geologic evolution of the iraqi zagros and its influence on the distribution of hydrocarbons in the kurdistan region whereas the vast majority of discovered hydrocarbon reserves in iraq reside in cretaceous and cenozoic reservoirs numerous oil and gas fields have been discovered recently in deeper jurassic and triassic reservoirs in the kurdistan region of iraq this study presents a middle upper jurassic thermal maturity map for the kurdistan region of iraq and demonstrates that regional first order trends in jurassic source rock maturity show a close correlation to the spatial distribution of oil gravities within the overlying jurassic and cretaceous reservoirs this distribution is consistent with compartmentalization of the active source rock kitchens due to zagros folding resulting in relatively short distance migration and charge of the anticlinal structures from the adjacent synclinal lows the thermal maturity map confirms relatively low maturity over the mosul high where the cretaceous and cenozoic section overlying the source rock interval is relatively thin and increasing maturity to the southeast as the thickness of the cenozoic foredeep sediments increases toward the depocenter located in the southeastern iraqi zagros and the adjacent iranian zagros the correlative trend in oil gravities is exemplified by the recent jurassic discoveries low to medium gravity oils 14 27 api in shaikan and atrush to the northwest light oil 39 47 api in mirawa and bina bawi and gas condensate 55 api in miran west to the southeast understanding thermal maturity patterns and hydrocarbon fluid type distributions will help to guide risk assessment for remaining prospectivity and future exploration drilling within the kurdistan region of iraq

alkylbiphenyls in ancient sediments and petroleums abstract c 1 and c 2 alkylbiphenyls have been analysed in crude oils and sediment extracts by capillary gas chromatography after preliminary isolation procedures involving tlc and hplc the abundance of 2 methylbiphenyl relative to 3 methylbiphenyl has been measured in samples from two sedimentary sequences 2 methylbiphenyl decreases in relative abundance with increasing thermal maturity of the sediments in both sedimentary sequences these isomeric methylbiphenyls are potentially useful as thermal maturity indicators for crude oils

geochemical and geological characteristics of the es3l lacustrine shale in the bonan sag bohai bay basin china abstract although extensive studies have been conducted on unconventional shale oil resources in recent years little work has been performed on the resource potential of lacustrine shales the es3l lower sub member of the third member of the eocene shahejie formation shale of the bonan sag a set of thick lacustrine deposited sediments offers a good example for furthering the understanding of these rocks geochemical and mineralogical investigations were carried out on a large sample set from the 220 m thick sequence of well luo69 in total 200 core samples were analyzed for total organic carbon toc and rock eval pyrolysis and 421 core samples were analyzed for mineral compositions the es3l shales have a very high toc content with type i lacustrine oil prone kerogen in the early oil generation stage rock eval tmax suppression is evident in the lower part of the es3l member associated with a rise in pi production index with respect to fracability or brittleness the content of brittle minerals in the es3l shale is generally higher than that of marine shales in the usa with higher calcite mineral averaging 51 82 wt and lower clay content averaging 18 86 wt interparticle pores in minerals grains or clay aggregates intraparticle pores intercrystalline dolomite and pyrite framboid and four types of fractures tectonic fractures abnormal pressure fractures clay shrinkage fractures and inter laminar fractures are developed in the es3l shale organic matter pores are not present in the studied samples probably due to lower maturity tectonic fracture may play an important role in hydrocarbon migration and accumulation the results of this study suggest that the es3l shale in the bonan sag has very good shale oil potential especially in the lower section

geochemical characteristics and hydrocarbon generation modeling of the jurassic source rocks in the shoushan basin north western desert egypt abstract the shoushan basin is an important hydrocarbon province in the western desert egypt but the origin of the hydrocarbons is not fully understood in this study organic matter content type and maturity of the jurassic source rocks exposed in the shoushan basin have been evaluated and integrated with the results of basin modeling to improve our understanding of burial history and timing of hydrocarbon generation the jurassic source rock succession comprises the ras qattara and khatatba formations which are composed mainly of shales and sandstones with coal seams the toc contents are high and reached a maximum up to 50 the toc values of the ras qattara formation range from 2 to 54 wt while khatatba formation has toc values in the range 1 47 wt the ras qattara and khatatba formations have hi values ranging from 90 to 261 mghc gtoc suggesting types ii iii and iii kerogen vitrinite reflectance values range between 0 79 and 1 12 vrr rock eval t max values in the range 438 458 c indicate a thermal maturity level sufficient for hydrocarbon generation thermal and burial history models indicate that the jurassic source rocks entered the mature to late mature stage for hydrocarbon generation in the late cretaceous to tertiary hydrocarbon generation began in the late cretaceous and maximum rates of oil with significant gas have been generated during the early tertiary paleogene the peak gas generation occurred during the late tertiary neogene

geochemical characteristics and depositional environment of paleogene lacustrine source rocks in the lufeng sag pearl river mouth basin south china sea abstract a systematic geochemical analysis of samples from newly drilled wells in the lufeng sag pearl river mouth basin has been carried out to characterize source rock quality determine organic matter input and reconstruct the depositional environment of the enping and wenchang formations total organic carbon toc content ranges from 0 46 to 1 57 wt in the enping formation and from 0 53 to 6 10 wt in the wenchang formation kerogen types i ii were identified in the wenchang formation samples while kerogen types ii iii were identified in the enping formation samples maturity parameters suggest marginally mature to mature levels for most samples with higher maturity for the wenchang formation samples biomarker assemblage and trace element ratios of the wenchang and enping formations are distinctively different indicating predominantly aquatic origin organic matter input under suboixc anoxic water conditions for the wenchang formation and more allochthonous terrestrial organic matter input under oxic water conditions for the enping formation moderate to high primary productivity and temperature drove water stratification together with weak detrital material dilution led to the enrichment of organic matter in the wenchang formation while the low primary productivity poor preservation conditions and high dilution led to the relatively poor source rock quality in the enping formation

hydrocarbon generation and expulsion characteristics of the source rocks in the third member of the upper triassic xujiahe formation and its effect on conventional and unconventional hydrocarbon resource potential in the sichuan basin abstract the third member of the upper triassic xujiahe formation t3x3 is a typical source reservoir cap unit for natural gas exploration in the sichuan basin however most previous studies mainly focused on the t3x3 as a source rock ignoring its role as a reservoir as a result the evaluation of hydrocarbon resource potential was not accurate this study established a hydrocarbon generation and expulsion model through analyzing the geological and geochemical characteristics of the t3x3 source rocks and calculated the resource potential of conventional gas tight gas and shale gas systematically with combining the lower boundary of buoyancy dominated accumulation lbba the results indicated that the thickness of the source rocks dominated by mudstone was distributed widely with an average value of more than 45 m the sedimentary environment was salty lacustrine deposits they have a high content of total organic carbon toc with an average value of 4 80 wt the kerogen is mainly type iii with minor type ii and the thermal evolution has entered the high to over mature stage the hydrocarbon generation threshold was determined to be 0 5 ro while the hydrocarbon expulsion threshold and the lbba were determined to be 0 83 ro and 1 12 ro respectively the efficiency of hydrocarbon expulsion was relatively high with an average of about 56 also the maximum hydrocarbon generation and expulsion intensity reached to 110 108 m3 km2 and 53 108 m3 km2 the amounts of hydrocarbon generation expulsion and residual associated with the t3x3 source rocks were 125 68 1012m3 70 38 1012m3 and 55 30 1012m3 respectively under the criterion condition of the lbba the conventional gas resource was 7 21 1010m3 the tight gas resource was 294 34 1010m3 and the shale gas resource was 2488 50 1010m3 it indicated good prospects for exploration

organic geochemical and petrographic characteristics of the miocene salif organic rich shales in the tihama basin red sea of yemen implications for paleoenvironmental conditions and oil generation potential abstract this study is the first investigation which provides information regarding the organic geochemical and petrographic characteristics of miocene salif organic rich shales from tihama basin in the red sea yemen we evaluate organic matter content type maturity and oil generation potential as well as depositional environmental conditions the total organic carbon toc contents of the miocene salif shales vary between 0 59 and 5 40 indicating fair to very good source rock potential the salif shales have hydrogen index values in the range of 64 576 mg hc g toc the organic matter in the salif shales are dominated by type ii kerogen and mixed ii iii kerogens with a minor contribution of type iii kerogen as supported by kerogen microscopy this is also confirmed by their biomarker and carbon isotope results which indicate that the salif shales were deposited in highly reducing marine conditions and received high contributions of aquatic organic matter e g algal and microbial and terrigenous organic matter consequently the salif formation is likely to be an oil source rock maturity indicators such as vitrinite reflectance and pyrolysis data i e tmax and pi indicate that most of the salif shale samples are generally thermally mature at the early mature to peak oil window stage the new data presented in this paper suggest that early mature oil has been generated from miocene salif organic rich shales so exploration strategies should focus on the known location of miocene salif organic rich shales for predicting the location of the source kitchen

quasi biennial fluctuations in sea level pressures over the northern hemisphere abstract an investigation is made into the presence of quasi biennial oscillations qbos in sea level pressure fields over the northern hemisphere using 55 years 1925 79 of seasonally averaged sea level pressure anomalies a series of analyses has been performed in order to systematically isolate and describe the qbos a standard empirical orthogonal function eof analysis of the seasonal anomalies reveals significant nonrandomness at qbo periods the data were then band pass filtered in order to focus on the qbo and a second eof analysis was performed finally a new complex eof analysis technique was applied to the data complex eofs have the advantage of permitting both standing and propagating modes the qbo variance in six standard eofs is essentially confined to four eofs in the filtered data set and compressed into three complex eofs the latter account for 56 of the filtered variance the dominant mode of the complex eof analysis was common to all analyses and has been found in many other s

mechanisms of salinization in a middle eocene lake in the tanggu area of the huanghua depression abstract the sha 3 5 submember of the shahejie formation in the tanggu area of the huanghua depression contains analcime bearing dolomite indicating salinization of an ancient lake during deposition solar evaporation and hydrothermal salinization have both been proposed as ways to generate these saline conditions based on a comprehensive analysis of core data thin sections spore and pollen data elemental geochemistry pyrolysis results and vitrinite reflectance we assessed the mechanisms driving salinization in light of provenance evolution geothermal evolution paleoclimate mineral responses to evaporation and the relationship between fluid temperature and salinity the vertical profiles of ree eu eu and tmax exhibit little variation and the maximum paleotemperatures attained by organic matter are comparable to present day drill hole temperature no major changes in provenance or paleotemperature and no petrological fabrics that would indicate a hydrothermal input are observed in the studied section however evidence for a semi humid to semi arid climate primary evaporitic textures and structures and a positive relationship between fluid temperature and salinity all support evaporation as the primary mechanism driving rising salinity solar evaporation rather than hydrothermal eruption appears to have been the primary factor driving lake salinization during middle eocene deposition of the dolomitic sha 3 5 submember

biodegradation of tar sand bitumens from the ardmore anadarko basins oklahoma ii correlation of oils tar sands and source rocks abstract in an earlier paper we reported the effects of biodegradation on tar sand bitumens from the southern part of the ardmore and anadarko basins in this paper we wish to describe geochemical correlations that have been made between the tar sand bitumens and oils produced from various formations in the pauls valley area 25 miles to the north it was determined that the tar sands were formed from a source similar to many of these oils whose reservoir ages ranged from ordovician to pennsylvanian the oils had been previously divided into two major groups on the basis of their biomarker distributions with one group 80 of the oils studied proposed to have been sourced from the woodford shale devonian and the other group from the viola limestone ordovician the tar sand bitumen oil correlation study based on hydrocarbon and porphyrin biomarker distributions and pyrolysis gas chromatography of asphaltenes has shown that the tar sand bitumen appears to be genetically related to the group of oils derived from the woodford shale and more specifically to those present in the oil creek formation ordovician of the anadarko basin

source rock characteristics and hydrocarbon generation modelling of upper cretaceous mukalla formation in the jiza qamar basin eastern yemen abstract the upper cretaceous mukalla coals and other organic rich sediments which are widely exposed in the jiza qamar basin and believed to be a major source rocks were analysed using organic geochemistry and petrology the total organic carbon toc contents of the mukalla source rocks range from 0 72 to 79 90 with an average toc value of 21 50 the coals and coaly shale sediments are relatively higher in organic richness consistent with source rocks generative potential the samples analysed have vitrinite reflectance in the range of 0 84 1 10 ro and pyrolysis t max in the range of 432 454 c indicate that the mukalla source rocks contain mature to late mature organic matter good oil generating potential is anticipated from the coals and coaly shale sediments with high hydrogen indices 250 449 mg hc g toc this is supported by their significant amounts of oil liptinite macerals are present in these coals and coaly shale sediments and py gc s 2 pyrograms with n alkane alkene doublets extending beyond nc 30 the shales are dominated by type iii kerogen hi one dimensional basin modelling was performed to analysis the hydrocarbon generation and expulsion history of the mukalla source rocks in the jiza qamar basin based on the reconstruction of the burial thermal maturity histories in order to improve our understanding of the of hydrocarbon generation potential of the mukalla source rocks calibration of the model with measured vitrinite reflectance ro and borehole temperature data indicates that the present day heat flow in the jiza qamar basin varies from 45 0 mw m 2 to 70 0 mw m 2 and the paleo heat flow increased from 80 ma to 25 ma reached a peak heat flow values of approximately 70 0 mw m 2 at 25 ma and then decreased exponentially from 25 ma to present day the peak paleo heat flow is explained by the gulf of aden and red sea tertiary rifting during oligocene middle miocene which has a considerable influence on the thermal maturity of the mukalla source rocks the source rocks of the mukalla formation are presently in a stage of oil and condensate generation with maturity from 0 50 to 1 10 ro oil generation 0 5 ro in the mukalla source rocks began from about 61 ma to 54 ma and the peak hydrocarbon generation 1 0 ro occurred approximately from 25 ma to 20 ma the modelled hydrocarbon expulsion evolution suggested that the timing of hydrocarbon expulsion from the mukalla source rocks began from 15 ma to present day

late gas generation potential for different types of shale source rocks implications from pyrolysis experiments abstract gas generation from shale source rocks typically occurs via cracking of both kerogen and retained oils such that it is difficult to predict and compare gas generation potentials of different shales because they are related not only to the kerogen type but also to the oil expulsion efficiency in this study five different shale kerogen samples were pyrolyzed in sealed gold tubes to investigate how kerogen type and oil expulsion efficiency affect their gas generation after oil window maturity the results illustrate that the maximum extractable organic matter eom and gas generation potentials of different original shale kerogens o kerogen in a closed system vary widely in the range of 229 790 mg g tocok and 308 594 ml g tocok respectively however the gas yields of different residual shale kerogens r kerogen with a starting equivalent vitrinite reflectance eqvro value of approximately 1 22 are quite similar and vary between 131 and 145 ml g tocrk pyrolysis experiments also reveal that the late gas generation potential eqvro 1 22 of shale is mainly controlled by the amount of retained eoms rather than kerogen type when the shale source rocks containing types i and ii kerogens have the same amount of retained eoms their gas generation potentials are quite similar under most geological conditions the late gas generation potentials of shale source rocks normalized to the toc of matured shale at 1 22 eqvro tocshale vary approximately in the range of 180 300 ml g tocshale to reach a gas content of 3 m3 ton shale for the present day overmature shale gas exploration in the lower palaeozoic shales of south china a conservative present day toc tocpd value of 2 0 is proposed as a screening parameter that can eliminate the risk of insufficient gas generation potential as much as possible

geochemistry and organic petrology study of kimmeridgian organic rich shales in the marib shabowah basin yemen origin and implication for depositional environments and oil generation potential kimmeridgian organic rich shales of the madbi formation from the marib shabowah basin in western yemen were analysed to evaluate the type of organic matter origin and depositional environments as well as their oil generation potential results of the current study establishes the organic geochemical characteristics of the kimmeridgian organic rich shales and identifies the kerogen type based on their organic petrographic characteristics as observed under reflected white light and blue light excitation kerogen microscopy shows that the kimmeridgian organic rich shales contain a large amount of organic matter consisting predominantly of yellow fluorescing alginite and amorphous organic matter with marine microfossils e g dinoflagellate cysts and micro foraminiferal linings terrigenous organic matters e g vitrinite spores and pollen are also present in low quantities the high contributions of marine organic matter with minor terrigenous organic matter are also confirmed by carbon isotopic values the organic richness of the kimmeridgian shales is mainly due to good preservation under suboxic to relatively anoxic conditions as indicated by the percent of numerous pyritized fragments associated with the organic matter the biomarker parameters obtained from mass spectrometer data on m z 191 and m z 217 also indicate that these organic rich shales contain mixed organic matter that were deposited in a marine environment and preserved under suboxic to relatively anoxic conditions the kimmeridgian organic rich shales thus have high oil and low gas generation potential due to oil window maturities and the nature of the organic matter with high content of hydrogen rich type ii and mixed type ii iii kerogens with minor contributions of type iii kerogen

organic petrology of source rocks history and state of the art abstract the development of organic source rock petrology depended on the methods applied a procedure derived from coal petrology is the study of polished sections of the untreated rock under incident light this method combined with the fluorescence techniques is best suited to characterize and identify the discrete organic matter macerals and permits the most reliabble maturity measurements on the basis of vitrinite reflectance and of various fluorescence parameters another common method treats the rock with acids and studies strew slides of organic matter concentrates this destroys the natural texture of the rock and often some of the individual macerals as well but on the other hand it allows recognition of extremely fine particles which are not resolvable in polished sections maturity studies based on maceral colour changes as observed in strew slides are rapid and practical although they are rather subjective the relative merits of the various methods are discussed the individual organic constituents as seen in the whole rock and in organic matter concentrates are described and illustrated in two colour plates some classification systems are compared in tabular form finally the history of microscopic observations and measurements with respect to the generation of petroleum like substances in coal is briefly reviewed

petrological and geochemical characterization of candiota coal seams brazil implication for coal facies interpretations and coal rank abstract seven coal seams from cores of the borehole m iv c 101 candiota coalfield located in rio grande do sul state southern part of the parana basin were analyzed by coal petrographical and organic geochemical methods the seams occur in the rio bonito formation guata group tubarao supergroup of the parana basin and are of permian artinskian kungurian age the composition rank coal facies and depositional environment characterization were made based on lithotype maceral and microlithotype analyses the data were then used in the definition of different types of facies critical petrographical indices and were displayed in diagrams of coal facies in addition coal seams samples from candiota mine were analyzed by proximate total moisture and gross calorific values and were classified using the united nations economic commission for europe un ece classification in addition rock eval pyrolysis liquid chromatography gc and gc ms analyses were made to obtain independent parameters on coal rank and organic matter composition and environment of deposition the results suggest deposition in open mires with elevated contents of detrital macerals and clay minerals and also limno telmatic coal facies coal bearing sequence of coal seams represent a back barrier setting according to the international classification un ece candiota coals are in the subbituminous or low rank coal a stage results from geochemical analyses showed that terrestrial organic matter is predominant as indicated by hydrogen and oxygen indices carbon preference indices and the sterane distribution geochemical maturity parameters such as the 20 s 20 s 20 r and ratios for c 29 regular steranes support the low level of rank maturity as indicated by the vitrinite reflectance measurements 0 41 0 45 and gross calorific values

observations of pkp df and pkp bc across the united kingdom implications for studies of attenuation in the earth s core summary we demonstrate that pkp df and pkp bc recorded by a network of broad band stations in the united kingdom from earthquakes in the southwest pacific show considerable spatial variation in amplitude and frequency content we suggest that strong heterogeneity in apparent attenuation at the base of the mantle related to ultra low velocity zones ulvz beneath the southwest pacific and or possibly to the east of iceland may explain the anomalous observations of df and bc across the uk the length scale of attenuating ulvzs required to explain the observations is similar to that estimated recently for a southwest pacific ulvz by wen helmberger 1998 that is low wave speed low apparent q regions of 80 km height separated by steep sided valleys of width 40 km with typical lowermost mantle wave speeds high apparent q if the apparent attenuation is due to anelasticity alone disregarding the possible contribution from scattering the minimum ulvz q values required to explain the amplitude of 2 hz bc are about 15 30 consistent with the interpretation of the ulvzs as zones of partial melt at the base of the mantle this suggests that estimates of inner core anelastic attenuation inferred from df bc spectral ratios will be biased if df and or bc cross ulvzs at the base of the mantle under the source and or receiver further the presence of attenuating ulvzs may explain the large scatter in estimates of inner core q from global studies

modelling petroleum generation of late cretaceous dabut formation in the jiza qamar basin eastern yemen abstract the jiza qamar basin in eastern yemen is still undergoing hydrocarbon exploration and hydrocarbon potential has not been assigned yet in this study subsurface samples from two onshore and offshore wells were collected to characterize the source rocks of dabut formation and to incorporate into basin modelling in order to know and determine the timing of petroleum generation and expulsion of the dabut source rocks based on organic geochemical analysis the dabut sediments have variable toc content in the range of 0 5 2 5 wt indicating fair to good source rock generative potential the organic matter of dabut source rock is dominated by type iii kerogen with minor mixed iii ii kerogen contributions and is thus considered to be mainly gas prone and some oil prone this is supported by hi values in the range of 50 212 mg hc g toc vitrinite reflectance in the range of 0 63 0 88 ro and pyrolysis tmax in the range of 427 454 c generally indicate that the dabut source rocks contain mature organic matter one dimensional basin modelling was performed to analyse the hydrocarbon generation and expulsion history of the dabut source rocks in the jiza qamar basin based on the reconstruction of the burial and thermal maturity histories in order to improve our understanding of the hydrocarbon generation potential calibration of the model with measured vitrinite reflectance ro and borehole temperature bht data indicates that the paleo heat flow was constant during the late cretaceous paleogene but increased during the late paleogene neogene and then decreased exponentially from neogene to present day the modelled maturity history predicts that the oil generation 0 5 ro in the dabut source rock began from about 56 ma to 42 ma and the peak hydrocarbon generation 0 86 ro occurred approximately from 14 ma to 13 ma these models also indicate that the main phase of oil generation was at 56 ma to 25 ma whereas the main phase of gas generation began from about 25 ma to 14 ma and still generated in the present day

source rock evaluation and nature of hydrocarbons in the khalda concession shushan basin egypt s western desert abstract organic geochemical studies were undertaken on 241 jurassic cretaceous ditch cuttings samples and 9 gases and 10 crude oils from some productive mesozoic pay zone intervals in the khalda concession shushan basin northern western desert egypt we aim to investigate source rock characteristics origin of gases nature of oils and their inferred source rocks and to establish genetic relationships the middle jurassic khatatba formation and older rocks contain organic rich mature coaly and carbonaceous shales which are the main source for hydrocarbons in egypt s western desert including the shushan basin which generally contains kerogen type iii with some contribution of type iii ii kerogen molecular and isotopic composition indicates that the khalda gases are of thermogenic origin a mature 0 6 2 0 ro source rock with terrigenous organic matter kerogen type iii was identified as a precursor of wet thermogenic gases in the shushan basin geochemical results indicate that the oil samples were derived from a source rock deposited mainly under oxic conditions and containing terrigenous organic matter biomarker data indicate that paraffinic oils and condensates from the shushan basin were derived from mature source rocks within the oil window the light hydrocarbon data suggests that the analyzed oils can be classified into two groups as a result of evaporative fractionation and maturation this signal of a secondary reservoir transformation which is not revealed by biomarker analysis emphasizes the importance of integrating biomarker and light hydrocarbon data to understand variations in the chemical composition and origin of oils

organic geochemical characteristics and depositional environment of the tertiary tanjong formation coals in the pinangah area onshore sabah malaysia article i nfo article history the tertiary tanjong formation coals exposed in the west middle block of the pinangah coalfield central part of southern sabah were analyzed and their depositional environments were interpreted the tertiary tanjong coals are humic and generally dominated by vitrinite with significant amounts of liptinite and low amounts of inertinite macerals total organic carbon contents toc of the coals range from 51 2 to 77 7 wt and yield of bitumen values ranging from 57 300 to 140 000 ppm which meet the standard as a source rock with good hydrocarbon generative potential in support good liquid hydrocarbons generation potential can be expected from the tanjong coals based on significant liptinitic content 15 this is supported by their high hydrogen index up to 300 mg hc g toc consistent with type ii and mixed type ii iii kerogens and py gc s2 pyrograms with n alkane alkene doublets extending beyond c30 the coal samples have vitrinite reflectance values in the range of 0 42 0 66 ro indicating immature to early mature stage for hydrocarbon generation these vitrinite reflectance values also indicated that the tanjong coals are with sub bituminous b a and high volatile bituminous c rank tmax values ranging from 419 to 451 c are good agreement with the vitrinite reflectance data this is supported by biomarker maturity parameters as suggested by the c32 homohopane the saturated fraction of the tanjong coals are characterized by dominant odd carbon numbered n alkanes n c23 to n c33 high pr ph ratios 8 18 high tm ts ratios 6 28 and pre dominant of regular sterane c29 all biomarker parameters clearly indicate that the organic matter was de rived from terrestrial inputs and deposited under oxic condition

organic geochemical characteristics and depositional environments of the jurassic coals in the eastern taurus of southern turkey abstract in this study organic matter content type and maturity as well as some petrographic and physical characteristics of the jurassic coals exposed in the eastern taurus were investigated and their depositional environments were interpreted the total organic carbon toc contents of coals in the feke akkaya kozan gedikli and kozan kizilinc areas are 24 54 66 78 and 49 15 respectively the feke akkaya and kozan kizilinc coals have low hydrogen index hi values while the kozan gedikli coals show moderate hi values all coal samples display very low oxygen index oi values the kozan gedikli coals contain type ii organic matter om the feke akkaya coals contain a mixture of type ii and type iii om and the kozan kizilinc coals are composed of type iii om sterane distribution was calculated as c27 c29 c28 from the m z 217 mass chromatogram for all coal samples tmax values for the feke akkaya kozan gedikli and kozan kizilinc coals are 439 412 and 427 c vitrinite reflectance values ro for the feke akkaya and kozan kizilinc coal samples were measured as 0 65 and 0 51 and these values reveal that the feke akkaya and kozan kizilinc coals are at subbituminous a or high volatile c bituminous coal stage on the basis of biomarker maturity parameters these coals have a low maturity the pristane phytane pr ph ratios for the feke akkaya kozan gedikli and kozan kizilinc coals are 1 53 1 13 and 1 25 respectively in addition all coals show a homohopane distribution which is dominated by low carbon numbers and c35 homohopane index is very low for all coal samples all these features may indicate that these coals were deposited in a suboxic environment the high sterane hopane ratios with high concentrations of steranes low pr ph ratios and c25 c26 tricyclic ratios 1 may indicate that these coals formed in a swamp environment were temporarily influenced by marine conditions

organic petrological and geochemical appraisal of the upper jurassic naokelekan formation kurdistan iraq abstract upper jurassic naokelekan formation being part of the intercepted strata of the well known miran oilfield in kurdistan region of northern iraq has been previously extensively evaluated as a potential effective source rock mainly by means of organic geochemistry in the present study a total of 60 samples were collected from four naokelekan fm outcrops those of banik galy derash barsarin and dwawa in order to conduct organic petrographical study and organic geochemical assessment including both biomarker and rock eval analyses the average recorded toc content for banik galy derash barsarin and dwawa section is considerable to very high corresponding to values of 27 5 9 0 3 5 and 5 2 wt respectively with the highest values representing the notably organic rich bottom part of the formation known as coal layer according to the petrographical analysis solid migrabitumens comprise the predominant component for all the analysed samples whereas the maceral groups of vitrinite liptinite and or inertinite showcase a minor to trace occurrence in terms of organic geochemistry each of the four sections of interest shows a different biomarker profile nevertheless a number of calculated parameters related to kerogen type and depositional conditions including the isoprenoids n alkanes ratios suggest a mixed terrestrial marine organic matter furthermore as indicated by the ro measurements along with rock eval parameters and the vitrinite reflectance equivalent based on aromatic compounds the maturity level is marginally mature in the cases of banik and galy derash whereas in the cases of dwawa and barsarin sections it is mature to post mature a synthesis of the organic petrography and geochemical appraisal applied in the present study suggests that the reported solid hydrocarbons in naokelekan fm particularly at its basal layers are non indigenous migrated and the precursor organic matter was deposited in a marine environment under oscillating conditions ranging from euxinic to well oxygenated accordingly the organic features of the notably bitumen rich coal bed fit the profile of a reservoir and or migration path

organic geochemistry and petroleum potential of early cretaceous garau formation in central part of lurestan zone northwest of zagros iran abstract deposition of organic rich black shales and dark gray limestones in the berriasian turonian interval has been documented in many parts of the world the early cretaceous garau formation is well exposed in lurestan zone in iran and is composed of organic rich shales and argillaceous limestones the present study focuses on organic matter characterization and source rock potential of the garau formations in central part of lurestan zone a total of 81 core samples from 12 exploratory wells were subjected to detailed geochemical analyses these samples have been investigated to determine the type and origin of the organic matter as well as their petroleum generation potential by using rock eval toc pyrolysis gc and gcms techniques the results showed that toc content ranges from 0 5 to 4 95 percent pi and tmax values are in the range of 0 2 and 0 6 and 437 and 502 c most organic matter is marine in origin with sub ordinary amounts of terrestrial input suggesting kerogen types ii iii and iii measured vitrinite reflectance rrandom values varying between 0 78 and 1 21 indicating that the garau sediments are thermally mature and represent peak to late stage of hydrocarbon generation window hydrocarbon potentiality of this formation is assessed fair to very good capable of generating chiefly gas and some oil biomarker characteristics are used to provide information about source and maturity of organic matter input and depositional environment the relevant data include normal alkane and acyclic isoprenoids distribution of the terpane and sterane aliphatic biomarkers the garau formation is characterized by low pr ph ratio

petroleum generation characteristics of heterogeneous source rock from chia gara formation in the kurdistan region northern iraq as inferred by bulk and quantitative pyrolysis techniques abstract this study is the rst attempt which provides information regarding the bulk and quantitative pyrolysis results of the chia gara formation from the kurdistan region northern iraq ten representative early mature to mature samples from the chia gara formation were investigated for toc contents rock eval pyrolysis pyrolysis gc and bulk kinetic parameters these analyses were used to characterize the petroleum generated during thermal maturation of the chia gara source rock and to clarify the quantity of the organic matter and its effect on the timing of petroleum generation pyrolysis hi data identi ed two organic facies with di erent petroleum generation characteristics type ii iii kerogen with hi values of 250 mg hc g toc and type iii kerogen with hi values bulk kinetic analysis of the chia gara source rock indicates a heterogeneous organic matter assemblage typical of restricted marine environments in general the activation energy distributions reveal relatively broad and high values ranging from 40 to 64 kcal mol with pre exponential factors varying from 2 2835 e 12 sec to 4 0920 e 13 sec the predicted petroleum formation temperature of onset tr 10 temperatures ranges from 110 to 135 c and peak generation temperatures geological tmax between 137 c and 152 c the peak generation temperatures reach a transformation ratio in the range of 42 50 tr thus the chia gara source rock could have generated and expelled significant quantities of petroleum hydrocarbons in the kurdistan of iraq

petroleum generation and expulsion characteristics of lower and middle jurassic source rocks on the southern margin of junggar basin northwest china implications for unconventional gas potential jurassic strata along the southern margin of junggar basin are important petroleum system elements for exploration in northwest china the lower and middle jurassic source rock effectiveness has been questioned as exploration progresses deeper into the basin these source rocks are very thick and are distributed widely they contain a high total organic carbon composed predominantly of type iii kerogen with some type ii kerogen our evaluation of source rock petroleum generation characteristics and expulsion history including one dimensional basin modeling indicates that jurassic source rocks are gas prone at deeper depths they reached peak oil generation during the early cretaceous and began to generate gas in the late cretaceous gas generation peaked in the paleogene neogene source rock shales and coals reached petroleum expulsion thresholds at thermal maturities of 0 8 and 0 75 vitrinite reflectance respectively when the petroleum expulsion efficiency was 40 the petroleum generated and exp

organic facies and maturation of jurassic cretaceous rocks and possible oil source rock correlation based on pyrolysis of asphaltenes scotian basin canada abstract this paper establishes source rock characterization and oil oil and oil source rock correlations of selected organic rich shale source rocks and selected light oils and condensates from jurassic and cretaceous formations of the scotian basin multiple source rocks of kerogen types iia oil prone iia iib oil and condensate prone iib condensate and gas prone iii gas prone and iv nonsource are identified in various stratigraphic horizons vitrinite reflectance and t inmax data indicate variable maturation histories in different parts of the basin which are related to differences in lithology related heat conductivity and the presence of older sediments closer to areas of rifting multiple linear regression and cluster analyses of aromatic hydrocarbon ratios reveal two oil families some kerogen type iib rock extracts match many of the light oil and condensates in terms of the aromatic hydrocarbon distributions a second family of oils could not be correlated with any of the analyzed source rock extracts pyrolysis gas chromatography of asphaltenes from the cohasset a 52 and sable island 3h 58 wells are significantly different in n alkane aromatics and phenol content the asphaltene pyrolyzates of samples from venture b 52 and s desbarres o 76 have a high aromatic content low content of n alkanes and high phenol values s desbarres which is typical of a terrestial source they correlate well with one another and also with sable island light oil the n triumph g 43 whole rock and extract asphaltene pyrolyzates are dominated by normal hydrocarbons with aromatic phenolic and thiophenic compounds in low concentrations suggesting an algal source algal type organic matter may have made a contribution to the cohasset petroleum as its asphaltene pyrolyzate is also dominated by normal hydrocarbons

evaluation of the petroleum composition and quality with increasing thermal maturity as simulated by hydrous pyrolysis a case study using a brazilian source rock with type i kerogen abstract hydrous pyrolysis hp experiments were used to investigate the petroleum composition and quality of petroleum generated from a brazilian lacustrine source rock containing type i kerogen with increasing thermal maturity the tested sample was of aptian age from the araripe basin ne brazil the temperatures 280 360 c and times 12 132 h employed in the experiments simulated petroleum generation and expulsion i e oil window prior to secondary gas generation from the cracking of oil results show that similar to other oil prone source rocks kerogen initially decomposes in part to a polar rich bitumen which decomposes in part to hydrocarbon rich oil these two overall reactions overlap with one another and have been recognized in oil shale retorting and natural petroleum generation during bitumen decomposition to oil some of the bitumen is converted to pyrobitumen which results in an increase in the apparent kerogen i e insoluble carbon content with increasing maturation the petroleum composition and its quality i e api gravity gas oil ratio c 15 fractions alkane distribution and sulfur content are affected by thermal maturation within the oil window api gravity c 15 fractions and gas oil ratios generated by hp are similar to those of natural petroleum considered to be sourced from similar brazilian lacustrine source rocks with type i kerogen of lower cretaceous age api gravity of the hp expelled oils shows a complex relationship with increasing thermal maturation that is most influenced by the expulsion of asphaltenes c 15 fractions i e saturates aromatics resins and asphaltenes show that expelled oils and bitumen are compositionally separate organic phases with no overlap in composition gas oil ratios gor initially decrease from 508 131 m 3 m 3 during bitumen generation and remain essentially constant 81 84 m 3 m 3 to the end of oil generation this constancy in gor is different from the continuous increase through the oil window observed in anhydrous pyrolysis experiments alkane distributions of the hp expelled oils are similar to those of natural crude oils considered to be sourced from similar brazilian lacustrine source rocks with type i kerogen of lower cretaceous age isoprenoid and n alkane ratios i e pristane n c 17 and phytane n c 18 decrease with increasing thermal maturity as observed in natural crude oils pristane phytane ratios remain constant with increasing thermal maturity through the oil window with ratios being slightly higher in the expelled oils relative to those in the bitumen generated hydrocarbon gases are similar to natural gases associated with crude oils considered to be sourced from similar brazilian lacustrine source rocks with type i kerogen of lower cretaceous with the exception of elevated ethane contents the general overall agreement in composition of natural and hydrous pyrolysis petroleum of lacustrine source rocks observed in this study supports the utility of hp to better characterize petroleum systems and the effects of maturation and expulsion on petroleum composition and quality

geochemical characteristics of the triassic chang 7 lacustrine source rocks ordos basin china implications for paleoenvironment petroleum potential and tight oil occurrence abstract the fact that high quality lacustrine source rocks generally shale and mudstone control the formation and distribution of conventional and unconventional oil and gas reservoirs in lacustrine basins has been well accepted in petroleum exploration and exploitation taking the chang 7 lacustrine source rocks in the ordos basin as an example several points having been reached are as follows 1 the chang 7 source rocks possess an excellent source rock potential and the shales hold a better potential than the mudstones 2 the paleoenvironments of the chang 7 source rocks were sub reducing to sub oxidizing conditions and fresh and brackish water depositional environments with a maximum water depth of 150 m the organic matter origins of the source rocks are mainly plankton algae bacteria and other aquatic microorganisms 3 the beginning time of the oil generation of the chang 7 source rocks is at 165 ma and the peak oil generation occurred during 115 95 ma the cumulative amounts of oil generation are up to 4711 103 t km2 and the ratios of peak generation amounts to cumulative generation amounts are 50 the beginning timing and peak generation timing of the shales are earlier than those of the mudstones respectively and the cumulative oil generation amount of the shales is higher than that of the mudstones indicating a better oil generation potential of the shales 4 due to the more remained oil possessed in the shales the hydrocarbon expulsion threshold of the chang 7 shales 2560 m is deeper than that of the chang 7 mudstones 2080 m 5 the occurrences of the chang 8 6 tight oils are predominantly controlled by the outer boundary of the chang 7 source rocks distribution while the transition areas between thickness toc and ro high value centers are the accumulation and enrichment zones the chang 7 shales controlled the occurrence of the chang 8 tight oil reservoirs and the chang 7 mudstones controlled the occurrence of the chang 7 and chang 6 tight oil reservoirs

source rock evaluation by pyrolysis gas chromatography a pyrolysis gas chromatography system has been developed for the rapid evaluation of potential source rocks for the determination of organic richness and maturation this system uses the pyrolysis methods previously described however the determination of hydrocarbon production type and the identification of contamination by migrated hydrocarbons or drilling additives are accomplished by gas chromatographic gc analysis of the thermal extracts and pyrolysis products of rock samples or isolated kerogens the production type is recognized either qualitatively by gc fingerprint traces or quantitatively by hydrocarbon composition c1 to c6 c6 to c11 c11 from the kerogen peak ii pyrolysate oil prone erogens are recognized by gc traces with a full spectrum of c1 to c28 hydrocarbons or by high concentrations of c11 compounds in contrast gas prone kerogens are characterized by the predominance of light hydrocarbons from c1 to c4 and higher contributions of aromatic compounds mixed type production is intermediate in character between the two contaminants are identified from the gc analysis of the thermally extractable material in peak i possible mineral organic matter reactions during sample heating make interpreting data from whole rock samples more difficult

depositional environment and geochemical characteristics of the lower carboniferous source rocks in the marsel area chu sarysu basin southern kazakhstan abstract there are two sets of carbonate source rocks in the lower carboniferous layers in marsel the visean c1v and serpukhovian c1sr however their geochemical and geological characteristics have not been studied systematically to assess the source rocks and reveal the hydrocarbon generation potential the depositional paleoenvironment and distribution of c1v and c1sr source rocks were studied using total organic carbon toc content rock eval pyrolysis and vitrinite reflectance ro data stable carbon isotope data gas chromatography gc and gas chromatography mass spectrometry gc ms analysis data the data were then compared with well logging data to understand the distribution of high quality source rocks the data were also incorporated into basin models to reveal the burial and thermal histories and timing of hydrocarbon generation the results illustrated that the average residual toc contents of c1v and c1sr were 0 79 and 0 5 respectively which were higher than the threshold of effective carbonate source rocks dominated by type iii kerogen the c1v and c1sr source rocks tended to be gas bearing the two source rocks were generally mature to highly mature the average ro was 1 51 and 1 23 in c1v and c1sr respectively the source rocks were deposited in strongly reducing to weakly oxidizing marine terrigenous environments with most organic material originating from higher terrigenous plants and a few aquatic organisms during the permian the deep burial depth and high heat flow caused a quick and high maturation of the source rocks which were subsequently uplifted and eroded stopping the generation and expulsion of hydrocarbons in the c1v and c1sr source rocks the initial toc fitted by the logr method was recovered and it suggests that high quality source rocks toc 1 are mainly distributed in the northern and central local structural belt

major and trace element geochemistry of the lacustrine organic rich shales from the upper triassic chang 7 member in the southwestern ordos basin china implications for paleoenvironment and organic matter accumulation abstract lacustrine organic rich shales are widespread in the upper triassic yanchang formation chang 7 member of the ordos basin however information on the short term climate evolution within the chang 7 member is still lacking and the mechanism of organic accumulation in the shales remains controversial to address these issues this study analyzes the palaeoenvironment and depositional setting of different intervals in the chang 7 member of the southwestern ordos basin and constrains the main control factors on accumulation and preservation of organic matter based on organic major and trace element data the lower chang 73 shale which contains a high abundance of thermally mature type i and ii kerogen has excellent original hydrocarbon generative potential the lower chang 73 interval has the most humid climatic condition the strongest weathering condition a euxinic bottom water condition a high paleo productivity and a low terrigenous input during the period of upper chang 73 and chang 72 the climate became somewhat drier and hotter which was marked by relatively weak weathering conditions suboxic to anoxic conditions low paleoproductivity and high terrigenous input the chang 71 was characterized by a moderately humid climate moderate weathering conditions paleoproductivity and terrigenous input the relationship among the primary productivity redox conditions clastic influx indicators and toc content suggests that primary productivity was the most critical factor controlling the enrichment of organic matter the high primary productivity during the early chang 73 interval was probably driven by the deposition of volcanic ash and was influenced by marine incursion events a warm and humid paleoclimate combined with input of volcanic ash and seawater resulted in eutrophic nutrient rich and stratified surface water during the early chang 73 period which led to algal blooms with high primary productivity a stratified water column with high primary productivity together with oxygen deficit bottom water conditions and low terrigenous input resulted in the greatest enrichment of organic matter in the lower part of chang 73 shale

geochemistry of a thermally immature eagle ford group drill core in central texas abstract the upper cretaceous eagle ford group displays significant lateral and vertical geochemical variability much of the work on the eagle ford group has been focused southwest of the san marcos arch to more fully characterize the eagle ford across the entire region a thermally immature drill core was acquired north of the san marcos arch that recovered the pepper shale and the eagle ford group molecular and isotopic analyses of rock extracts were combined with bulk organic and inorganic geochemistry and mineralogy to track the variability in organic matter source and depositional environment as well as to identify drivers of organic enrichment the pepper shale received significant terrigenous organic matter in its distal deltaic or prodeltaic setting compared to the more distally deposited eagle ford group that primarily hosts marine organic matter the upper eagle ford contains two chemofacies the older upper eagle ford chemofacies has similar mineralogy and organic matter to the underlying lower eagle ford and both intervals display good to excellent source rock potential in contrast the younger upper eagle ford chemofacies has a different sterane assemblage a larger terrigenous component and a higher clay mineral abundance however anoxic to euxinic depositional conditions distinguish the lower eagle ford from the upper eagle ford which was deposited under oxic to dysoxic conditions redox chemistry and organic matter source are two important variables that determine source rock quality but they did not change in parallel during eagle ford deposition differences in organic facies explain the tmax variability and depositional redox conditions governed organic richness in the eagle ford group in central texas

geochemical evaluation of aliphatic and aromatic hydrocarbons in palaeogene source rocks from the latrobe group gippsland basin australia abstract twenty seven hydrocarbon source rocks from the proteacidites asperopolus malvacipollis diversus and lygistepollenites balmei biozones palaeogene latrobe group in the gippsland basin were analysed using gas chromatography mass spectrometry based on the molecular geochemistry of the aliphatic and aromatic fractions together with bulk geochemical data including rock eval pyrolysis and total organic carbon contents the thermal maturity palaeoenvironments and organic matter source of these palaeogene samples were systematically evaluated the results provide a useful comparison with those from upper cretaceous source rocks in the gippsland basin jiang and george 2018 2019 similar to the upper cretaceous rocks the aliphatic hydrocarbons in the paleogene samples are mainly comprised of n alkanes isoprenoids terpanes hopanes and steranes the aromatic hydrocarbons are dominated by naphthalene phenanthrene anthracene fluorene dibenzofuran dibenzothiophene and their alkyl homologues other aromatic hydrocarbons detected include land plant derived compounds e g retene methylretenes cadalene simonellite etc and combustion derived compounds e g chrysene pyrene picene benzo b fluoranthene benzo a anthracene etc these 4 to 6 ring polycyclic aromatic hydrocarbons are more abundant in the paleogene samples compared to the upper cretaceous rocks biomarker and aromatic hydrocarbon distributions indicate that the proteacidites asperopolus and malvacipollis diversus samples are immature or are in the early stage of the oil generation window while the lygistepollenites balmei samples correspond to the low maturity to mature stage the samples were all deposited under sub oxic to oxic conditions in fresh water with low salinity possibly in a lacustrine depositional environment the organic matter inputs are from plankton algae and higher land plants but are dominated by organic matter with a terrigenous origin

source rock characteristics of the lower cretaceous abu gabra formation in the muglad basin sudan and its relevance to oil generation studies organic rich shale and claystone are present within the lower cretaceous abu gabra formation of the muglad basin representing excellent oil source rocks the source rock potential of abu gabra organicrich whole rock samples from two oilfields in the muglad basin was investigated using bulk and quantitative pyrolysis techniques the analytical program included toc pyrolysis sra pyrolysis gc bulk kinetics elemental analysis and kerogen microscopy the results were used to characterize the kerogen composition and type of petroleum generated from these abu gabra organic rich sediments to clarify the structural variability of the organic matter in the abu gabra source rock the investigated abu gabra organic rich sediments proved to contain excellent quality lacustrine kerogens the samples have moderate to high hydrogen index hi values 267e837 mg hc g rock consistent with predominantly oil prone types i and ii kerogen with a minor contribution of type iieiii kerogens this is supported by the abundant liptinitic materials i e lipid rich structured algae structureless amorphous alginite and sporinite and high atomic hydrogen to carbon h c ratio however pyrolysis gc analysis proved that all the investigated abu gabra samples contain homogeneous type i kerogen that produces mainly waxy oil bulk kinetic experiments on these samples indicate that the source rock facies derived from a homogenous organic matter spans an extremely narrow distribution of activation energy ea ranges from 49 kcal mol to 51 kcal mol the magnitude order of frequency factors a also show a narrow distribution range from 10

comparison of source rock geochemistry of selected rocks from the schei point group and ringnes formation sverdrup basin arctic canada abstract organic rich from the schei point group middle to late triassic in age and the ringnes formation late jurassic from the sverdrup basin of the canadian arctic archipelago have been geochemically evaluated for source rock characterization most samples from the schei point group are organic rich 2 toc and are considered as immature to mature oil prone source rocks kerogen types i i ii iia and ii iia these kerogen types contain abundant aom1 aom2 and alginite tasmanales nostocopsis leiosphaeridia acritarch and dinoflagellate with variable amounts of vitrinite inertinite and exinite samples from the ringnes formation contain dominant vitrinite and inertinite with partially oxidized aom2 alginite and exinite forming mostly immature to mature condensate and gas prone source rocks kerogen type ii iii iib iii and a few ii iia schei point samples contain higher bitumen extract saturate hydrocarbons and saturate aromatic ratio than the ringnes samples triterpane and sterane dominant c 30 distribution patterns and stable carbon isotope of bitumen and kerogen suggest that the analyzed samples from the schei point group are at the onset of oil generation and contain a mixture of sapropelic algal and minor terrestrial humic organic matter sterane carbon number distributions in the ringnes formation also suggest a mixed algal and terrestrial organic matter type there are some variations in hopane carbon number distributions but these are apparently a function of thermal maturity rather than significant genetic differences among samples pyrolysis gas chromatography mass spectrometry of the two samples with similar maturity shows that the schei point sample generates three times more pyrolyzate than the ringnes sample both samples have a dominant aliphatic character although the ringnes sample contains phenol and an aromaticity that is higher than that of the schei point sample

immature oil and condensate modification of hydrocarbon generation model for terrestrial organic matter petroleum has been found in canadian frontier basins in reservoirs which have undergone low levels of thermal alteration vitrinite reflectance 0 6 ro paraffin indices stable carbon and hydrogen isotope contents pristane to nc17 ratios and diterpenoid biologic markers have been used to assess the level of maturity of the hydrocarbons in the reservoir independently of the level of maturity of the reservoir itself and of the surrounding shale units in the tertiary of the beaufort mackenzie basin naphthenic oils and condensates have been generated from terrestrially derived organic matter in source rocks juxtaposed with the reservoir at reflectance levels of 0 4 to 0 6 ro however condensates discovered in reservoirs which are th rmally immature on the labrador shelf have undergone extensive vertical migration and can be classed as conventional mature to overmature condensates hydrocarbons discovered in the lower cretaceous of the beaufort mackenzie basin and also those of the scotian shelf are more or less in place in that they are at a level of thermal alteration about equivalent to that of the reservoirs in which they are trapped the source for the early oils and condensates is considered to be resinite occurring dispersed in coal fragments the proportion of resinite liptinite and vitrinite in the organic matter of terrestrial source rocks strongly controls both the level of thermal alteration necessary for the section to function as an effective source rock and the ultimate product gas oil or condensate which will be generated

relationships between coal quality and organic geochemical parameters a case study of the hafik coal deposits sivas basin turkey abstract this study provides coal quality organic petrographic and organic geochemical data on tertiary subbituminous coal of the hafik area northwestern part of the sivas basin turkey coal petrological studies along with proximate and ultimate analyses were undertaken to determine the organic petrographic characteristics of the hafik coals huminite reflectances were found to be between 0 38 and 0 48 corresponding to an organic material rich and coal layers values characteristic of low maturity this parameter shows a good correlation with calorific values average 21 060 kj kg and average t max 422 c mineral matter diagenesis indicating immaturity the studied coals and organic material underwent only low grade transformation a consequence of low lithostatic pressure therefore the hafik coals are actually subbituminous in rank rock eval analysis results show types ii iii and iii kerogens the organic fraction of the coals is mostly comprised of humic group macerals gelinites with small percentages derived from the inertinite and liptinite groups in this study organic petrographic organic geochemical and coal quality data were compared the hafik deposit is a high ash high sulfur coal the mineral matter of the coals is comprised mainly of calcite and clay minerals

source rock characteristics depositional setting and hydrocarbon generation potential of cretaceous coals and organic rich mudstones from gombe formation gongola sub basin northern benue trough ne nigeria abstract the ongoing exploration activities at the maiganga coal mine uncover some missing gaps in the stratigraphy of the late cretaceous gombe formation therefore there is a need to further investigate this sequence including the organic facies variations and distributions of the coals mudstones and sandy shaly sediments in the gombe sandstone formation gongola sub basin northern benue trough of northeastern nigeria geochemical and petrographic methods were used to assess the organic matter source input paleodepositional conditions thermal maturity and hydrocarbon generation potential of the analysed maiganga and yaya ngari samples field observations showed four coal seams interbedded with mudstones and shales deposited in coarsening upward sequence of a deltaic environment evaluation based on the source rock analyses sra reveals that maiganga sedimentary facies is dominated by terrestrial source input of type iii kerogen this is supported by the biomarker study suggesting land plant origin for the organic matter with minor lacustrine and marine influences in maiganga that grades into predominantly mixed organic matter input of a transitional terrestrial to marine environment in the yaya ngari area this shows a progressive movement towards marine source input paleodepositional conditions of organic matters were sub oxic to oxic in maiganga while the mixed organic matters in yaya ngari were deposited in sub oxic conditions based on organic petrology and bitumen extraction data the maiganga coal was distinctly observed to be immature of pre oil generation window while the yaya ngari is in early oil generation window these analysed sediments are mainly gas prone based on the dominance of type iii kerogen although the presence of type ii iii kerogen supported by relatively higher hi may indicate gas oil potential for the maiganga coal on the other hand type iv kerogen dominated the yaya ngari samples this suggests that these shales are gas prone or do not possess any hydrocarbon generation potential as indicated by the very low hi values

oil oil and oil source rock correlations in the muglad basin sudan and south sudan new insights from molecular markers analyses abstract oil oil and oil source rock correlations for nineteen crude oils and eight mudstone extracts from four sub basins in the muglad basin were achieved by gas chromatography gc and gas chromatography mass spectrometry gc ms based on the characteristics of biomarker compositions and hierarchical cluster analysis an outlier crude oil has been discovered in the muglad basin the majority of discovered oils have similar geochemical characteristics and belong to an established oil family this oil family has relatively higher c19 c20 c23tt and c24tet c26tt ratios small amounts of long chain tricyclic terpanes with a dominance of c21tt among c19 c23tt homologues a lower abundance of c28 regular steranes with abundant c30 4 methylsteranes an unusually higher content of diasteranes and diahopanes these biomarker ratios indicate the mixed inputs of aquatic plankton and terrigenous organic matter deposited under oxic to sub oxic and fresh to brackish water sedimentary environments this oil family belongs to source rocks of the abu gabra formation as proven by oil source rock correlation in contrast the distribution characteristics of tricyclic and tetracyclic terpanes c28 regular steranes c30 4 methylsteranes diasteranes and diahopanes are all significantly different than those of the established oil family in the well kela 1 oil 2563 m within the darfur group reservoir the geochemical signatures indicate that their related source rock is an algal dominated organic matter input deposited in sub oxic condition and brackish to saline sedimentary environment moreover the composition and characteristics of molecular markers of the well kela 1 oil are highly consistent with those of the two mudstone samples from the darfur group this clearly demonstrates that the darfur group mudstones are the potential source rocks for the outlier crude oil identification of the outlier crude oil shows that the darfur group mudstones have a certain potential regarding hydrocarbons resources that could provide petroleum companies an impetus to enhance their exploration efforts

organic geochemical and petrographic characteristics of neogene organic rich sediments from the onshore west baram delta province sarawak basin implications for source rocks and hydrocarbon generation potential abstract the neogene succession of the onshore petroleum prolific west baram province of north west borneo contains organic rich sediments particularly within sarawak basin bulk and quantitative pyrolysis results coupled with organic petrographic characteristics of neogene organic rich sediments have enabled investigation of the source rock characteristics and evaluation of the hydrocarbon generation potential the results were used to assess the quantity of organic matter kerogen composition thermal maturity and type of petroleum that could possibly be generated from these neogene sediments the total organic carbon toc contents of the neogene sediments range between 1 06 and 11 11 wt and hydrogen index hi values are largely below 105 mg hc g toc suggesting that the sediments are organically rich and contain gas prone type iii kerogen this kerogen type is supported by the abundant terrestrial materials i e vitrinite phytoclasts spores and pollen low atomic hydrogen to carbon atomic h c ratio and high abundance of aromatic hydrocarbons in pyrolysis gc pyrograms and would likely generate mainly condensate and gas the analysed samples have vitrinite reflectance in the range of 0 39 0 48 ro and pyrolysis t max in the range of 401 434 c which indicate that these neogene sediments contain immature to very early mature organic matter this implies that these onshore sediments have not been buried to a sufficient depth however the offshore stratigraphic equivalent of these sediments are known to have been buried to deeper depth and could therefore act as an effective petroleum source rock in particular for natural gas

application of aromatic compounds as maturity indicators in source rocks and crude oils concentration ratios of aromatic compounds such as naphthalenes phenanthrenes and dibenzothiophenes are at present attracting increasing attention as maturity indicators in sedimentary rocks and crude oils generally these indicators rely either on an increase with maturity in the degree of alkylation of a given parent compound or a shift in the isomer distribution of alkyl aromatic homologues towards thermally more stable isomers a combination of both concepts in the methylphenanthrene index mpi resulted in an excellent maturity parameter as demonstrated for rock extracts by an improved correlation with mean vitrinite reflectance rm between 0 65 and 1 4 i e in the zone of oil formation in cases that rm measurements were ambiguous this empirical relationship has proved useful in the calculation of theoretical vitrinite reflectance rc values from the mpi on the other hand for potential petroleum source rocks reaching maturity at relatively low temperatures the influence of the organic matter type on the aromatic distributions cannot be neglected consequently organic facies effects should be taken into account in the interpretation of aromatic distributions of such source rocks and related crude oils since the impact of the organic facies is strongly reduced with increasing maturity aromatic maturity parameters are particularly useful in the maturity evaluation of post mature crude oils and condensates in contrast to biological markers substantially higher concentrations of the key alkyl aromatics persist at elevated maturation levels thus aromatic maturity parameters should be considered as versatile tools in organic maturation studies and can complement established maturity indicators based on steranes and terpanes

petroleum source rock evaluation of the sebahat and ganduman formations dent peninsula eastern sabah malaysia the sebahat middle miocene to early pliocene and ganduman early pliocene to late pliocene formations comprise part of the dent group the onshore sebahat and ganduman formations form part of the sedimentary sequence within the sandakan sub basin which continues offshore in the southern portion of the sulu sea off eastern sabah the ganduman formation lies conformably on the sebahat formation the shaly sebahat formation represents a distal holomarine facies while the sandy ganduman formation represents the proximal unit of a fluvial deltaic system based on organic geochemical and petrological analyses both formations posses very variable toc content in the range of 0 7 48 wt for sebahat formation and 1 57 wt for ganduman formation both formations are dominated by type iii kerogen and are thus considered to be gas prone based on hi vs tmax plots although the hi tmax diagram indicates a type iii kerogen petrographic observations indicate a significant amount of oil prone liptinite macerals petrographically it was observed that significant amounts 1 17 by volume of liptinite macerals are present in the ganduman formation with lesser amounts in the sebahat formation both formations are thermally immature with vitrinite reflectance values in the range of 0 20 0 35 ro for ganduman formation and 0 25 0 44 ro for sebahat formation although these onshore sediments are thermally immature for petroleum generation the stratigraphic equivalent of these sediments offshore are known to have been buried to deeper depth and could therefore act as potential source rocks for gas with minor amounts of oil

petrophysical implications of source rock microfracturing abstract hydrocarbon generation induced microfracturing in source rocks is important affecting both primary migration of hydrocarbons and unconventional shale plays in this study petrographic observations rock eval and total organic carbon content toc data and log derived physical properties were analyzed in order to evaluate eventual petrophysical implications of microfracturing induced by hydrocarbon generation petrographically evidences of microfracturing both normal and parallel to bedding have been found horizontal microfractures typically cross cut each other at an angle between 30 and 90 horizontal microfractures are readily imaged compared to vertical microfractures vertical microfractures were clearly observed only in rare cases in samples with a high degree of microfracturing in the case of moderate microfracturing the vertical component of microfractures may be too small to be detectable using conventional microscopy techniques longer vertical components of the microfractures may be facilitated by higher toc and particularly dense laminated organic matter fabric as well as higher thermal maturity levels clay minerals particularly smectites are also playing a role in reducing permeability and thereby increasing the local pressure generated by hydrocarbon generation eventually resulting in microfracturing log derived petrophysical properties particularly p wave velocity vp and formation resistivity can give information on microfracturing potential even though the techniques can t resolve the microfractures directly vp has been postulated to be sensitive to organic matter quantity and fabric whereas formation resistivity is largely governed by fluid content and clay minerals a reverse trend of increasing resistivity with decreasing vp was found and is linked to higher hydrocarbon saturation and toc and or dense laminated fabric of organic matter favoring microfractures the implications of the log derived petrophysical results are in agreement with the direct petrographic observations formation resistivities in the source rocks however are lower than those observed in non clay dominated hydrocarbon saturated intervals this indicate that low permeable organic rich source rocks with a high clay content particularly smectites may facilitate formation of the hydrocarbon filled vertical microfractures even at relatively low thermal maturities

influence of retained bitumen in oil prone shales on the chemical and carbon isotopic compositions of natural gases implications from pyrolysis experiments abstract retained bitumen in oil prone source rocks has a significant impact on late gas generation but such influence is still poorly quantified because it is quite difficult to restore the bitumen content retained in a mature source rock in this study a suite of artificially matured samples were prepared from a moderate maturity shale sample to represent shales with different amount of retained bitumen these samples were then pyrolyzed in sealed gold tubes to investigate how the amount of retained bitumen affects the changes in chemical and carbon isotopic compositions of generated gases and the uncertainty of the evaluation of gas maturity and source identification the results indicate that the decrease in yields of hydrocarbon gases is proportional to the reduction of retained bitumen content however a progressive enrichment in heavier carbon isotope 13c of gaseous hydrocarbons occurs while less amount of bitumen is retained in shales this experimental observation partly explains the heterogeneity of methane carbon isotopes for shale gases that have identical thermal maturity levels although the amount of retained bitumen can significantly change the carbon isotopic ratios of individual gas 13c1 13c2 and 13c3 the difference in carbon isotopic composition between gaseous components such as ethane and methane 13c2 13c1 or propane and ethane 13c3 13c2 are not significantly affected and therefore these differential values can be potentially used as maturity indicators for overmature natural gases exhibiting no carbon isotopic reversals geochemical and carbon isotopic diagrams that are widely used for the identification of oil and kerogen cracking gases are also found to be affected by the retained bitumen content these results illustrate that it is necessary to take into account the retained bitumen content of shales when thermal maturity and genetic origin of natural gases derived from oil prone source rocks are being evaluated

geochemistry of asphaltenes abstract asphaltenes derived from both oil and source rocks have been studied by pyrolysis gas chromatography the pyrograms obtained at 450 and 550 c show that asphaltene structure is very close to the structure of the kerogen of the same sample they can be interpreted as kerogen moieties resulting from its early evolution therefore they can be used as substitutes of kerogen in genetic studies consequently asphaltenes pyrolysis appear to be a tool in correlation studies for oil oil correlation it can supplement and even replace in the case of degraded oils the information given by hydrocarbon distributions for oil source rock correlations the match between pyrograms of asphaltenes from both oil and source rocks offers more direct possibilities than usual techniques

a type of continuous petroleum accumulation system in the shulu sag bohai bay basin eastern china abstract this study analyzed crude oils from the lower part of the third member of the eocene shahejie formation es 3 l and three prospective source rocks from the shulu sag bohai bay basin eastern china using a variety of organic geochemical methods biomarker characteristics were used to interpret source rock organic matter input and depositional environment and oil source rock correlation the biomarker data indicate that the crude oils originated from the es 3 l source rock which contains a mixture of plankton and land plant organic matters deposited in brackish fresh water under reducing conditions the oil in the es 3 l is self sourced instead of migrated from the overlying source rocks the petroleum generation potential of the es 3 l source rock was evaluated using organic geochemistry total organic carbon toc values for approximately 100 samples are between 1 02 and 4 92 wt and hydrogen indices range from 285 to 810 mg hydrocarbons g toc the es 3 l source rock contains mainly type ii and iii kerogen and most of the samples are thermally mature the data show that the es 3 l source rock has good potential for liquid hydrocarbon generation the es 3 l rock also acts as the oil reservoir having very low bulk porosity and permeability various types of storage space in the marlstone and carbonate rudstone in the es 3 l of the shulu sag include 1 fractures 2 intergranular pores 3 dissolution pores 4 organic matter pores 5 intragranular pores and 6 seams around gravels pore size ranges from nanometers to millimeters because the oil was generated and stored in es 3 l strata which lack any obvious trap and seal and have low permeability the unit represents a continuous petroleum accumulation

withdrawn advantageous source reservoir combination in siliciclastic carbonate sedimentary systems in a saline lacustrine basin jiuquan basin nw china implications for prediction of tight oil enrichment

source rock characteristics and hydrocarbon expulsion potential of the middle eocene wenchang formation in the huizhou depression pearl river mouth basin south china sea abstract the middle eocene wenchang wc formation in the huizhou depression of the pearl river mouth basin is an important geological element for petroleum exploration in the south china sea in this study the geological and geochemical characteristics of the wc source rocks including the distribution sedimentary environment organic matter type hydrocarbon generation potential and thermal maturity were investigated hydrocarbon generation history and hydrocarbon expulsion intensity and quantities were evaluated through one dimensional basin modelling and an improved hydrocarbon generation potential methodology the wc source rocks are widely distributed and have an elevated thickness mostly thicker than 200 m with a maximum thickness greater than 1000 m they were deposited in a lacustrine weak oxidation weak reduction sedimentary environment with low salinity the source rocks have low to high organic matter abundance toc mainly ranges from 0 27 to 3 59 wt with an average of 1 39 wt dominated by ii 1 type and ii 2 type kerogen resulting in significant hydrocarbon generating potential under moderate high thermal evolution r o mainly ranges from 0 65 to 1 2 on the margins of sags and greater than 1 2 in the centre of sags the source rocks became mature r o 0 5 in the early miocene and began to generate hydrocarbons they reached the hydrocarbon expulsion threshold at 0 8 r o and the hydrocarbon expulsion rate became greatest at 1 1 r o the expulsion intensities in the h26 sag h21 sag x24 sag and x23 sag are relatively large with their greatest expulsion intensities being 104 10 6 71 10 6 62 10 6 and 53 10 6 t km 2 respectively the comprehensive hydrocarbon expulsion efficiency was approximately 75 about 690 1 10 8 t of hydrocarbons were expulsed from the wc source rocks in the huizhou depression

petrographic classification of oil shales abstract oil shales are a diverse group of rocks that contain mineral matter and organic matter the organic matter is derived from terrestrial lacustrine and marine organisms the maceral nomeclature system of the international committee for coal petrology used widely in coal petrography and petroleum source rock studies is suitable for describing the organic matter in oil shales provided the terminology for organic matter derived from algal precursors is divided into two submacerals telalginite and lamalginite macerals of the liptinite group including alginite are volumetrically important constituents of oil shales and are the major source of the shale oil that is formed during pyrolysis liptinite is easily characterized and quantified using fluorescence mode microscopy and thus the type and abundance of liptinite can be used as a basis for a petrographic classification of oil shales oil shales are grouped using the environmental of deposition as the discriminatory criterion into the three primary divisions of terrestrial lacustrine and marine oil shales type and abundance of liptinite is then used to subdivide these three groups into cannel coal torbanite lamosite further subdivided into rundle type lamosite and green river type lamosite marinite tasmanite and kuckersite

petrologic and organic geochemical characteristics of late permian bark coal in mingshan coalmine southern china abstract bark coal is found only in late permian age coals and only at some specific locations in southern china the depositional environment of bark coal is not yet well understood as a contribution to improving the understanding of the origin of this unusual coal component the petrological characteristics and organic geochemistry of bark coal were investigated by gas chromatography gc analysis gas chromatography mass spectrometry gc ms analysis and coal petrology techniques the samples were selected from the b3 coal seam in the mingshan coal mine leping area in the south of china the thermal maturity and organic matter type of the samples were determined by rock eval analysis and from organic geochemical data barkinite occurs were commonly in the middle and upper parts and less commonly in the lower parts of the b3 coal seam barkinite is type ii kerogen while other samples are type ii iii kerogen consistent with good hydrocarbon generation potential the thermal maturity of the samples is consistent with their being of early mature to peak oil window maturity gas chromatograms obtained from the samples are dominated by long chain n alkanes n c22 to n c27 and high carbon preference index cpi values indicating terrestrial organic matter input the biomarker parameters obtained from mass spectrometer data on m z 191 and m z 217 indicate that the formation of these samples was influenced by marine environment and the deposited organic matter was preserved under relatively oxic conditions

organic geochemical characteristics and oil generating potential of the upper jurassic safer shale sediments in the marib shabowah basin western yemen the organic rich safer shales exposed in the north central part of onshore marib shabowah basin are evaluated and their depositional environments are interpreted total organic carbon contents toc of the shales range from 1 02 16 8 wt and yield hydrogen index hi values ranging from 130 to 820 mg hc g toc consistent with mainly type ii with minor contributions from type i and mixed types ii iii kerogens the safer shale samples have vitrinite reflectance values in the range of 0 5 1 0 ro indicating early mature to peak mature stage for oil generation tmax values range from 429 438 c which are in reasonably good agreement with vitrinite reflectance data kerogen microscopy shows that the safer shales are characterized by high amounts of organic matter consisting predominantly of yellow fluorescing amorphous organic matter and alginite of marine origin this is supported by their high content of hydrogen rich type ii and i oil prone kerogen the biomarker distributions of the upper jurassic safer extracts are characterized by dominant low to medium molecular weight compounds n c14 to n c20 low pr ph ratio 1 0 high phytane n c18 ratios 0 82 2 68 and predominant regular sterane c27 all biomarker parameters clearly indicate that the organic matter was derived from marine algal inputs and deposited under anoxic reducing conditions hypersaline conditions also prevailed during deposition of these sediments as indicated by the presence of gammacerane

re os age and depositional environment for black shales from the cambrian ordovician boundary green point western newfoundland chemical and isotopic signatures for black shales serve as potential proxies for reconstruction of paleoenvironmental conditions here we bring rock eval major and trace element and re os isotopic data together to examine the environmental record at the cambrian ordovician global stratotype section and point gssp at green point in western newfoundland canada the green point shales are oil mature and contain type ii organic material of marine origin a re os isochron for the shales provides the first radiometric age for shale deposition at the gssp at 484 16 ma with an initial 187os 188os ratio of 0 74 0 05 model 3 age mswd 21 n 13 2 uncertainties factor analysis of the geochemical data set shows association of most trace elements with total organic carbon toc and s contents ensuring an authigenic origin for most elements and hence their validity for evaluating the paleo redox state relatively high enrichment factors for redox sensitive elements e g re u and mo compared to average shale but comparatively low enrichment compared to modern black sea sediments suggest deposition in anoxic but not euxinic waters comparison of lower ordovician shale geochemistry data sets at a global scale leads us to suggest that anoxic conditions and warm oceanic regimes were restricted to the margins of laurentia and baltica whereas depositional basins with colder waters e g avalonia and gondwana were less reducing these outcomes underscore the important role of paleogeography in regulating oceanic conditions and marine life

organic geochemistry and petrography of kazhdumi albian cenomanian and pabdeh paleogene potential source rocks in southern part of the dezful embayment iran there are several source rock units in the zagros basin but the cretaceous kazhdumi and paleogene pabdeh formations probably have produced the majority of the commercial hydrocarbons in this area among the hydrocarbon provinces of iran the dezful embayment which is located southwest of zagros mountains is one of the most prolific regions in the middle east numerous studies have been made in the northern part of the dezful embayment but relatively few have been done in its southern part the present study focuses on organic matter characterization of two potential source rocks kazhdumi and pabdeh formations in southern part of the dezful embayment cuttings samples 114 were collected from 10 wells and evaluated using rock eval pyrolysis and organic petrography in order to characterize the content and type of organic matter and thermal maturity the results showed that the average total organic carbon toc content of kazhdumi and pabdeh formations are 2 48 and 1 62 wt respectively the highest toc contents for both formations are found in the northern compartment and decreased gradually toward the south pyrolysis data reveal that organic matter has a fair to very good hydrocarbon generation potential and are classified as type ii iii and type iii rock eval t max and vitrinite reflectance show that the majority of samples are in the early mature to mature stage of the oil generation window c 2012 elsevier ltd all rights reserved

diverse sedimentary conditions during deposition of coal and oil shale from the meihe basin eocene ne china the meihe basin in northeastern china is a normal fault controlled basin filled with eocene nonmarine deposits the sediments assigned to the meihe formation sediment grain sizes core study well log analysis and micropetrographic study combined with sedimentary facies analysis indicate that the main sedimentary facies of the meihe basin represent fan delta lake and turbidite deposits thick coal seams that are mainly distributed in the eastern part of the studied area were deposited in the swamp facies of the lower coal bearing member oil shale was mainly deposited in the deep lake represented by the mudstone member and is mainly distributed in the southern part of the studied area in the lower coal bearing member organic rich sediments are characterized by toc content between 0 6 wt and 43 1 wt and contain type ii and iii kerogen the thick coal seams are the result of high landplant productivity and good preservation conditions thin coal seams in the fan delta plain resulted from the migration and erosion of the fan delta channel in the shallow lake and fan delta front limited productivity coupled with dilution by inorganic matter resulted in lower organic matter content in themudstonemember oil shale and mudstone rich in organic matter were deposited in a deep lake with an average toc content of 3 4 wt the origin of the organic matter was mainly algae and aquatic plants mixed with land plants the improved preservation conditions and high bioproductivity in this environment resulted in three oil shale layers in the lower part of this sedimentary succession three coal bearing and oil shale bearing fault basins lie adjacent to the dunhua mishan fault zone among which the fushun basin is located in the southwest the meihe basin is in themiddle and thehuadian basin is in the southeast from the fushun basin to the huadian basin the oil shale and coal seams have distinct sedimentation characters laterally vertically in each basin the organic matter sources all have the same variation trend from land plants to land plants mixed with algae to algae then to algae mixed with land plants and the toc content also shows a similar trend from high to medium high then to low in each basin

the origins of carbonate minerals of a source controlled lacustrine carbonate succession in the shulu sag bohai bay basin implications for porosity development and paleoenvironment abstract lacustrine carbonates are widely distributed in the third member of the eocene shahejie formation es3l of the shulu sag and other rift basins in the bohai bay basin which can act as reservoirs for hydrocarbon and provide insights into paleoenvironment however the origins of lacustrine carbonate deposition and their implications for porosity development and paleoenvironment are not well understood based on micropetrological characteristics x ray diffraction xrd stable carbon and oxygen isotope analyses and organic geochemistry data four types of calcite calcite debris calcareous biological detritus micrite in fine grained marlstone fibrous sparry calcite and two types of dolomite dolomite debris rhombic euhedral dolomite with distinctly different characteristics and origins are identified the 13c and 18o values of calcite and dolomite debris are consistent with that of the cambrian ordovician carbonate rock in the provenance area suggesting that the carbonate debris was sourced from the surrounding cambrian ordovician carbonate bedrock microcrystalline calcites are commonly developed in organic rich marlstones with a large number of algae the 13c values of the microcrystalline calcites are higher than that of carbonate debris and the positive excursion of the 13c value is along with the increase of toc content these indicate that origin of the microcrystalline calcite was authigenic calcite and was formed by biochemical process bedding parallel fibrous sparry calcite occurs in intervals with high toc contents and within the thermally mature zone of hydrocarbon generation indicating that oil generation should be responsible for the sparry calcite formation rhombic euhedral dolomite commonly occurs as isolated micro crystals with euhedral to subhedral rhombs shape micro sized spherule like dolomite in the early stage of crystal growth were also present rhombic euhedral dolomite are commonly associated with organic matter and developed in organic matter rich intervals with plenty of fossilized bacterial filaments and framboidal pyrite these suggest that rhombic euhedral dolomite were probably microbially mediated dolomite mineral components can affect reservoirs quality the porosities of samples show a positive correlation with dolomite content and the porosities of fibrous sparry calcite bearing intervals are higher than non parry calcite bearing intervals the increase in authigenic microcrystalline calcite content reflects a rise in lake level and an increase in water depth and primitive productivity

organic geochemistry of agacbasi yayla peat deposits koprubasi trabzon ne turkey abstract peat deposits which outcrop in the southern agacbasi region in trabzon northern turkey were studied by using chemical organic geochemical petrographic and palynological characteristics of peats palynological data indicate that the peats were deposited in terrestrial or lacustrine environments comprising organic matter with an average composition of 70 woody 19 3 herbaceous and 10 7 amorphous material the peats are holocene recent in age the peat organic matter that has been interpreted as immature based on the sci spore color index analyses suggests that the peat organic matter was immature rock eval analyses show that the average total organic carbon toc content of the peat is 42 and the average hi value is 315 mghc gtoc which is very high for peat the high oi values avg 134 mgco 2 gtoc point that the depositional environment of peats were deposits under oxic or suboxic conditions the selected sample aby 13 with the highest extractable yield has tar terrigenous aquatic ratio and cpi carbon preference index index values of 2 4 and 3 4 respectively these values reflect high levels of n alkanes supporting a terrestrial organic matter input the p aq aquatic plant n alkane proxy ratio 0 6 indicates that there was a contribution from mixtures of submerged floating emergent and terrestrial plant mixtures the p wax vascular plant n alkane proxy ratio 0 6 is a sign of moist and wetter conditions the toc acl q wood grass c 27 c 31 q wood plant c 27 c 29 c 27 c 29 c 31 and q grass plant c 31 c 27 c 29 c 31 values indicate that woody plants were the dominant vegetation in the peat mire was woody plants and the climate was relatively wet and cold according to the m z 191 and m z 217 fragments tracking from gc ms chromatogram data obtained using biomarker analyses the lack of c 34 and c 35 homohopanes was interpreted as that organic matter was deposited under oxic or suboxic conditions moretane hopane tm ts and tm c 30 pentacyclic triterpane ratios also point indicate oxic and acidic conditions during the formation of the peat the absence of 17 h 28 30 bisnorhopane from the m z 191 chromatograms support the interpretation that the agacbasi yayla peat was deposited in a terrestrial or lacustrine environment under oxic or suboxic conditions the dominance of c 29 steranes indicates significant terrestrial organic matter input using sterane carbon number distributions the extract of the peat sample plots in the terrigenous region additionally c 30 steranes which imply marine environments were not detected the ts ts tm ratios also suggest that the peat contained immature organic matter

oil source rock correlation for tight oil in tuffaceous reservoirs in the permian tiaohu formation santanghu basin northwest china tight oil in the permian tiaohu formation in the santanghu basin northwest china has a peculiar property such that the reservoir is sedimentary organic matter bearing tuff characterized by high porosity 10 25 and very low permeability mainly in the range of 0 01 0 50 md biomarker and stable carbon isotope compositions of selected crude oils and source rock extracts were analyzed to determine the source rock of the tight oil source rocks in the lucaogou formation consist of various rock types dominated by mudstones containing organic matter with intense yellow green fluorescence mudstones in the lucaogou formation have total organic carbon toc values mainly in the range of 1 0 8 0 wt hydrocarbon generation potential s1 s2 mostly 6 mg g and chloroform extractable bitumen a generally 0 1 the maceral composition is predominantly fluorescing amorphinite the hydrogen index hi varies from 300 to 900 mg hc g toc indicating dominant type i and type ii kerogen compared with the mudston

a petrological and organic geochemical study of permian coal seams east of maracaja south santa catarina parana basin brazil abstract coal samples from the permian rio bonito formation collected from borehole mml 09 east of maracaja south santa catarina parana basin brazil were characterized by petrological vitrinite reflectance measurements maceral analyses and geochemical rock eval total organic carbon toc and gc ms methods the mean vitrinite reflectance values range from 0 73 to 0 87 rrandom indicating a rank level of high volatile b a bituminous the maceral composition showed predominance of vitrinite 49 4 to 61 2 vol and inertinite 9 to 24 5 vol the rock eval analysis presented the following values s1 and s2 ranging from 0 74 to 2 51 mg hc g coal and 34 1 to 108 87 mg hc g coal respectively hydrogen indices between 158 and 240 mg hc g toc and tmax c between 440 and 448 c the toc contents of the coal samples present values ranging from 18 85 to 45 31 wt vitrinite reflectance and rock eval tmax values indicate that the coals are in the beginning of the oil generation window the potential for the formation of liquid hydrocarbons is rather low due to the nature of the humic coal whereas the rank level indicates that generation of gas from the coal has occurred the biomarker analysis using gc ms and gc ms ms allowed the interpretation of the depositional environment and provided another way of determining the degree of maturity of the coals besides vitrinite reflectance and tmax the pristane phytane pr ph ratio is 1 mainly controlled by organic matter type implied suboxic conditions during sedimentation the vitrinite reflectance measurements tmax values and 20s 20s 20r and ratios for c29 regular steranes revealed the marginally mature stage of the organic matter although the distribution of hopanes indicated a mature stage of the organic matter due to the absence of hopanes and predominance of the 22s epimer over the 22r epimer for the hopanes from c 31 to c 35

trends in thermal maturity indicators for the organic sulfur rich eagle ford shale abstract thermal maturity is critical to evaluate petroleum systems and to interpret biomarker results for paleoenvironmental and geobiology studies many thermal maturity indices were developed for marine source rocks containing type ii kerogen but their behavior in organic sulfur rich source rocks requires more investigation here we present geochemical analyses of whole and extracted rock isolated kerogen and extractable organic matter across a natural thermal maturity sequence of the upper cretaceous eagle ford shale to evaluate the behavior of maturity parameters in organic sulfur rich source rocks the samples have similar mineralogy and trace element composition minimizing potential facies effects on thermal maturity parameters atomic h c ratios of isolated kerogen extractable organic matter yield and programmed pyrolysis results show that the samples range from the pre oil through dry gas generation windows programmed pyrolysis data and kerogen elemental ratios show that the immature samples host both type iis atomic sorg c 0 04 and sulfur rich type ii kerogen kerogen sorg c 0 03 0 04 while samples with lower kerogen sorg c ratios kerogen sorg c

mechanism of hydrocarbon accumulation and enrichment of tuffaceous tight oil with separate reservoir and source rock a case study of tuff reservoir from the permian tiaohu formation in the santanghu basin northwest china different from most tight oil reservoirs the tuffaceous tight oil of the tiaohu formation is not in situ oil and no close contact exists between the source rock and reservoir in the malang sag santanghu basin china this study determined the mechanism of hydrocarbon accumulation of this tuffaceous tight oil reservoir through an integrated analysis of oil source rock correlation reservoir characteristics and rock wettability combined with a comprehensive analysis of geological conditions an oil source rock correlation using biomarkers and stable carbon isotopes shows that the crude oil originated from underlying source rocks in the lucaogou formation the oil in the tuffaceous tight reservoir is not indigenous but has migrated over a long distance to accumulate in these reservoirs faults and fractures that developed at the end of the cretaceous are the oil migration pathways vitric and crystal vitric tuffs constitute the main rock types of the tuffaceous tight reservoir matrix related pores in the tuffs mainly comprise interparticle pores between minerals and dissolution intraparticle pores formed by devitrification the adsorption of polar components of the oil generated from original organic matter in the tuff leads to wettability of lipophilicity which is the main reason for hydrocarbon charging and accumulation to our knowledge this is the first comprehensive study reporting this finding

organic petrographic characteristics of tertiary oligocene miocene coals from eastern malaysia rank and evidence for petroleum generation abstract oligocene to miocene coals from eastern malaysia were analysed to evaluate their regional ranks and petroleum generative potential the current study performs organic geochemical characteristics of the coals and identifies macerals based on their organic petrographic characteristics as observed under reflected white light and blue light excitations the coals are characterised by relatively high hydrogen index values between 282 and 516 mg hc g toc this indicates that these coals are dominated by type ii to mixed type ii iii kerogens and are thus considered to be generated mainly oil prone and limited gas prone this is supported by the presence of significant amounts 11 31 by volume of oil prone liptinite macerals suberinite is among the most common of the oil prone liptinite macerals in coals these coals likely are to be potential petroleum sources thus where the former is abundant waxy oils and naphthenic oil might be expected this has been supported by the distribution of n alkyl chains within kerogen pyrolysates predicting the generation of a mainly paraffinic and paraffinic naphthenic aromatic p n a high wax oils the coals are thermally early mature and coal rank in the region is subbituminous a to high volatile bituminous c possessing vitrinite reflectance in the range of 0 50 0 67 this maturity has a considerable influence on the proximate analysis particularly on a relatively low moisture content and relatively high fixed carbon and low volatile matter contents although these onshore coals are thermally early mature for petroleum generation the stratigraphic equivalent of these sediments offshore is known to have been buried to deeper depth and could therefore act as potential source rock for mainly oil with minor amounts of gas

geochemical characteristics of crude oil from a tight oil reservoir in the lucaogou formation jimusar sag junggar basin jimusar sag which lies in the junggar basin is an important tight oil study area in china however the properties and origin of the crude oil and the geochemical characteristics of the tight oil from the lucaogou formation have not yet been studied in the present study 23 crude oil samples from the lucaogou formation were collected for analysis including physical properties density and viscosity bulk composition saturated hydrocarbon gas chromatography mass spectrometry and calculation of various biomarker parameters source rock evaluation and porosity permeability analysis were applied to the mudstones and siltstones to analyze the hydrocarbon generation history of the lucaogou source rocks one dimensional basin modeling was performed the oil filling history was also investigated by means of basin modeling and microthermometry biomarkers of suitable source rocks total organic carbon content is 1 summation of the free and volatile hydrocarbon and remaining hydrocarbon generative potential is 6 mg hc g rock and vitrinite reflectance is between 0 7 and 1 were analyzed for oil source correlation the results indicate that low maturity to mature crude oils originated from the source rocks containing terrigenous organic matter which were deposited in a saline lake the source rocks are of mainly type ii kerogen oil in the lower section of the lucaogou formation is relatively dense and viscous and has elevated nonhydrocarbon content in addition a higher proportion of bacteria and algae is shown to have contributed to the formation of crude oil in the lower section when compared with the upper section of the lucaogou formation oil source correlations demonstrate that not all mudstones within the lucaogou formation contribute to oil accumulation thin section observation indicates organic macerals surround the grains of some siltstones within the porous and permeable subsections which proves the siltstones contribute to hydrocarbon generation crude oils from the upper and lower sections mainly originate from thin bedded mudstones interbedded and siltstones within the porous and permeable subsections the mudstones over or beneath the porous and permeable subsections consist of seals and prevent the vertical movement of oil by capillary forces despite being thicker mudstones between the two porous and permeable subsections make no obvious contribution to the oil accumulation because of their low permeability and distance from the porous and permeable subsections which is consistent with the principle of near source charging for tight oil accumulations lucaogou oil has been charged twice once from 235 to 210 ma and again from 180 to 150 ma coinciding with oil generation time

organic geochemistry petrology and palynofacies of middle devonian lacustrine flagstones in the orcadian basin scotland depositional environment thermal history and petroleum generation potential during middle devonian time a thick succession of organic rich mainly lacustrine flagstones developed within the orcadian basin these petroleum source rocks crop out in northern scotland nineteen samples were studied using organic petrology palynology and organic geochemistry in order to characterize kerogen type depositional environment thermal maturity and petroleum generation potential c org carbonate and sulphur content as well as hydrogen index hi values are quite variable e g hi from 79 to 744 mg hc g c org based on biomarker data organic material mainly originates from aquatic organic matter deposited under lacustrine conditions with oxygen depleted but not permanently anoxic bottom waters petrography reveals small quantities of vitrinite particles indicating minor input of terrestrial material this is supported by biomarker data and the palynofacies which is characterized by a high amount of oil prone amorphous organic matter aom and generally few miospores maturity of the succession studied in caithness and orkney is between immature and oil mature one dimensional basin modelling shows that a significant remaining hydrocarbon generation potential exists within the middle devonian succession in contrast to the low hydrocarbon generation in the onshore area offshore oil generation was significant especially after deposition of thick upper jurassic upper cretaceous sediments at the end of cretaceous time hydrocarbon generation ceased due to uplift the contribution to known oil fields from the devonian flagstones is a realistic scenario including a contribution to the beatrice oil field in the south of the modelled area

geochemical and petrographic characterization of late jurassic early cretaceous chia gara formation in northern iraq palaeoenvironment and oil generation potential the marine late jurassic to early cretaceous chia gara formation is well exposed in northern iraq it is built of organic rich limestones and calcareous shales the organic rich sediments have been investigated to determine the type and origin of the organic matter as well as their petroleum generation potential kerogen microscopy shows that these sediments are characterized by large amounts of predominantly amorphous organic matter with a total organic carbon content of 7 42 the large amounts of organic matter are mainly due to good preservation under anoxic conditions as evidenced by numerous pyritized fragments and biomarkers that are diagnostic for the depositional environment the investigated biomarkers are characterized by a dominance of low to medium molecular weight compounds a low pr ph ratio 1 0 a composition of c27 c29 regular steranes and the presence of tricyclic terpanes indicating a strong decay of marine organic matter preserved under reducing conditions a small amount of terrigenous organic matter is according to the n alkane distribution also present the chia gara sediments thus have a high oil but a low gas generation potential due to the high content of hydrogen rich type ii and mixed type ii iii kerogens with a minor contribution of type iii kerogen