Potential Hydrocarbon Source Rocks Research Articles

Biostratigraphic correlation of the Ordovician black shales in Tarim Basin and its peripheral regions

Ordovician black shales are widely distributed in the Tarim Basin and its peripheral regions, and some of them may serve as potential hydrocarbon source rocks. The present study of the Ordovician graptolite fauna from these shales, together with the yielded conodonts and chitinozoans etc., permits a refined correlation of the rocks. Based mainly on a new collecting of the graptolites and a study of the faunas in Kalpin and Kuruktag regions, and the successful identification of the new graptolite material from a few drill cores within the basin, we are able to update our knowledge of the Ordovician in the regions, and draw some conclusions: (1) The most widespread distribution of the black shales in the Tarim Basin and its peripheral regions, which correspond to the Nemagraptus gracilis Zone, may be related to a global sea-level rise during this time interval. (2) Black shales of Ordovician occur most frequently and extensively in the Kuruktag (also spelled as Quruq Tagh) region in eastern Tianshan Mountains, spanning Tremadocian to mid-Katian (D. spiniferus Zone) temporally and extending southeastwards into Manjiaer Depression. The black shales of the D. spiniferus Zone may even extend into the central Tarim Basin. (3) Three different bio- and litho-facies belts (Bachu: carbonate platform and reef belt; Kalpin-Aksu: marginal platform and upper slope belt; Wushi: slope belt) are recognized in the northwestern Tarim Basin. (4) The internationally well-correlated Saergan black shale, which has been considered to possess high potential for hydrocarbon source rock, may possess a restricted distribution in the Kalpin and Aksu areas.

Assessment of hydrocarbon potential of Jurassic and Cretaceous source rocks in the Tarnogród-Stryi area (SE Poland and W Ukraine)

Assessment of hydrocarbon potential of Jurassic and Cretaceous source rocks in the Tarnogród-Stryi area (SE Poland and W Ukraine) The Jurassic/Cretaceous stratigraphic complex forming a part of the sedimentary cover of both the eastern Małopolska Block and the adjacent Łysogóry-Radom Block in the Polish part as well as the Rava Rus'ka and the Kokhanivka Zones in the Ukrainian part of the basement of the Carpathian Foredeep were studied with geochemical methods in order to evaluate the possibility of hydrocarbon generation. In the Polish part of the study area, the Mesozoic strata were characterized on the basis of the analytical results of 121 core samples derived from 11 wells. The samples originated mostly from the Middle Jurassic and partly from the Lower/Upper Cretaceous strata. In the Ukrainian part of the study area the Mesozoic sequence was characterized by 348 core samples collected from 26 wells. The obtained geochemical results indicate that in both the south-eastern part of Poland and the western part of Ukraine the studied Jurassic/Cretaceous sedimentary complex reveals generally low hydrocarbon source-rock potential. The most favourable geochemical parameters: TOC up to 26 wt. % and genetic potential up to 39 mg/g of rock, were found in the Middle Jurassic strata. However, these high values are contradicted by the low hydrocarbon index (HI), usually below 100 mg HC/g TOC. Organic matter from the Middle Jurassic strata is of mixed type, dominated by gas-prone, Type III kerogen. In the Polish part of the study area, organic matter dispersed in these strata is generally immature (Tmax below 435 °C) whereas in the Ukrainian part maturity is sufficient for hydrocarbon generation.

Formation Pressure Evolution in Lynedoch Fields, Northern Bonaparte Basin, Australia

The Lynedoch Fields are located in the flanks of Calder Graben. Wells lynedoch-1, lynedoch-2 and Seismic line N11809 are selected to evaluate the pressure evolution history, investigate the mechanisms of overpressures generation and the timing of oil and gas generation from the potential hydrocarbon source rock. Three areas of pressure evolution were identified namely normal pressure, slight excess pressure and intense excess pressure. The pressure releases are consistent with the tectonic events increasing with depth and dissipating laterally. The peak of excess pressure generation, the peak sedimentation rates in wells Lynedoch-1 and Lynedoch-2 and the peak generation of oil and gas of the same wells were occurred during the Late Cretaceous at 65Ma. High sedimentation rates with rapid subsidence and oil and gas generation are the main favorable conditions for overpressure generation in the study area.

New potential hydrocarbon source-rocks in the Lower Eocene Metlaoui Formation (Central-Northern Tunisia, Northern Africa)

Significant quantities of organic matter accumulated and were preserved in central-northern Tunisia during the Ypresian (Early Eocene). The organic geochemical characterization of the organic-rich facies of the Ypresian Metlaoui Formation (Ousselat and Es-Sfeia sections) shows their significant potential as source rocks and increases interest in the Central-Northern Tunisia oil play. The TOC content in these rocks ranges from 0.09 to 3.71% suggesting their petroleum potential, whereas their T max fluctuates from 429 to 439°C. These values and the predominance of the hetero compounds (NSO; 2-95%) point to low organic matter maturation. The diverse maturity levels reported for these organic-rich rocks never reached the conventional oil window peak stage and resulted from their different locations within the basin. The HI values and the high saturate concentrations (1-91%) compared to aromatics (1-33%), as well as the predominance of short-chain n-alkanes centered atn-C18 and n-C20 are indicative of unequivocal type-II kerogen. The fluctuation of the pristane/phytane ratio (0.97-2.53) records changes of the basin redox conditions, which mainly evolved around the sub-oxic range.

Neoproterozoic deglacial sediments and their hydrocarbon source rock potential

Abstract Many Neoproterozoic successions contain viable hydrocarbon source rocks, even though they were deposited before most extant life forms evolved. Eukaryotic microalgae, bacteria, chlorophyte micoalgae, marine pelagophyte algae and dinoflagellates may have contributed organic matter. Major global-scale glaciations, which are commonly attributed to a ‘snowball’ or ‘slushball’ Earth scenario, or deposited under a ‘zipper rift’ scenario, are believed to have played an important role in the deposition of hydrocarbon source rocks during the mid- Neoproterozoic (Cryogenian). Phases of Cryogenian deglaciation may have culminated in the deposition of high total organic carbon shales and ‘cap carbonates’ in restricted anoxic basins, which may have been carved by ice sheets themselves or, alternatively, formed as restricted extensional half graben as Rodinia began to fragment. One example of these organically enriched deglacial sediments comprises shales and dolostones deposited following the Sturtian glaciation in the Centralian Superbasin of Australia, an amalgam of basins that extends almost continent-wide across Australia. Data from the Marmot MMDD-1 drill core on the Stuart Shelf in the southern part of the Centralian Superbasin, together with previously published data on organic enrichment in the Amadeus Basin in the central part of the Centralian Superbasin, suggest that the deposition of organically enriched shales was widespread during the Sturtian deglaciation.

Upper Ordovician conodont biostratigraphy and the age of the Collingwood Member, southern Ontario, Canada1Earth Science Sector (ESS) Contribution 20100302.

The Upper Ordovician stratigraphy in southern Ontario represents the clastic foredeep associated with the Appalachian Taconic Orogeny transitioning northwest into coeval carbonate platform facies. Ten measured and sampled sections in both the Collingwood area and on Manitoulin Island, Lake Huron, provide two relatively complete composite sections (277 and 95 m, respectively) through the marine part of the sequence. A total of 100 2 kg samples collected for a conodont biostratigraphic study yielded 77 215 well-preserved specimens. Taxonomic study of the fauna, illustrated herein, identified 34 species representing 22 genera and three taxa in open nomenclature. Taxonomic revisions are made to five species of Pseudobelodina and one of Rhipidognathus ; a new species, Pseudobelodina microdentata , is established. The fauna primarily represents the Midcontinent Province with incursions from the North Atlantic Province primarily in the Collingwood area. Four conodont zones are recognized that help refine the ages for the Upper Ordovician upper Lindsay (Collingwood Member), Blue Mountain, Georgian Bay, and Queenston formations. In particular, the Collingwood Member of the Lindsay Formation, a regionally distributed organic-rich shale of hydrocarbon source rock potential, is demonstrated to lie within the Amorphognathus ordovicicus Zone of North Atlantic Province and the Oulodus robustus Zone of Midcontinent Province and to be early Richmondian age.

Hydrocarbon generation potential and Miocene–Pliocene paleoenvironments of the Kangal Basin (Central Anatolia, Turkey)

This study deals with the organic geochemical characteristics, hydrocarbon generative potential and Miocene–Pliocene paleoenvironments of the Kangal coal district, which developed in a limnic depositional environment and contains the Hamal, Etyemez and Kalburçayırı coal fields in the southern part of the Sivas Basin (Central Anatolia). Around Kalburçayırı, the average thickness of each of the two coal seams approximately 10 m are currently being exploited based on open-cast methods, the coal from which is used by the nearby lignite-fired Kangal power station. An attempt was made to elucidate depositional conditions through proximate and ultimate analyses, coal petrography and the geochemical characteristics of the Kangal coals. These coals have a huminite reflectance value of R max = 0.40%. Accordingly, from the standpoint of coal rank, this is a dull brown coal of the “subbituminous C” type. Huminite is the most widespread maceral type, while gelinites are the most often encountered macerals. Relative to liptinites, the proportion of inertinites is high. On the basis of maceral composition, the depositional environment of the Kangal coals was determined to be either a forest swamp or a lake bottom. The distributions of the C 27 and C 28–C 29 steranes for all these coal samples are very similar (C 29 > C 27 > C 28). Tricyclic terpanes have low concentrations in all samples of the Kangal coals, and are dominated by low molecular weight compounds (C 20–C 24) with a maximum at C 23. Total organic carbon (TOC, wt.%) values of the Kalburçayırı samples are 4.64–30.64 wt.%, in the Hamal samples 0.83–2.53 wt.%, and in the Etyemez samples 8.91–10.39 wt.%. On the basis of T max values, the samples are in the immature-early mature stage. According to Rock-Eval pyrolysis data, the coals have hydrocarbon source-rock potential, but the coaly shales and other organic-matter-rich levels have no hydrocarbon source-rock potential. The high inertinite levels and high vitrinite/inertinite ratios suggest that the Kangal coals have more potential for gas generation than oil.

The Jackass Mountain Group of south-central British Columbia: depositional setting and evolution of an Early Cretaceous deltaic complex1This article is one of a series of papers published in this Special Issue on the theme of New insights in Cordilleran Intermontane geoscience: reducing exploration risk in the mountain pine beetle-affected area, British Columbia.2Earth Science Sector (ESS) Contribution 20100280.

The Lower Cretaceous Jackass Mountain Group of southwestern British Columbia records a complex history of deltaic and proximal marine sedimentation in a tectonically active area of the Canadian Cordillera. Two Jackass Mountain Group successions, exposed in the Camelsfoot Range and Chilko Lake regions and separated by ∼125 km across the northwest–southeast-trending Yalakom fault, provide details of stratigraphy, sedimentology, petrography, and geochemistry of the group. Restoring dextral movement across the Yalakom fault indicates that these locales were adjacent to one another during deposition; data presented herein support this reconstruction. In addition, detailed sedimentological investigations reveal widespread shallow-marine and deltaic features, indicating that deposition occurred predominantly within a large, shallow-water deltaic system. This interpretation is crucial to the understanding of regional facies patterns and for predicting hydrocarbon potential in adjacent subsurface rocks. New porosity, permeability, and thermal maturity data augment information collected from Jackass Mountain Group strata in the subsurface and indicate that some units represent potential hydrocarbon source rocks.

The Cenomanian/Turonian oceanic anoxic event in the Razzak Field, north Western Desert, Egypt: Source rock potential and paleoenvironmental association

The Western Desert of Egypt is one of the world’s most prolific Jurassic and Cretaceous hydrocarbon provinces. It is one of many basins that experienced organic-rich sedimentation during the late Cenomanian/early Turonian referred to as oceanic anoxic event 2 (OAE2). The Razzak #7 oil well in the Razzak Field in the northern part of the Western Desert encountered the Upper Cretaceous Abu Roash Formation. This study analyzed 23 samples from the upper “G”, “F”, and lower “E” members of the Abu Roash Formation for palynomorphs, particulate organic matter, total organic carbon (TOC) and δ 13C org in order to identify the OAE2, determine hydrocarbon source rock potential, and interpret the depositional environment. The studied samples are generally poor in palynomorphs, but show a marked biofacies change between the lower “E” member and the rest of the studied samples. Palynofacies analysis (kerogen quality and quantity) indicates the presence of oil- and gas-prone materials (kerogen types I and II/III, respectively), and implies reducing marine paleoenvironmental conditions. Detailed carbon stable isotopic and organic carbon analyses indicate that fluctuations in the δ 13C org profile across the Abu Roash upper “G”, “F”, and lower “E” members correspond well with changes in TOC values. A positive δ 13C org excursion (∼2.01‰) believed to mark the short-term global OAE2 was identified within the organic-rich shaly limestone in the basal part of the Abu Roash “F” member. This excursion also coincides with the peak TOC measurement (24.61 wt.%) in the samples.

Upper Permian Main Dolomite microbial carbonates as potential source rocks for hydrocarbons (W Poland)

Various microbialite lithofacies were common in the shallow-water environments which flourished under highly saline and arid climate conditions in the Polish part of the Zechstein (Upper Permian) Main Dolomite (Ca2) carbonates. Data came from detailed analysis of 78 cores from wells located at the southern and northern margins of the Main Dolomite basin in west Poland. Microbialite lithofacies are represented by columnar, planar and domal stromatolites, clotted thrombolites and biolaminites developed in high-to-low energy environments within the upper slope, lower parts of oolitic barrier/shoal, restricted lagoon, and tidal flat and tidal channel zones. In barrier environments ooids were predominant whereas in lagoonal settings microbial oncoids and peloids were common. In basinal settings laminated dolomudstones formed which are regarded as hemipelagic and are partly pelagic microbial in origin. Microbial communities coexisted with algae and developed mainly within shallow marine environments. Microbialites are built of cyanobacterial filaments and organo-mineral coccoidal forms possibly of bacterial origin. Organic geochemistry data confirm that organic matter was transformed by cyanobacteria and bacteria which may have played a main role in hydrocarbon generation. This is confirmed by C 29 to C 35 hopanes, Pr/Ph ratio below 1.0, and the presence of gammacerane as typical for Ca2 profiles. The role and occurrence of algae, as confirmed by C 29-steranes, in hydrocarbon generation was possibly minor. Thus it is concluded that the Main Dolomite microbialites could be the likely source rocks for hydrocarbons, with calculated original TOC values from 0.8 to ca 2.0 wt. %. These units also form the reservoir rocks, with porosities reaching 20%.

SOURCE ROCK POTENTIAL AND ORGANIC GEOCHEMISTRY OF CENOMANIAN‐TURONIAN BLACK SHALES, WESTERN TAURUS, SW TURKEY

The depositional environment and hydrocarbon source rock potential of Cenomanian‐Turonian black shales of the Dereköy and Ballik Formations in SW Turkey were investigated by organic geochemical methods. In detail, 33 samples from three section of the Dereköy Formation, and 15 samples from one section of the Ballik Formation were analysed for elemental (TOC, Rock ‐Eval pyrolysis), C15+‐lipid and biomarker compositions.Based on maximum pyrolysis degradation temperatures of not more than 420°C, all the shale samples are classified as immature, corresponding to a vitrinite reflectance of less than 0.45% Rr and a lignite to sub‐bituminous coal stage. This is confirmed by relatively high isoprenoid to n‐alkane ratios as well as by high biomarker contents. According to this maturity stage, and both total organic carbon contents of 6–41% and hydrogen indices of 255–708 mg HC/g TOC, the Cenomanian‐Turonian black shales exhibit fair to excellent source rock potential with mixed Type II and Type I kerogen.Relatively high isoprenoid to n‐alkane ratios may indicate at least partial (bio‐) degradation/evaporation/waterwashing and selective modification of the lipid composition due to the nature of the outcrop. However, very similar unimodal n‐alkane distributions in the gas chromatograms of four selected shale samples, with a predominance in the C16 to C17 region, clearly point to a significant contribution of algal and/or bacterial type organic matter with low terrigenous organic input.C27, C28 and C29 steranes in shales from both formations have similar distributions (C29>C27>C28). High C31 R homohopane / C30 hopane ratios indicate a marine depositional environment. This is confirmed by the presence of gammacerane in all the black shales investigated which in general indicates salinity. Pregnanes in one sample (BA‐6) may point to hypersaline conditions.

Hydrocarbon Source Rock Assessments of the Late Jurassic Black Shales (Tokmar Formation) in the Central Taurus Region of Turkey

The hydrocarbon source rock potential and the thermal maturity of the Late Jurassic Tokmar Formation in the Boğuntu area of the central Taurus region have been investigated. Tokmar Formation includes organic matter–rich dark grey shales alternating with carbonates that were deposited under dysoxic to anoxic marine conditions prevailed in the Late Jurassic. A total of 14 samples have been analyzed by Leco and Rock-Eval pyrolysis for determination of their hydrocarbon source rock characteristics and organic maturity. The total organic carbon content of the samples range from 0.26 to 1.53 wt%. The actual Rock-Eval pyrolytic yields (S1 + S2 peak values) are between 0.25 and 3.63 mg HC/g rock. The calculated hydrogen index and oxygen index values imply that the main organic matter types are Type II and Type III kerogens. Tmax versus hydrogen index values indicate that the Boğuntu samples are thermally mature and took place in the oil generation window.

Petroleum potential of campano-maastrichtian shales of Anambra Basin, south astern Nigeria

Over 6,000 meters thick terrigeneous sediment (mainly shale/ siltstones/lithologies) of campano – Maastrichtian age has been recorded in the Anambra basin. These shale/siltstones lithologies have been reported to be rich in organic matter and had fulfilled other relevant condition for hydrocarbon source rock potential. However, only few patches of hydrocarbon shows have been documented elsewhere in the basin. This work attempts to critically evaluate the hydrocarbon source potential of the organic rich shale sediments in the basin. A sample set of 40 ditch cuttings of manly shale lithologies retrieved at different depths intervals from 2 well were subjected to standard geo-chemical and organic petrography investigations. The samples were analyzed for the total carbon content (TOC), extract yield, organic matter types and organic maturity level. As screening criteria, all the sample set were subjected to TOC measurement (LECO). The TOC values range from 0.81-1.40% (AKU2) and from 0.82-1.81% (AMA.1) most of the samples meet up with minimum required TOC value ().5%) for a siliciclastic sediments to be hydrocarbon prone. Extract yield range from 30.0 to 180.5 ppm (AKU2) and 30.0 to 128ppm (AMA 1). The Rock-Eval Pyrolysis data HI vs OI revealed that the samples fall within types II & III kerogen. This corroborates with the results of the maceral analysis. The maceral composition is mainly vitrinitic and liptinitic of terrestrial origin, which are over 65 volume percent. The shales are moderately rich in organic matter. Extract yields and the bitumen ratio (mg HC/g TOC) revealed that these samples are at immature stage of Hydrocarbon generation. This is also supported by Tmax values of between 430-4900C.KEY WORDS:- Terrigeneous, Campano – Maastrichtian, Vitrinit, Liptinite, Rock-Eval.

Source rock characterization and oil generating potential of the Jurassic Madbi Formation, onshore East Shabowah oilfields, Republic of Yemen

Abstract The hydrocarbon source rock potential of shales from the Jurassic Madbi Formation was evaluated using organic geochemistry (Rock-Eval pyrolysis, TOC and bitumen extraction) and organic petrology. Very good source rock potential is suggested by high values of total organic carbon content (TOC, >2.0 wt%) and high extractable organic matter content and hydrocarbon yields (>11,000 and 6000 ppm, respectively). The Madbi Formation samples have high hydrogen index (HI) and low oxygen index (OI) values. Most of the samples in the study area are thermally mature and contain oil prone Type I and Type II kerogen. Vitrinite reflectance (Ro) values for the Madbi shale samples were measured from 0.74% to 0.89%. Tmax values range from 430 to 438 °C, which are in reasonably good agreement with vitrinite reflectance data, reveal that the Madbi shales are at the early to peak mature stage. On the basis of biomarker maturity parameters, these shales are thermally mature. Shales of the Madbi Formation contain abundant hydrogen rich kerogen (liptinite up to 55%) and therefore good oil generating potential is anticipated. This is supported by high hydrogen indices (HI) of up to 400 mg HC/g TOC and early to peak mature oil window range.

SOURCE ROCK POTENTIAL OF EOCENE, PALEOCENE AND JURASSIC DEPOSITS IN THE SUBSURFACE OF THE POTWAR BASIN, NORTHERN PAKISTAN

The hydrocarbon source rock potential of five formations in the Potwar Basin of northern Pakistan – the Sakesar Formation (Eocene); the Patala, Lockhart and Dhak‐Pass Formations (Paleocene); and the Datta Formation (Jurassic) – was investigated using Rock‐Eval pyrolysis and total organic carbon (TOC) measurement. Samples were obtained from three producing wells referred to as A, B and C. In well A, the upper ca. 100 m of the Eocene Sakesar Formation contained abundant Type III gas‐prone organic matter (OM) and the interval appeared to be within the hydrocarbon generation window. The underlying part of the Sakesar Formation contained mostly weathered and immature OM with little hydrocarbon potential. The Sakesar Formation passes down into the Paleocene Patala Formation. Tmax was variable because of facies variations which were also reflected in variations in hydrogen index (HI), TOC and S2/S3 values. In well A, the middle portion of the Patala Formation had sufficient maturity (Tmax 430 to 444°C) and organic richness to act as a minor source for gas. The underlying Lockhart Formation in general contained little OM, although basal sediments showed a major contribution of Type II/III OM and were sufficiently mature for hydrocarbon generation.In Well B, rocks in the upper 120 m of the Paleocene Patala Formation contained little OM. However, some Type II/III OM was present at the base of the formation, although these sediments were not sufficiently mature for oil generation. The Dhak Pass Formation was in general thermally immature and contained minor amounts of gas‐prone OM.In Well C, the Jurassic Datta Formation contained oil‐prone OM. Tmax data indicated that the formation was marginally mature despite sample depths of > 5000 m. The lack of increase in Tmax with depth was attributed to low heat flows during burial. However, burial to depths of more than 5000 m resulted in the generation of moderate quantities of oil from this formation.

Neoproterozoic-Early Cambrian (Infracambrian) hydrocarbon prospectivity of North Africa: a synthesis

Abstract Despite the existence of proven Neoproterozoic–Early Cambrian (‘Infracambrian’) hydrocarbon plays in many parts of the world, the Neoproterozoic Eon, from 1000 Ma to the base of the Cambrian at 542 Ma, is relatively poorly known from a petroleum perspective. The so-called ‘Peri-Gondwanan Margin’ is one region of the Neoproterozoic world that is exciting particular interest in the search for ‘old’ hydrocarbon plays, mainly due to exploration success in time-equivalent sequences of Oman. The ‘Infracambrian’ succession in North Africa is widely accessible, and is already emerging as a hydrocarbon exploration target with considerable potential and with proven petroleum systems in different areas. The Taoudenni Basin (Mauritania, Mali, Algeria) in western North Africa is an underexplored basin, despite the Abolag-1 well (Texaco 1974) gas discovery. New palynological data have recently provided the first definitive Late Riphean age dates for the stromatolitic limestone reservoir sequence in Abolag-1. The widespread presence of stromatolitic carbonate units of potential reservoir facies in many parts of North Africa has been confirmed by new fieldwork in the Taoudenni Basin, in the Anti-Atlas region of Morocco and in the Al Kufrah Basin of Libya. Similar biostratigraphic age constraints have also been obtained from subsurface sequences of the Cyrenaica Platform bordering the East Sirte Basin of Libya, many of which have been traditionally assigned an ‘unconstrained’ Cambro-Ordovician age on the basis of lithological characteristics. Besides the proven, producing, weathered-granite reservoir in East Sirte Basin, the hydrocarbon potential of Neoproterozoic–Early Cambrian sequences developed in structural troughs bordering the south Cyrenaica Platform is still being evalutated. Neoproterozoic–Early Cambrian organic-rich strata with hydrocarbon source rock potential are widespread along the Peri-Gondwanan Margin. Some of the black shales encountered on the West African Craton may be as old as 1000 Ma and predate the Pan-African orogenic event. The Late Ordovician–Early Silurian systems in North Africa and the Middle East may form a good analogue for post-glacial source rock depositional systems in the Neoproterozoic, where black shale deposition may also have been triggered by post-glacial sea-level rise.

Infracambrian hydrocarbon source rock potential and petroleum prospectivity of NW Africa

Abstract Proven Infracambrian hydrocarbon plays occur in various parts of the world, including Oman, the former Soviet Union, India, Pakistan and Australia. Organic-rich strata also occur in NW Africa, and gas shows originating from Infracambrian hydrocarbon source rocks are known from well Abolag-1 in the Mauritanian part of the Taoudenni Basin. The distribution of Infracambrian source rocks in North Africa is patchy and deposition commonly occurred in half-graben and pull-apart basins. In these intra-shelf basins, marine, organic-rich shales and limestones were deposited beneath the turbulent wave zone, away from the coarse siliciclastic Pan-African molasse detritus. On the West African Craton (including the Taoudenni Basin) organic-rich horizons were also deposited earlier, in pre- and syn-Pan-African times between 0.5 and 2 Ga (Ga is 10 9 years). The long-lasting sedimentation history in this area contrasts with that of the Pan-African regions, such as Oman, which lies in the Pan-African province of the East African Orogen, where preserved sediments are rarely older than 640 Ma. Infracambrian black phyllites in the Anti-Atlas region of Morocco were deposited on a continental slope of a short-lived ocean lying to the north of the West African Craton. Hydrocarbons generated during Infracambrian times from these deposits, however, have a low preservation potential. Infracambrian organic-rich and/or black-pyritic deposits in North Africa are proven in the Taoudenni Basin, the Anti-Atlas and the Ahnet Basin. Thick carbonate successions exist in the Taoudenni Basin, indicating deposition in areas some distance from contaminating coarse siliciclastic hinterland influx. Infracambrian strata may also occur in the Tindouf Basin. However, their deep burial and consequent early maturation history may be unfavourable for the preservation of Infracambrian-sourced hydrocarbons in this area. Local development of Infracambrian source facies may also occur in the Reggane, Ahnet, Mouydir and Iullemeden basins, as indicated by black shales in wells MKRN-1 and MKRS-1 in the Ahnet Basin. Generally, however, these basins appear to be close to the active Pan-African orogenic belt and, consequently, probably received large quantities of coarse siliciclastic sediment, largely of continental facies, which may have diluted any significant hydrocarbon source potential.

Molecular Records of Primary Producers and Sedimentary Environmental Conditions of Late Permian Rocks in Northeast Sichuan, China

A series of biomarkers were identified in the aliphatic and aromatic fractions of the extracts from Late Permian Dalong and Wujiaping formations in Shangsi Section, Northeast Sichuan, South China, on the basis of the analysis of gas chromatography-mass spectrometry (GC-MC). The dominance of lower-molecular-weight n -alkanes throughout the profile suggests the dominant contribution of algae and bacteria to the organics preserved in the marine section. Wujiaping Formation is characterized by the elevated contribution from algae as well as other photoautotrophs such as photosynthetic bacteria as shown by the molecular ratios of hopanes to steranes or tricyclic terpanes as well as the ratio of pristane (Pr) and phytane (Ph) to C 17 and C 18 n -alkanes. This is in accord with the data from the microscopic measurement on the calcareous algae. In contrast, Dalong Formation is featured by enhanced contribution from bacteria and probably terrestrial organics indicated by the enhanced C 24 tetracyclic terpanes relative to tricyclic terpanes. The two formations also show a distinct discrimination in sedimentary environmental conditions including redox condition and salinity. The anoxic condition was only found in the middle of the Dalong Formation as shown by the ratios of Pr/Ph and dibenzothiophene to phenanthrene, consistent with the reported data of Mo and U. An enhanced salinity indicated by the homohopane index is observed at the shallow Wujiaping Formation. On the basis of the composition of primary productivity and the redox condition, Dalong Formation is proposed, herein, to be potential hydrocarbon source rocks in the study site. It is notable that the topmost end-Permian is characterized by a large perturbance in both the redox condition and salinity, with oxic conditions being frequently interrupted by short-term anoxia, likely showing a causal relationship with the episodic biotic crisis across the Permian—Triassic boundary.

Depositional and Ecological Features of Permian Oxygen Deficient Deposits at Shangsi Section, Northeast Sichuan, China

Because oxygen deficient conditions enhance the preservation of depositional organic matter, analysis on paleooxygenation conditions of depositional environments becomes a routine work in evaluations of potential hydrocarbon source rocks. The article focuses on depositional and ecological features relating to oxygen deficient shelfal environments at the Shangsi Section, as a part of multidiscipline collaboration to reevaluate the hydrocarbon potential of the Middle and Upper Permian, Guangyuan, Northeast Sichuan Province. Ichnofabric Zoophycos , sepiolite-bearing limestones (SBL) were interpreted as indicators of dysaerobic environments. Laminated calcareous and/or siliceous mudstones with pelagic ammonites and radiolarians were believed to be the deposits of anaerobic environments. When rhythmic succession was considered, average strategy was adopted for the oxygenation explanation of a given interval. The anaerobic condition in this Permian section was observed in the upper part of the latest Permian Dalong Formation, in which siliceous mudstones with ammonite, radiolarians develop in association with lower U/Mo ratio, lower biomarker ratio of Pr/Ph, and the highest TOC content. The topmost Maokou Formation, featured by thin-bedded calcareous and siliceous mudstones with ammonite, thin-shelled bivalves, and laminations would be deposits of the quasianaerobic condition. The middle part of the Members I and III of the Chihsia Formation is proposed to be dysaerobic condition as indicated by occurrences of SBL and ichnofabric features, with the Member III being the severe dysaerobic condition.

Fácies orgânica: conceitos, métodos e estudos de casos na indústria do petróleo

The concept of organic facies, as well as the definitions and means of the different facies became a very important tool to petroleum exploration. The application of this concept is the best way to integrate microscopy and geochemical techniques to study kerogen contained in sedimentary rocks. Thus, palynofacies analysis and bulk geochemical methods are used to characterize the total particulate organic matter. Palynofacies analysis involves the integrated study of all aspects of the kerogen assemblage: identification of the individual particulate components, assessment of their absolute and relative proportions and preservation states. The correlation between palynofacies and geochemical data provides the organic facies models that point out the depositional environmental conditions and hydrocarbon source rock potential.