formation (1%). The Mukalla Formation has a Rock‐Eval T_max of 439–454 °C and an HI of up to 374 mgHC/gTOC, pointing to kerogen Types II and III. The Dabut Formation mainly contains kerogen Type III with a T_max of 427–456°C and HI of up to 152 mgHC/gTOC. Vitrinite reflectance values ranging between 0.3 and 1.0% and thermal alteration index values between 3 and 6 indicate thermal maturities sufficient for hydrocarbon generation. Three palynofacies types were identified representing marine, fluvial‐deltaic and marginal‐marine environments during the deposition of the Mukalla and Dabut Formations in the late Santonian — early Maastrichtian.     

AN INTRODUCTION TO THE PRECAMBRIAN PETROLEUM SYSTEM IN THE SANKURU‐MBUJI‐MAYI‐LOMAMI‐LOVOY BASIN,SOUTH‐CENTRAL DEMOCRATIC REPUBLIC OF CONGO

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 (R_mcR_o%) 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.     

AN OVERVIEW OF THE PETROLEUM SYSTEMS IN THE IONIAN ZONE,ONSHORE NW GREECE AND ALBANIA

The Ionian and Gavrovo Zones in the external Hellenide fold‐and‐thrust belt of western Greece are a southern extension of the proven Albanian oil and gas province. Two petroleum systems have been identified here: a Mesozoic mainly oil‐prone system, and a Cenozoic system with gas potential. Potential Mesozoic source rocks include organic‐rich shales within Triassic evaporites and dissolution‐collapse breccias; marls at the base of the Early Jurassic (lower Toarcian) Ammonitico Rosso; the Lower and Upper Posidonia beds (Toarcian–Aalenian and Callovian–Tithonian respectively); and the Late Cretaceous (Cenomanian–Turonian) Vigla Shales, part of the Vigla Limestone Formation. These potential source rocks contain Types I‐II kerogen and are mature for oil generation if sufficiently deeply buried. The Vigla Shales have TOC up to 2.5% and good to excellent hydrocarbon generation potential with kerogen Type II. Potential Cenozoic gas‐prone source rocks with Type III kerogen comprise organic‐rich intervals in Eocene–Oligocene and Aquitanian–Burdigalian submarine fan deposits, which may generate biogenic gas. The complex regional deformation history of the external Hellenide foldbelt, with periods of both crustal extension and shortening, has resulted in the development of structural traps. Mesozoic extensional structures have been overprinted by later Hellenide thrusts, and favourable trap locations may occur along thrust back‐limbs and in the crests of anticlines. Trapping geometries may also be provided by lateral discontinuities in the basal detachment in the thin‐skinned fold‐and‐thrust belt, or associated with strike‐slip fault zones. Regional‐scale seals are provided by Triassic evaporites, and Eocene‐Oligocene and Neogene shales. Onshore oil‐ and gasfields in Albania are located in the Peri‐Adriatic Depression and Ionian Zone. Numerous oil seeps have been recorded in the Kruja Zone but no commercial hydrocarbon accumulations. Source rocks in the Ionian Zone comprise Upper Triassic – Lower Jurassic carbonates and shales of Middle Jurassic, Late Jurassic and Early Cretaceous ages. Reservoir rocks in both oil‐ and gas‐fields in general consist of silicilastics in the Peri‐Adriatic Depression succession and the underlying Cretaceous–Eocene carbonates with minimal primary porosity improved by fracturing in the Albanian Ionian Zone. Oil accumulations in thrust‐related structures are sealed by the overlying Oligocene flysch whereas seals for gas accumulations are provided by Upper Miocene–Pliocene shales. Thin‐kinned thrusting along flysch décollements, resulting in stacked carbonate sequences, has clearly been demonstrated on seismic profiles and in well data, possibly enhanced by evaporitic horizons. Offshore Albania in the South Adriatic basin, exploration targets in the SW include possible compressional structures and topographic highs proximal to the relatively unstructured boundary of the Apulian platform. Further to the north, there is potential for oil accumulations both in the overpressured siliciclastic section and in the underlying deeply buried platform carbonates. Biogenic gas potential is related to structures in the overpressured Neogene (Miocene–Pliocene) succession.     

THE THERMAL GRADIENT HISTORY OF THE THRACE BASIN, NW TURKEY: CORRELATION WITH BASIN EVOLUTION PROCESSES

Thermal maturity modelling is widely used in basin modelling to help assess the exploration risk. Of the calibration algorithms available, the Easy%Ro model has gained wide acceptance. In this study, thermal gradients at 70 wells in the Thrace Basin, NW Turkey, were calibrated against vitrinite reflectance (%Ro) using the Easy%Ro model combined with an inverse scheme. The mean squared residual (MSR) was used as a quantitative measure of mismatch between the modelled and measured %Ro. A 90% confidence interval was constructed on the mean of squared residuals to assess uncertainty. The best thermal gradient (i.e. minimum MSR) was obtained from the MSR curve for each well, and an average palaeo‐thermal gradient map of the Thrace Basin was therefore created. Calculated thermal gradients were compared to the results of previous studies. A comparison of modelled palaeo‐thermal gradients with those measured at the present day showed that the thermal regime of the Thrace Basin has not changed significantly during the basin's history. The geological and thermal characteristics of the Thrace Basin were compared and the thermal anomalies were evaluated as a function of basin evolution processes. The basin's thermal regime was controlled by: (1) basement edge effects; (2) crustal thickness and basement heat flows; (3) thermal conductivity variations within the stratigraphic column; (4) transient heat flow effects; and (5) the influence of tectonic features. The impact of these factors on variations in the thermal gradients is discussed in detail. Basement edge effects are most marked on the steep northern margin of the basin where heat is preferentially retained in highly conductive basement rocks rather than being transferred into less conductive sedimentary rocks. Thus, heat is significantly focused onto the northern edge of the basement, resulting in a thermal anomaly along the northern basin margin. The margins of the basin, with relatively thick upper crust, have relatively higher thermal gradients compared to the central areas. This is due to radiogenic heat production in the upper crust. Thus, thermal gradients increase above highs and at the margins where thicker upper crust is present. A heat flow map of the Thrace Basin, constructed using a basin‐scale crustal thickness map and a basement heat‐flow algorithm, is presented and demonstrates the heat generation potential of the upper crust. The Eocene Ceylan Formation, which has relatively low thermal conductivity, significantly reduces the thermal gradients by blocking heat transferred from the basement. Areas of high sedimentation rate are associated with low thermal gradients due to the transient heat flow effects of young, thick and “thermally immature” sediments as a function of the heat capacities of these deposits. A direct relationship between thermal gradients and major structural trends could not be established because of a number of factors including the inactivity of the subsurface Miocene fault systems, which did not allow the flow of high temperature fluids through to shallow depths; also, the steady burial and sedimentation rates since the Early Eocene have maintained the pressure system in equilibrium.     

GEOCHEMISTRY OF LITHUANIAN OILS AND SOURCE ROCKS: A PRELIMINARY ASSESSMENT

A series of oils and potential petroleum source-rock samples has been analysed from exploration wells on-and offshore Lithuania. Despite the limited amount of data, the results indicate the possible existence of partly-exhausted source rocks within the Cambrian succession. Furthermore, possible source rocks are present within the Ordovician succession, and excellent source rocks occur within the Silurian in several wells. The source rocks are all present within a few hundred metres of stratigraphic succession, and the thermal maturity roughly follows the actual depth of burial, despite the fact that most of the subsidence and maturation took place in the latest Palaeozoic. The most important reservoir rocks are Middle Cambrian sandstones, but petroleum accumulations also occur in Ordovician limestones and Silurian reefal carbonates. Petroleum accumulations in Lithuania probably result from the pooling of oil derived from several sources, with the Lower Silurian (Llandoverian) shales being the most important single contributor.     

BURIAL AND THERMAL HISTORY MODELLING OF THE EDIACARAN SUCCESSION IN WESTERN AND SW UKRAINE AND MOLDOVA

The Ediacaran (Upper Neoproterozoic) succession in west and SW Ukraine and Moldova rests on a Cryogenian succession or basement. The succession is exposed at the surface along the southern margin of the Ukrainian Shield and dips to the SW towards the Carpathian Overthrust; where burial depths are sufficient, it is mature for oil and gas generation. The Ediacaran succession is made up of terrigenous siliciclastics ranging from conglomerates and sandstones to siltstones and mudstones, and includes a shale interval (the Kalus Beds) which may have source rock potential. Organic matter in the Kalus shales includes Vendotenides sp. (colonial bacteria) together with amorphous OM. This paper presents a study of the Kalus Beds and is based on data from surface and core samples and thin sections, and the results of Rock‐Eval pyrolysis and reflectance analyses. TOC contents in the Kalus shales are in general <0.5 wt%, although the measured TOC was 0.89 wt% and 0.84 wt%, respectively, in samples from the Sokal‐1 borehole and the Mynkivtsi outcrop location in SW Ukraine. The low present‐day TOC in borehole samples may be due to the thermal transformation of the OM originally present. Reflectivity as measured on vitrinite‐like macerals and bitumen in samples from outcrops ranges from 0.63 to 1.28% VR_oeq indicating a relatively low level of thermal maturity. However, the generally low TOC values in the outcrop samples mean that the Kalus Beds in general have little hydrocarbon potential in the study area. The burial and thermal history of the Ediacaran succession in SW Ukraine and the Moldovian Platform was reconstructed, and 1D modelling was carried out at the Brody‐1, Chernivtsi‐1, Dobrotvir‐1, Kolynkiv‐1, Litovyzh‐1, Ludyn‐1, Lyman‐1, Peremyshlyany‐1, Sokal‐1 and Voyutyn‐1 boreholes. The results of modelling indicate that maturities equivalent to the onset of the oil window were reached from the Early Devonian through the Early Carboniferous. Slightly higher modelled maturities occurred in boreholes located near the Teisseyre‐Tornquist Zone. The modelled transformation ratio for kerogen in the Kalus Beds is high and may exceed 90% in the boreholes studied.     

CRETACEOUS CARBONATES IN THE ADIYAMAN REGION, SE TURKEY: AN ASSESSMENT OF BURIAL HISTORY AND SOURCE-ROCK POTENTIAL

The burial history and source‐rock potential of Cretaceous carbonates in the Adiyaman region of SE Turkey have been investigated. The carbonates belong to the Aptian‐Campanian Mardin Group and the overlying Karabogaz Formation. The stratigraphy of these carbonates at four well locations was recorded. At each well, the carbonate succession was found to be incomplete, and important unconformities were present indicating periods of non‐deposition and/or erosion. These unconformities are of variable extent. When combined with the effects of rapid subsidence and sedimentation which took place in the SW of the Adiyaman region during end‐Cretaceous foredeep development, they have resulted in variations in the carbonates' present‐day burial depths, thereby influencing the regional pattern of source‐rock maturation and the timing of oil generation. Burial history curves indicate that the carbonates' maturity increases from SW to NE, towards the Late Cretaceous thrust belt. Predicted levels of maturity for the Mardin Group are consistent with measured geochemical data from three of the wells in the study area (the exception being well Karadag‐1). Three potential source‐rock intervals of Cretaceous age have been identified. Two of these units — the Derdere and Karababa Formations of the Mardin Group — are composed of shallow‐water carbonates which were deposited on the northern margin of the Arabian Platform. The third source‐rock unit, the overlying Karabogaz Formation, is composed of pelagic carbonates which were deposited during a regional transgression. These potential source‐rock intervals contain marine organic matter dominated by Type II kerogen. Total organic carbon contents range from 0.5 to 2.9 %. Time‐temperature analyses indicate that the Mardin Group carbonates are immature to marginally mature at well locations in the SW of the study area, and are mature at western and NE well locations. The onset of oil generation in these Cretaceous source rocks took place between the middle Eocene (48 million yrs ago) and the Oligocene (28 million yrs ago).     

HYDROCARBON EXPLORATION POTENTIAL OF MONTENEGRO – A BRIEF REVIEW

Geological and geophysical data generated during the mid‐1990s and early 2000s indicate that the Montenegro – NW Albania area may have hydrocarbon potential. Thrust‐related structures and sub‐thrust autochthonous Mesozoic platform carbonates in the Dinaride‐Albanide fold‐and‐thrust belt are potential exploration targets. Potential play types include structurally inverted autochthonous platform carbonates both on‐ and offshore Montenegro, and platform build‐up closures located offshore. Potential source rocks are of Cretaceous age, analogous to those at oil discoveries in the Southern Apennines, and have been modelled to generate economic volumes of light oils which may be trapped in fractured shallow‐water carbonates and sealed by deep‐water Oligocene shales. The Neogene succession in Montenegro is dominated by turbidite sandstones which have the potential to contain biogenic gas. Structural and stratigraphic traps have been identified in 2D and 3D seismic reflection profiles but no wells have tested this play to date. However the biogenic gas play is considered to be of less importance than the potential oil play involving Mesozoic carbonates.     

华南地区地幔热源活动对海相碳酸盐岩油气的影响

中生代时期,在华南地区有许多孤立的地慢热源活动,它们对该区中生代地温场有很大的影响.古地温场对沉积层中有机质的热演变及成熟度.油气的运移及保存都有密切的关系.对我国南方海相碳酸盐岩进行含油气远景评价时,不仅要考虑其生油气的地化特征,还应把油气的保存条件列为重要因素来考虑,它要求成油期后地壳变动及上地壳沉积层受地慢热源活动的作用要弱一些.如含油层系地温高于250℃以上,对油气的保存均有不利的影响.由于中生代地温场的不均一性,华南地区古生代油气的保存是因地而异的,大致在雪峰山以西地区相对较好,东部地区相对较差.     

LATE CRETACEOUS TECTONIC AND SEDIMENTARY EVOLUTION OF THE BANDAR ABBAS AREA,FARS REGION,SOUTHERN IRAN

The Upper Cretaceous succession in the SE Zagros (Bandar Abbas area) is characterized by marked changes in fades and thickness. These changes relate to sediment deposition in a foreland basin along the NE margin of the Arabian plate. The succession was measured at eight outcrop sections in the Khush, Faraghun, Gahkum, Genow and Khamir anticlines. The measured sections illustrate a transition from shallow‐water carbonate platform deposits (Cenomanian to Coniacian) to deep‐water fades (Santonian to Maastrichtian). Outcrop observations were compared to data from ten off‐ and onshore wells and to a series of seismic profiles. Four cross‐sections were constructed using well and outcrop data and illustrate fades and thickness variations within the Upper Cretaceous. Based on these regional profiles, the Late Cretaceous depositional history of the Bandar Abbas area was reconstructed and can be divided into two tectono‐sedimentary phases suggesting a transition from a passive to an active margin. Sedimentation during Phase I (late Albion to Coniacian) took place in shallow‐water carbonate platform and intrashelf basin settings (Sarvak Formation), and four third‐order sequences can be recognised. The uppermost sequence is locally capped by fresh‐water, pisolith‐bearing carbonate sand and conglomerates with local laterite and palaeosols of the Coniacian Laffan Formation. Shallow‐water facies consist mainly of wackestone to packstones with abundant benthic foraminifera. Sediments deposited in intrashelf basins are dominated by oligosteginid‐bearing fades. Eustatic variations in sea level, the creation of a foreland basin and salt tectonics most probably controlled patterns of sedimentation during this phase. During the second tectono‐sedimentary phase (Phase II: Santonian to Late Maastrichtian), sediments were dominated by pelagic marls and gravity flow deposits. Lateral thickness variations become more marked to the NE as a result of obduction processes and the creation of the foreland basin. Allochthonous ophiolitic and radiolarite‐bearing units are common in the northern part of the Fars region but are restricted to a few localities in the Bandar Abbas area. Traces of allochthonous materials occur in the SE‐most part of the Khush anticline; thrust slices in offshore seismic profiles may link to the Hawasina nappes of Oman. At the top of the Phase II succession, pelagic facies locally interfinger with Omphalocyclus and Loftusia‐bearing fades (Tarbur Formation) and evaporites (Sachun Formation). These deposits are overlain by slumped and dolomitized shallow‐water carbonates of the Paleocene – Eocene Jahrum Formation. The sedimentary sequence in the Bandar Abbas area illustrates a far‐field response to Late Cretaceous obduction processes and foreland basin development, as well as to halokinetic activity. Rapid variations in thickness and fades document the evolution of depositional processes in the foreland basin.     

STRATIGRAPHIC CORRELATION AND SOURCE ROCK CHARACTERISTICS OF THE BALUTI FORMATION FROM SELECTED WELLS IN THE ZAGROS FOLD BELT,KURDISTAN REGION,NORTHERN IRAQ

The Upper Triassic Baluti Formation has been identified and mapped based on its log response in selected wells from the Zagros foldbelt in the Kurdistan Region of northern Iraq. A preliminary evaluation of the formation's source rock potential was made by Rock-Eval screening analysis in four wells along a NW-SE profile (Atrush-1, Shaikan-5B, Taq Taq-22 and Miran-2) with maturity determined from reflectance measurements in samples from well Taq Taq-22. The Baluti Formation consists of thinly interbedded shales, carbonates and anhydrite ranging in thickness from 48 m in well Atrush-1 to 118 m in well Miran-2. The Rock-Eval screening was conducted primarily on bulk cuttings samples plus selected picked cuttings. The TOC content is low to moderate (0.23 to 1.14 wt%). However, the shale content in many of the analysed bulk samples was relatively low, making assessment of the source potential problematic. The highest TOCs are recorded from the thickest analysed sections from wells Miran-2 and Taq Taq-22, where high-gamma bituminous shales are present. Rock-Eval T_max values ranging from 295 to 438°C are not consistent with estimates of pre-Zagros burial to depths of between 4600 m (Atrush-1) and 6900 m (Miran-2). The relatively low T_max values suggest that the S2 response does not reflect kerogen pyrolysis in these samples and may be due to the presence of solid bitumen, which is observed in the Baluti Formation in at least three of the study wells (Taq Taq-22, Miran-2 and Shaikan-5B). Little pyrolysable organic matter remains in the formation due to the interpreted deep pre-Zagros burial and the consequent high maturity in Taq Taq-22 (VR = 1.51%R_o) and Miran-2 (estimated VR >2%R_o), and the poor source character in Atrush-1 and Shaikan-5B. Organic petrography suggests the presence of vestiges of Types I and II kerogen in Taq Taq-22, with bitumen observed as stains in the matrix of the shales and also in the pores and fractures of interbedded dolostones. However, bitumen reflectance determinations for Taq Taq-22 indicate an equivalent vitrinite reflectance maturity of no more than 0.93%R_o, which is significantly less than that of the indigenous vitrinite, implying the solid bitumen in this well is derived primarily from migrated hydrocarbons. Further detailed analysis is required, but the results suggest that the Baluti Formation may have sourced hydrocarbons in its depocentre which is identified in this study as covering a NW-SE trending area between Bekhme and Sangaw.     

COMPOSITION OF DIAMONDOIDS IN OIL SAMPLES FROM THE ALPINE FORELAND BASIN,AUSTRIA: POTENTIAL AS INDICES OF SOURCE ROCK FACIES,MATURITY AND BIODEGRADATION

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.     

SOURCE ROCK EVALUATION OF COALS FROM THE LOWER MAASTRICHTIAN MAMU FORMATION, SE NIGERIA

The Lower Maastrichtian Mamu Formation in the Anambra Basin (SE Nigeria) consists of a cyclic succession of coals, carbonaceous shales, silty shales and siltstones interpreted as deltaic deposits. Sub‐bituminous coals within this formation are distributed in a north‐south trending belt from Enugu‐Onyeama to Okaba in the north of the basin. Maceral analyses showed that the coals are dominated by huminite with lesser amounts of liptinite and inertinite. Despite high liptinite contents in parts of the coals, an HI versus T_max diagram and atomic H/C ratios of 0.80‐0.90 and O/C ratios of 0.11‐0.17 classify the organic matter in the coals as Type III kerogen. Vitrinite reflectance values (%R_r) of 0.44 to 0.6 and T_max values between 417 and 429°C indicate that the coals are thermally immature to marginally mature with respect to petroleum generation. Hydrogen Index (HI) values for the studied samples range from 203 to 266 mg HC/g TOC and S₁+S₂ yields range from 141.12 to 199.28 mg HC/ g rock, suggesting that the coals have gas and oil‐generating potential. Ruthenium tetroxide catalyzed oxidation (RTCO) of two coal samples confirms the oil‐generating potential as the coal matrix contains a considerable proportion of long‐chain aliphatics in the range C_19‐35. Stepwise artificial maturation by hydrous pyrolysis from 270°C to 345°C of two coal samples (from Onyeama, HI=247 mg HC/g TOC; and Owukpa, HI=206 mg HC/g TOC) indicate a significant increase in the S₁ yields and Production Index with a corresponding decrease in HI during maturation. The Bitumen Index (BI) also increases, but for the Owukpa coal it appears to stabilize at a T_max of 452‐454°C, while for the Onyeama coal it decreases at a T_max of 453°C. The decrease in BI suggests efficient oil expulsion at an approximate vitrinite reflectance of ～I%R_r. The stabilization/decrease in BI is contemporaneous with a significant change in the composition of the asphaltene‐free coal extracts, which pass from a dominance of polar compounds (～77‐84%) to an increasing proportion of saturated hydrocarbons, which at >330°C constitute around 30% of the extract composition. Also, the n‐alkanes change from a bimodal to light‐end skewed distribution corresponding to early mature to mature terrestrially sourced oil. Based on the obtained results, it is concluded that the coals in the Mamu Formation have the capability to generate and expel liquid hydrocarbons given sufficient maturity, and may have generated a currently unknown volume of liquid hydrocarbons and gases as part of an active Cretaceous petroleum system.