Tertiary Source Rocks Research Articles

An Arctic natural oil seep investigated from space to the seafloor

Due to climate change, decreasing ice cover and increasing industrial activities, Arctic marine ecosystems are expected to face higher levels of anthropogenic stress. To sustain healthy and productive ocean ecosystems, it is imperative to build baseline data to assess future climatic and environmental changes. Herein, a natural oil seep site offshore western Svalbard (Prins Karls Forland, PKF, 80–100 m water depth), discovered using satellite radar images, was investigated using an extensive multiscale and multisource geospatial dataset collected by satellite, aerial, floating, and underwater platforms. The investigated PKF seep area covers roughly a seafloor area of 30,000 m2 and discharges oil from Tertiary or younger source rocks. Biomarker analyses confirm that the oil in the slicks on the sea surface and from the seep on the seafloor have the same origin. Uranium/Thorium dating of authigenic carbonate crusts indicated that the seep had emanated since the Late Pleistocene when ice sheet melting unlocked the hydrocarbons trapped beneath the ice. The faunal communities at the PKF seep are a mix of typical high latitude fauna and taxa adapted to reducing environments. Remarkably, the inhospitable oil-impregnated sediments were also colonized by abundant infaunal organisms. Altogether, in situ observations obtained at the site provide essential insights into the characteristics of high–latitude oil seeps and can be used as a natural laboratory for understanding the potential impacts of human oil discharge into the ocean.

Reconstructing the Age of Formation of some Crude Oil samples from the Niger Delta Basin using Biomarker Fingerprinting

The Niger Delta Basin is a prolific petroleum province and is currently the only basin in which commercial petroleum production strives in Nigeria. The Niger Delta Basin has received a lot of research attention but with fewer studies regarding the reconstruction of the age of source rocks from their crude oils using biomarkers. The study aimed at reconstructing the age of the Niger Delta source rocks from crude oils samples from the Basin. The age determination of the sample set was attempted by looking at individual age-specific biomarkers that suggested a source age as well as looking at them together to have a clearer indication of the likely source age. Thirteen (13) crude oil samples from the “Y” Field of the Niger Delta Basin were subjected to Gas Chromatography-Mass Spectrometer analysis. The biomarkers used in this study were; oleanane index (OI), C28/ C29 ratio, C30 /(C27-C30) ratio, and Pr/Ph (pristane/phytane) ratio, with corresponding mean values of 1.08, 0.76, 0.28, and 1.12 respectively. The biomarker data based on some age-specific biomarkers, both individually and especially when used together, suggests a Tertiary age for the source rock that generated the crude oils. These results are based on the occurrences of oleanane, Pr/Ph ratios, and the high C28/C29 ratios, all indicating Tertiary age source rock.

Hydrocarbon generation and expulsion of tertiary coaly source rocks and hydrocarbon accumulation in the Xihu Sag of the East China Sea Shelf Basin, China

The widely developed Tertiary coal-bearing intervals in the Xihu Sag, East China Sea Shelf Basin in offshore eastern China, are hosted in the Middle-Upper Eocene Pinghu Formation (PHF) and Oligocene Huagang Formation (HGF). Based on field data and geochemical features, a new model for the hydrocarbon generation and expulsion is developed using Rock-Eval pyrolysis that was applied to quantify the potentials of coaly source rocks of the PHF and HGF throughout the Xihu Sag. The results suggest the coaly source rocks of the HGF and PHF are primarily composed of type II/III kerogen, and begin to expel hydrocarbon at 0.68 %Ro and 0.71 %Ro, respectively. Several hydrocarbon expulsion centers are located in the western slope zone for coals and the central anticline zone for mudstones, with the highest intensity of 3.5 × 106 and 24 × 106 t/km2 for coals and mudstones, respectively. Among all source rocks, the coals and mudstones contribute 2.5% and 97.5%, respectively, of the total expelled hydrocarbon, whereas the source rocks of the HGF and PHF provide 19% and 81%, respectively, of the total hydrocarbon. The study also shows that the natural gas discovered in the north of the central anticline zone and the north of the western subsag have mixed sources from the HGF and PHF while the light oil and condensate accumulated in other zones are primarily derived from the source rocks of the PHF. The model used in the Xihu Sag provides an efficient method for evaluating source rocks and identifying oil-gas sources.

Geochemical characterization of crude oils and potential source rocks from southern coastal Ecuador: Hypothetical petroleum systems

This research paper encompasses an organic geochemical investigation on oils and sedimentary rocks from the southern coastal region of Ecuador that examines the hydrocarbon generation and accumulation in the strata of Progreso Basin Province. This petroliferous province represents an interesting area for an oil geochemistry study due to its non-elucidated petroleum systems. The present work focuses on the analysis of eighty-five oils and forty rock samples to determine kerogen types, depositional paleoenvironments, levels of thermal maturity, and in-reservoir petroleum biodegradation stages as well as to assess correlations between source facies and oil samples. Potential source rocks were selected and analysed from different outcrops and wells throughout the basin and the southern Gulf of Guayaquil. Classic biomarker, extended diamondoid, and isotope studies indicated that almost all oils from the Progreso Basin Province underwent biodegradation and were generated from multiple Tertiary source rocks deposited in a marine setting with significant influx of terrestrial organic material. Three families of oils were identified. Oil-source rock correlations suggest that the Socorro, Dos Bocas and San Eduardo formations can be considered as contributors to the studied oils. Geochemical data and previous thermal models point towards two probable hydrocarbon kitchens defined in the deepest parts of the basin as well as a third possible kitchen extended offshore beyond the Santa Elena Peninsula.

The presence of 18α(H)-oleanane in Pennsylvanian and Mississippian rocks in the Anadarko Basin, Oklahoma

Analyses of multiple Mississippian and Pennsylvanian aged source rock samples in the Anadarko Basin, Oklahoma, revealed the presence of a compound that was tentatively identified as 18α(H)-oleanane. The identity of the 18α(H)-oleanane was subsequently confirmed by GCMS, GCMSMS, and coinjection with a sample known to contain 18α(H)-oleanane. The approach to identifying 18α(H)-oleanane was similar to that described in previous publications that have noted the presence of 18α(H)-oleanane in pre-Cretaceous samples. The presence of 18α(H)-oleanane in an Early Mississippian Kinderhookian sample appears to be the earliest reported occurrence to date. 18α(H)-Oleanane has typically been reported to be derived from a Late Cretaceous/Early Tertiary angiosperm source which would appear unlikely in this case since there are no Cretaceous or Tertiary aged source rocks in Oklahoma. This paper discusses possible sources for 18α(H)-oleanane including the suggestion that angiosperms, or angiosperm related species, split off from the gymnosperms far earlier than previously proposed. It is proposed that the data and methods discussed in this paper clearly show the presence of a compound identified as 18α(H)-oleanane in Mississippian and Pennsylvanian age samples. However, the source of the 18α(H)-oleanane still remains unclear.

Modelling hydrocarbon generation and migration in tertiary source rocks of deepwater, Phu Khanh Basin, offshore Vietnam

Modelling hydrocarbon generation and migration in tertiary source rocks of deepwater, Phu Khanh Basin, offshore Vietnam

Modelling hydrocarbon generation and migration in tertiary source rocks of deepwater, Phu Khanh Basin, offshore Vietnam

This study modelled a petroleum system to analyse the history of basin evolution, maturity, and hydrocarbon generation in the deepwater of the Phu Khanh Basin, offshore Vietnam. The paleo-heat flow...

Pre-Tertiary Basement Subcrops Beneath The Malay And Penyu Basins, Offshore Peninsular Malaysia: Their Recognition And Hydrocarbon Potential

Following the successful production from fractured basement in similar Tertiary basins, the basement play was pursued in the Malay Basin, particularly during the 2000-2010 period but, unfortunately, that effort fell short of expectations. The only oil discovery in fractured basement reservoir was Anding in the southwestern part of the basin. Despite its development being delayed due to economic reasons, the Anding discovery had been the basis for the basement play concept: namely, a fractured reservoir formed of pre-Tertiary metamorphic rock, charged from overlying Tertiary lacustrine source rocks in an adjacent half-graben and sealed by a transgressive shale unit. This paper examines seismic, gravity and well evidences on the pre-Tertiary basement geology, with the aim of assessing further the hydrocarbon potential of pre-Tertiary basement. The pre-Tertiary basement subcrops beneath the Malay and Penyu basins represent a continuation of the onshore geology of Sundaland Mesozoic terrane. Wells that penetrate the Base-Tertiary Unconformity (BTU) indicate a variety of rock types including igneous, metamorphic and sedimentary. Seismic data show the widespread presence of layered rocks beneath the BTU which could include potential new plays. Gravity modelling was carried out to help distinguish between pre-Tertiary layered rocks and Tertiary synrift sediments. Fractured reservoirs, like those discovered at Anding, seem to be associated with major strike-slip fault zones which are identifiable on high-quality seismic. Carbonate structures such as paleokarsts and buried hills are also recognisable and could potentially be mapped with seismic. These pre-Tertiary plays also rely on hydrocarbon charge mainly from the overlying Tertiary source rocks. Although Palaeozoic-Mesozoic source rocks may have passed their hydrocarbon generation stage, their gas potential cannot be ruled out.

Source rocks study and thermal modelling in Salawati basin, West Papua

Hydrocarbon in Salawati Basin is generated from Tertiary and Pre-Tertiary source rock. Several source rocks studies have been conducted, such as in Sirga, Kais and Klasafet Formation. Lack of knowledge in characteristics and thermal modelling source rock in Sirga and Pre-Faumai Formation, also curiosity to observe basin reverse polarity occurrence is intriguing to be researched further. The purposes of this research are to know: a.) Sirga and Pre-Faumai Formation source rock characteristics to generate hydrocarbon in Salawati Basin; b.) Maturity values based on %Ro, Tmax and 1D basin modelling. Research methodology was carried out using petroleum geochemistry analysis, including: TOC, Rock Eval Pyrolysis, kerogen typing, vitrinite reflectance from 9 cutting samples. Based on TOC parameter, organic-rich materials in both formations show good to very good quantity. On the other hand, PY parameter shows fair to good potency quality as source rock to generate hydrocarbon. Kerogen type composition dominated NFA which indicates oxidizing marine or lacustrine depositional environment. Sirga and Pre-Faumai Formation show low level maturity based on %Ro and Tmax. On the contrary, based on 1D basin modelling maturity of the source rock on Warir-1X well and WIR-1A (outside research area) show higher level maturity (early to mid-mature) since Middle Pliocene and progressed into late maturity stage on oil generation since Early Pleistocene. Basin polarity reversal occurred since Pliocene and changed basin configuration i.e. depocenter from on southern area becoming on northern area. Sirga and the Pre-Faumai Formation are believed to be the two formations as hydrocarbon generating source rocks in the Salawati Basin based on geochemical characteristics analysis. Maturity based on% Ro shows the level of immature to peak mature.

The study of the oil source in Xiaoliangshan Sag, Northwestern Qaidam Basin, China

The geochemical characteristics of the crude oil in the northwestern and southwestern Qaidam Basin and the Tertiary source rocks of Xiaoliangshan Sag were compared and analyzed. The results show that the Tertiary source rocks of N1 and E32 are the best two sets of source rocks in Xiaoliangshan Sag. The crude oil of the northwestern Qaidam Basin is sourced from nearby Xiaoliangshan Sag rather than Mangya Sag. The crude oil of N22 in the shallow strata of Nanyishan, Jiandingshan and Xiaoliangshan are mainly sourced from the source rocks of N1, while the crude oil of E32 in the deep strata is mainly sourced from the source rocks of E32.

The Sufficiency of Deep Hydrocarbons in the South Caspian Region for Turkey and European Union

The Caspian Sea region did not appear as an important hydrocarbon province during the Soviet Union. This is because that Soviet Russia has very rich and exploitable oil and gas reserves in areas outside the Caspian region. The Caspian Sea coastal states as Azerbaijan, Turkmenistan and Kazakhstan, after gained their independence, have prioritized assessing the hydrocarbon reserves of the region in line with their governance policies and have started to include external partners in their exploration and development study. In order to develop the long known hydrocarbon assets of the region, the exploration efforts carried out have enabled the discovery of new fields especially in the Azerbaijan sector of the southern Caspian region. In addition, hydrocarbons discovered in the onshore areas of both Kazakhstan and Turkmenistan have made the southern Caspian region the world's major hydrocarbon province. The tectonic evolution and petroleum systems of the hydrocarbon-bearing basins called as the North Caspian, Middle Caspian and South Caspian basins in the Caspian Sea region, differ in terms of both essential elements and processes. The most important differences of the South Caspian Basin are rapid deposition of more than twenty-five km thickness sediment fill resulting from an avalanche type sedimentation and the presence of the young Tertiary hydrocarbon source rocks and reservoirs. Therefore, generation-migration, accumulation and trapping processes of the South Caspian Basin petroleum system are still continuing.

Kinetic analysis of hydrocarbon generation based on saline lacustrine source rock and kerogen samples in the western Qaidam Basin, China

Tertiary carbonate rocks from the Qaidam Basin in China are typical plateau saline lacustrine source rocks. Despite the fact that this set of source rocks has a relatively low abundance of organic matter (major frequency of total organic carbon, 0.4–0.6%), the organic matter has a high hydrocarbon conversion rate and commonly forms low-maturity oil. In this study, a comparative analysis was conducted on Tertiary source rock and kerogen samples from the Qaidam Basin using a kinetic experiment of hydrocarbon generation. The objectives of the study were to investigate the mechanism of hydrocarbon generation from source rock to low-maturity oil and the catalysis of kerogen pyrolysis by minerals. The results showed that both the source rock and kerogen samples reached a maximum liquid hydrocarbon yield during the low-maturity stage. Eighty percent of the hydrocarbons were expulsed before the Easy Ro reached 0.8%. Special algal parent materials in the saline lacustrine basin could be the primary cause that leads to generating low-maturity oil. Compared to the kerogen samples, the source rock was more prone to hydrocarbon generation via pyrolysis. The latter had a higher liquid hydrocarbon yield per unit organic matter and a lower activation energy; thus, it entered the hydrocarbon generation threshold earlier. The key factor for the aforementioned differences might be catalysis by minerals (particularly carbonate minerals) and the presence of soluble organic matter in the source rocks.

ORGANIC GEOCHEMISTRY OF OIL AND NATURAL GAS IN THE WEST DIKIRNIS AND EL‐TAMAD FIELDS, ONSHORE NILE DELTA, EGYPT: INTERPRETATION OF POTENTIAL SOURCE ROCKS

Crude oil in the West Dikirnis field in the northern onshore Nile Delta, Egypt, occurs in the poorly‐sorted Miocene sandstones of the Qawasim Formation. The geochemical composition and source of this oil is investigated in this paper. The reservoir sandstones are overlain by mudstones in the upper part of the Qawasim Formation and in the overlying Pliocene Kafr El‐Sheikh Formation. However TOC and Rock‐Eval analyses of these mudstones indicate that they have little potential to generate hydrocarbons, and mudstone extracts show little similarity in terms of biomarker compositions to the reservoired oils. The oils at West Dikirnis are interpreted to have been derived from an Upper Cretaceous – Lower Tertiary terrigenous, clay‐rich source rock, and to have migrated up along steeply‐dipping faults to the Qawasim sandstones reservoir. This interpretation is supported by the high C29/C27 sterane, diasterane/sterane, hopane/sterane and oleanane/C30 hopane ratios in the oils. Biomarker‐based maturity indicators (Ts/Tm, moretanes/hopanes and C32 homohopanes S/S+R) suggest that oil expulsion occurred before the source rock reached peak maturity. Previous studies have shown that the Upper Cretaceous – Lower Tertiary source rock is widely distributed throughout the on‐ and offshore Nile Delta.A wet gas sample from the Messinian sandstones at El‐Tamad field, located near to West Dikirnis, was analysed to determine its molecular and isotopic composition. The presence of isotopically heavy δ13 methane, ethane and propane indicates a thermogenic origin for the gas which was cracked directly from a humic kerogen. A preliminary burial and thermal history model suggests that wet gas window maturities in the study area occur within the Jurassic succession, and the gas at El‐Tamad may therefore be derived from a source rock of Jurassic age.

An overview on source rocks and the petroleum system of the central Upper Rhine Graben

The petroleum system of the Upper Rhine Graben (URG) comprises multiple reservoir rocks and four major oil families, which are represented by four distinct source rock intervals. Based on geochemical analyses of new oil samples and as a review of chemical parameter of former oil fields, numerous new oil–source rock correlations were obtained. The asymmetric graben resulted in complex migration pathways with several mixed oils as well as migration from source rocks into significantly older stratigraphic units. Oldest oils originated from Liassic black shales with the Posidonia Shale as main source rock (oil family C). Bituminous shales of the Arietenkalk-Fm. (Lias α) show also significant source rock potential representing the second major source rock interval of the Liassic sequence. Within the Tertiary sequence several source rock intervals occur. Early Tertiary coaly shales generated high wax oils that accumulated in several Tertiary as well as Mesozoic reservoirs (oil family B). The Rupelian Fish Shale acted as important source rock, especially in the northern URG (oil family D). Furthermore, early mature oils from the evaporitic-salinar Corbicula- and Lower Hydrobienschichten occur especially in the area of the Heidelberg-Mannheim-Graben (oil family A). An overview on potential source rocks in the URG is presented including the first detailed geochemical source rock characterization of Middle Eocene sediments (equivalents to the Bouxwiller-Fm.). At the base of this formation a partly very prominent sapropelic coal layer or coaly shale occurs. TOC values of 20–32 % (cuttings) and Hydrogen Index (HI) values up to 640–760 mg HC/g TOC indicate an extraordinary high source rock potential, but a highly variable lateral distribution in terms of thickness and source rock facies is also supposed. First bulk kinetic data of the sapropelic Middle Eocene coal and a coaly layer of the ‘Lymnaenmergel’ are presented and indicate oil-prone organic matter characterized by low activation energies. These sediments are considered as most important source rocks of numerous high wax oils (oil family B) in addition to the coaly source rocks from the (Lower) Pechelbronn-Schichten (Late Eocene). Migration pathways are significantly influenced by the early graben evolution. A major erosion period occurred during the latest Cretaceous. The uplift center was located in the northern URG area, resulting in SSE dipping Mesozoic strata in the central URG. During Middle Eocene times a second uplift center in the Eifel area resulted in SW-NE-directed shore lines in the central URG and contemporaneous south-southeastern depocenters during marine transgression from the south. This structural setting resulted in a major NNW-NW-directed and topography-driven migration pattern for expelled Liassic oil in the fractured Mesozoic subcrop below sealing Dogger α clays and basal Tertiary marls.

Sedimentology and organic properties of lower Tertiary lacustrine source rocks, Lunpola Basin, central Tibetan Plateau: Implications for hydrocarbon potential

The Tertiary lacustrine Niubao Formation is well exposed in the middle-western part of the Lunpola Basin, central Tibetan Plateau, where crude oil was once discovered during drilling campaigns. Sedimentological, organic petrographic and geochemical work was performed on the upper and middle members of this formation in order to investigate its hydrocarbon source rock potential.Sedimentological analyses indicate that both members were deposited in relatively deep lake conditions away from the influence of big stream system, with the upper Niubao Formation (UNF) having higher sand content. The two members contain abundant high-quality Type I kerogen derived mainly from plankton, algae, and bacteria. Compared with samples of the middle Niubao Formation (MNF), UNF samples also contain more Type II and Type III kerogens of terrestrial origin. Biomarkers of source rock extracts suggest that a long-standing anoxic, stratified, and saline ancient lake occupid the basin during deposition of the two members, which was conducive to the preservation of organic matter. However, higher gammacerane content and the presence of β-carotane in MNF samples imply a more saline lake condition. Rock-Eval Tmax and biomarker parameters reveal marginal maturity and immaturity for samples from MNF and UNF, respectively. Therefore, MNF has better source rocks of higher maturity might be the main hydrocarbon generating member of the basin; similar diagnostic biomarkers and biomarker parameters reported in the crude oil also imply its affiliation with the source rocks of MNF.

Substratum transverse faults in Kuqa Foreland Basin, northwest China and their significance in petroleum geology

The importance of transverse faults in basin evolution and petroleum geology has been often emphasized. However, the transverse faults in the Kuqa Foreland Basin, the most important gas producing area in China, have rarely been studied. Interpreted seismic sections and earthquake focal mechanism solutions, as well as other geological and geophysical data, allow us to identify a few widely-spaced, approximately NS trending, transverse strike-slip faults separating major structural units, and to clarify the geometry and kinematics of these transverse faults hidden below thrust faults. In the Kuqa Foreland Basin, two major structural domains can be distinguished. Transverse faults in the northern Kuqa Foreland Basin are mainly NNE trending sinistral, indicating clockwise-rotation of fault-bounded blocks. In contrast, the predominant NW trending dextral faults in the southern Kuqa Foreland Basin imply counterclockwise-rotation of fault-bounded blocks. We propose a tectonic model in which crustal blocks are bounded by strike-slip faults in a zone of simple shear rotation about vertical axis. The strike-slip faulting and thrust faulting in the Kuqa Foreland Basin suggest that some of the convergence between South Tianshan and Tarim blocks may have been accommodated not only by obvious crustal shortening and thickening along thrust faults, but also by rotation and possible lateral movement of the crust along transverse faults. Controlled by the remote collision of Indian block with Eurasian block since the Miocene, these reactivated substratum faults, which may inherit from Paleozoic deformation, control various elements relevant to gas accumulation in the Kuqa Foreland Basin which should expect to be paid more attention in the future. These elements include maturity of Tertiary and Jurassic source rocks, a difference in the regional cap of Kumugelimu salt beds from east to west, reservoir bed properties, gas migration channels, and traps formation. In addition, the strike-slip faulting of the transverse faults may affect deformation of the sedimentary cover, including making the western Qiulitag structural belt to form an arcuated structure curved to the SSW.

The Kinetics of Oil Generation in a Saline Basin: A Case Study of the Source Rock of Tertiary in Zhahaquan Depression, Qaidam Basin, China

Pyrolysis of source rocks and kerogen isolated from the source rocks, which was collected from the Tertiary in Zhahaquan Depression, Qaidam Basin, China, was performed in a confined system. The kinetics for generation of crude oil from the source rocks and kerogen were studied and the kinetic parameters applied to modeling generation from the Tertiary source rocks on the basis of burial and thermal history of the Zhahaquan Depression. The results of kinetic modeling show that the source rocks entered the “oil window” a little earlier than the kerogen, however, it could be ignored in the geological time, which means that the catalytic role of the salts on the role of hydrocarbon generation control is weak. In addition, the elemental analysis data of kerogen shows that the high sulfur content, which might be the main reason of immature-low mature oil generation in Tertiary salinization Qaidam Basin.

Evaluation of bio-molecular signatures and hydrocarbon potential of upper Cretaceous shale, NE Nigeria

The Bornu Basin is a sector of the Chad Basin located in the northeastern part of Nigeria, occupying about one-tenth of total area in Chad Basin. Twenty-eight representative shale cutting samples retrieved from Tuma-1, Sa-1 and Albarka-1 exploratory wells were analyzed. Seventeen shale samples systematically selected from Gongila, Fika Shale and Chad Formations were subjected to Total Organic Content (TOC), Rock–Eval pyrolysis, Soluble Organic Matter, Liquid Chromatography, Gas Chromatography and Gas Chromatography/Mass Spectrometry analyses. This is to characterize and assess the potential capability of the shale units.The results showed that TOC of the Coniacian–Paleocene shale units exceed the threshold (0.5wt%) needed for petroleum generation. This classifies it as potential source beds. Evidence from biomarkers indicates a preponderance of marine organic matter with subordinate terrigenous input. The quantity of gammacerane occurrence suggests normal saline environment. The presence of oleanane index indicates angiosperms input into Cretaceous–Tertiary source rock. C35/C34 homohopane ratio showed the anoxia development towards the center of the basin. C29ααα (20R)/C27ααα (20R) sterane ratio indicate the dominance of marine organic matter with subordinate terrigenous input. The 22S/(22S+22R) ratio of C31 hopane have not reached equilibrium as evident by immaturity to early mature stages from diagnostic ratios of βα moretane/αβ hopane, Ts/(Ts+Tm), 28,30-bisnorhopanes/17α-hopanes, diasteranes/regular steranes, ααα steranes/αββ steranes and 20S/(20S+20R) C29 regular steranes respectively. This is corroborated with the Rock–Eval indices showing immature to earlier mature kerogen within the Fika Formation. It consists preeminently of Type IV, with subordinate Type III. The prospect for hydrocarbon in this part of the basin is only fair to moderate with potential for gaseous rather than liquid hydrocarbon.

Hydrocarbon occurrences and petroleum geochemistry of Albanian oils

Oil accumulations occur in the Ionian zone limestone section and in the Adriatic Basin sandstone reservoirs of Tortonian and Messinian age, respectively.A large set of geochemical compositional data of Albanian oils have been analysed. Oil entrapment occurred during two main phases: 1) during the Early Miocene, when the main part of source rocks were in the oil maturity window; 2) during the Pliocene, when the source rocks were in a more advanced stage of oil genesis. The multiphase genesis has resulted in hydrocarbon accumulations with a broad range of geochemical characteristics. Both individual fieldsand in field complexes, biodegraded and non-biodegraded heavy oils, light oils, condensates, wet and dry gas may occur. In general, oil density and sulphur content decrease with depth.Oil grouping is evident from the data set, although stable carbon isotope values suggest that the Berat Belt oils and the Adriatic Basin oils are slightly different from the majority of oils in the Kurveleshi Belt. No exact correlations between the oils and the individual carbonate source rock levels could be established.The Tertiary humid source rock has been matured probably in the early stage, and has generated dry gas and some immature condensates.The gas accumulations in the Adriatic Basin consist mostly in pure biogenic and mixed thermogenic/ biogenic gases. The deeper classic reservoirs contain relatively less dry gas.

Geochemical characteristics of Tertiary coal-bearing source rocks in Xihu depression, East China Sea basin

This study aims at investigating hydrocarbon generation potential and biological organic source for the Tertiary coal-bearing source rocks of Pinghu Formation (middle-upper Eocene) in Xihu depression, East China Sea shelf basin. Another goal is to differentiate coal and mudstone with respect to their geochemical properties. The coal-bearing sequence has a variable organofacies and is mainly gas-prone. The coals and carbonaceous mudstones, in comparison with mudstones, have a higher liquid hydrocarbon generation potential, as reflected by evidently higher HI values (averaging 286mg HC/g C) and H/C atomic ratios (round 0.9). The molecular composition in the coal-bearing sequence is commonly characterized by unusually abundant diterpenoid alkanes, dominant C29 sterane over C27 and C28 homologues and high amount of terrigenous-related aromatic biomarkers such as retene, cadalene and 1, 7-dimethylphenanthrene, indicating a predominantly terrigenous organic source. The source rocks show high Pr/Ph ratios ranging mostly from 3.5 to 8.5 and low MDBTs/MDBFs ratios (<1.0), indicating deposition in an oxic swamp-lacustrine environment. The coals and carbonaceous mudstones could be differentiated from the grey mudstones by facies-dependent biomarker parameters such as relative sterane concentration and gammacerane index and carbon isotope composition. Isotope and biomarker analysis indicate the genetic correlation between the Pinghu source rocks and the oils found in Xihu depression. Moreover, most oils seem to be derived from the coal as well as carbonaceous mudstone.