Oil-generation kinetics for organic facies with Type-II and -IIS kerogen in the Menilite Shales of the Polish Carpathians

The Menilite Shales (Oligocene) of the Polish Carpathians are the source of low-sulfur oils in the thrust belt and some high-sulfur oils in the Carpathian Foredeep. These oil occurrences indicate that the high-sulfur oils in the Foredeep were generated and expelled before major thrusting and the low-sulfur oils in the thrust belt were generated and expelled during or after major thrusting. Two distinct organic facies have been observed in the Menilite Shales. One organic facies has a high clastic sediment input and contains Type-II kerogen. The other organic facies has a lower clastic sediment input and contains Type-IIS kerogen. Representative samples of both organic facies were used to determine kinetic parameters for immiscible oil generation by isothermal hydrous pyrolysis and S₂ generation by non-isothermal open-system pyrolysis. The derived kinetic parameters showed that timing of S₂ generation was not as different between the Type-IIS and -II kerogen based on open-system pyrolysis as compared with immiscible oil generation based on hydrous pyrolysis. Applying these kinetic parameters to a burial history in the Skole unit showed that some expelled oil would have been generated from the organic facies with Type-IIS kerogen before major thrusting with the hydrous-pyrolysis kinetic parameters but not with the open-system pyrolysis kinetic parameters. The inability of open-system pyrolysis to determine earlier petroleum generation from Type-IIS kerogen is attributed to the large polar-rich bitumen component in S₂ generation, rapid loss of sulfur free-radical initiators in the open system, and diminished radical selectivity and rate constant differences at higher temperatures. Hydrous-pyrolysis kinetic parameters are determined in the presence of water at lower temperatures in a closed system, which allows differentiation of bitumen and oil generation, interaction of free-radical initiators, greater radical selectivity, and more distinguishable rate constants as would occur during natural maturation. Kinetic parameters derived from hydrous pyrolysis show good correlations with one another (compensation effect) and kerogen organic-sulfur contents. These correlations allow for indirect determination of hydrous-pyrolysis kinetic parameters on the basis of the organic-sulfur mole fraction of an immature Type-II or -IIS kerogen.     

Comparison of natural gases accumulated in Oligocene strata with hydrous pyrolysis gases from Menilite Shales of the Polish Outer Carpathians

This study examined the molecular and isotopic compositions of gases generated from different kerogen types (i.e., Types I/II, II, IIS and III) in Menilite Shales by sequential hydrous pyrolysis experiments. The experiments were designed to simulate gas generation from source rocks at pre-oil-cracking thermal maturities. Initially, rock samples were heated in the presence of liquid water at 330 °C for 72 h to simulate early gas generation dominated by the overall reaction of kerogen decomposition to bitumen. Generated gas and oil were quantitatively collected at the completion of the experiments and the reactor with its rock and water was resealed and heated at 355 °C for 72 h. This condition simulates late petroleum generation in which the dominant overall reaction is bitumen decomposition to oil. This final heating equates to a cumulative thermal maturity of 1.6% R_r, which represents pre-oil-cracking conditions. In addition to the generated gases from these two experiments being characterized individually, they are also summed to characterize a cumulative gas product. These results are compared with natural gases produced from sandstone reservoirs within or directly overlying the Menilite Shales. The experimentally generated gases show no molecular compositions that are distinct for the different kerogen types, but on a total organic carbon (TOC) basis, oil prone kerogens (i.e., Types I/II, II and IIS) generate more hydrocarbon gas than gas prone Type III kerogen. Although the proportionality of methane to ethane in the experimental gases is lower than that observed in the natural gases, the proportionality of ethane to propane and i-butane to n-butane are similar to those observed for the natural gases. δ¹³C values of the experimentally generated methane, ethane and propane show distinctions among the kerogen types. This distinction is related to the δ¹³C of the original kerogen, with ¹³C enriched kerogen generating more ¹³C enriched hydrocarbon gases than kerogen less enriched in ¹³C. The typically assumed linear trend for δ¹³C of methane, ethane and propane versus their reciprocal carbon number for a single sourced natural gas is not observed in the experimental gases. Instead, the so-called “dogleg” trend, exemplified by relatively ¹³C depleted methane and enriched propane as compared to ethane, is observed for all the kerogen types and at both experimental conditions. Three of the natural gases from the same thrust unit had similar “dogleg” trends indicative of Menilite source rocks with Type III kerogen. These natural gases also contained varying amounts of a microbial gas component that was approximated using the Δδ¹³C for methane and propane determined from the experiments. These approximations gave microbial methane components that ranged from 13–84%. The high input of microbial gas was reflected in the higher gas:oil ratios for Outer Carpathian production (115–1568 Nm³/t) compared with those determined from the experiments (65–302 Nm³/t). Two natural gas samples in the far western part of the study area had more linear trends that suggest a different organic facies of the Menilite Shales or a completely different source. This situation emphasizes the importance of conducting hydrous pyrolysis on samples representing the complete stratigraphic and lateral extent of potential source rocks in determining specific genetic gas correlations.     

Origin and alteration of oils and oil seeps from the Sinú-San Jacinto Basin, Colombia

Liquid hydrocarbons have been detected in the subsurface as well as in the surface in the Sinú-San Jacinto Basin (northwestern Colombia). The origin of the oils has not been conclusively established especially in the southern part of the basin. The most likely source rocks in the basin are the Ciénaga de Oro Fm. of the Oligocene-Early Miocene and the Cansona Fm. of the Upper Cretaceous. In this study, oil samples, seeps and source rock extracts were analyzed by GC and GC/MS, and δ¹³C was determined to identify the source facies. The sulphur content and gravity data were also considered.Two organic facies were identified: one constituted by terrestrial organic matter deposited in siliciclastic sediments in marginal marine to deltaic environments and the other made up of marine organic matter deposited in marine costal shelf to pelagic environments. The oils from the former organic facies have low sulphur contents, whereas the oils from the latter facies have high sulphur levels. Correlation of the oil seeps from the former facies with the Ciénaga de Oro Fm. has not been clearly established. The oil seeps from the latter facies correlate well with the extracts from the source rocks of the Cansona Fm., deposited along the fold belt of San Jacinto (east side). The oil seeps are affected by moderate to severe biodegradation, whereas the oil from the only oil producing well in the Sinú Basin (Floresanto-6 well) has not undergone biodegradation.     

The occurrence of ultra-deep heavy oils in the Tabei Uplift of the Tarim Basin,NW China

Deeply buried heavy oils from the Tabei Uplift of the Tarim Basin have been investigated for their source origin, charge and accumulation time, biodegradation, mixing and thermal cracking using biomarkers, carbon isotopic compositions of individual alkanes, fluid inclusion homogenization temperatures and authigenic illite K–Ar radiometric ages. Oil-source correlation suggests that these oils mainly originated from Middle–Upper Ordovician source rocks. Burial history, coupled with fluid inclusion temperatures and K–Ar radiometric ages, suggests that these oils were generated and accumulated in the Late Permian. Biodegradation is the main control on the formation of these heavy oils when they were elevated to shallow depths during the late Hercynian orogeny. A pronounced unresolved complex mixture (UCM) in the gas chromatograms together with the presence of both 25-norhopanes and demethylated tricyclic terpanes in the oils are obvious evidence of biodegradation. The mixing of biodegraded oil with non-biodegraded oil components was indicated by the coexistence of n-alkanes with demethylated terpanes. Such mixing is most likely from the same phase of generation, but with accumulation at slightly different burial depths, as evidenced by overall similar oil maturities regardless of biodegradation level and/or amount of n-alkanes. Although these Ordovician carbonate reservoirs are currently buried to over 6000 m with reservoir temperatures above 160 °C, no significant secondary hydrocarbon generation from source rocks or thermal cracking of reservoired heavy oil occur in the study area. This is because the deep burial occurred only within the last 5 Ma of the Neogene, and there has not been enough heating time for additional reactions within the Middle–Upper Ordovician source rocks and reservoired heavy oils.     

A review of the occurrences and causes of migration-contamination in crude oil

Migration-contamination occurs when a migrating or trapped crude oil functions as a solvent, dissolving molecular components from the syndepositional organic matter of the migration conduit and/or the reservoir rock. This review documents the causes and worldwide occurrences of migration-contamination, and suggests methods of identifying the signatures of this phenomenon within the molecular and isotopic composition of crude oils. Instances of migration-contamination have been identified in oils of Australia, Asia, Africa and North America, and are best identified by the presence of molecular and/or isotopic imbalances in the oil. Such imbalances are most apparent when co-occurring molecular suites are incompatible with one another, particularly in terms of thermal maturity. Occurrences of migration-contamination in oils of the US Gulf of Mexico—documented by molecular maturity imbalances such as the presence of unsaturated hydrocarbons known to be unstable at petroleum generation temperatures—provide the best examples of this phenomenon. An attempt is made to quantify the extent and impact of this process in the Vermilion 14 field, offshore Louisiana in the US Gulf of Mexico. Here, molecular maturity markers in the migrated fluid and in the syndepositional organic matter of the reservoir rocks are compared, and the proportion of contamination in each reservoired fluid is estimated. Examples such as this may assist in explaining maturity anomalies observed in several oils worldwide, particularly in Tertiary-reservoired oils that have migrated through, and are trapped in, thermally immature sediments. It is suggested that the low molecular maturity ratios often observed in Tertiary-reservoired oils and attributed to unusually high heating rates may be caused, at least in part, by migration-contamination.     

Lower Carboniferous peritidal carbonates and associated evaporites adjacent to the Leinster Massif,southeast Irish Midlands

Analysis of a 275 m‐thick section in the Milford Borehole, GSI‐91‐25, from County Carlow, Ireland, has revealed an unusual sequence of shallow subtidal, peritidal and sabkha facies in rocks of mid?‐late Chadian to late Holkerian (Viséan, Lower Carboniferous) age. Sedimentation occurred on an inner ramp setting, adjacent to the Leinster Massif. The lower part of the sequence (late Chadian age) above the basal subtidal bioclastic unit is dominated by oolite sand facies associations. These include a lower regressive dolomitized, oolitic peloidal mobile shoal, and an upper, probably transgressive, backshoal oolite sand. A 68 m‐thick, well‐developed peritidal sequence is present between the oolitic intervals. These rocks consist of alternating stromatolitic fenestral mudstone, dolomite and organic shale, with evaporite pseudomorphs and subaerial exposure horizons containing pedogenic features. In the succeeding Arundian–Holkerian strata, transgressive–regressive carbonate units are recognized. These comprise high‐energy, backshoal subtidal cycles of argillaceous skeletal packstones, bioclastic grainstones with minor oolites and algal wackestones to grainstones and infrequent algal stromatolite horizons. The study recognizes for the first time the peritidal and sabkha deposits in Chadian rocks adjacent to the Leinster Massif in the eastern Irish Midlands. These strata appear to be coeval with similar evaporite‐bearing rocks in County Wexford that are developed on the southern margin of this landmass, and similar depositional facies exist further to the east in the South Wales Platform, south of St. George's Land, and in Belgium, south of the Brabant Massif. The presence of evaporites in the peritidal facies suggests that dense brines may have formed adjacent to the Leinster Massif. These fluids may have been involved in regional dolomitization of Chadian and possibly underlying Courceyan strata. They may also have been a source of high salinity fluids associated with nearby base‐metal sulphide deposits. Copyright © 2005 John Wiley & Sons, Ltd.     

石油碳、氢同位素组成的研究

通过对我国18个含油气区、385个石油样品进行碳、氢同位素和部分馏份碳同位素分析,将所获数据对两种不同性质的石油如正常原油和轻质（凝析）油分别研究其碳、氢同位素地球化学特征,提出轻质（凝析）油的碳同位素值（δ13C为-32.5‰～ -24.3‰）比正常原油δ13C为-34.4‰～ -24.6 ‰．6‰）相对偏高;石油馏份中芳烃碳同位素组成的变化受母质继承效应更为明显。因此,用芳烃碳同位值可以判识不同母质来源的石油。与海相有关的轻质（凝析）油的氢同位素值大于-15.0‰,而非海相轻质（凝析）油的δD值( δD为-21.0‰～-1.05‰）基本覆盖了海相轻质油的分布范围,从淡水－微咸水－半咸水和海水环境其氢同位素有明显变重趋势,表明氢同位素主要与沉积环境密切相关。     

Genesis of Oils in Eastern Kamchatka: Evidence from Hydrocarbon Biomarkers

Gas chromatography and gas chromatography–mass spectrometry data on oils from wells and seeps in the Eastern Kamchatka Basin indicate that, according to their composition and the distributions of biomarker molecules, these oils can be classified into three groups, which differ in the composition of the parent organic matter, litho–facies sedimentation conditions, and catagenetic transformations. Oils from the wells were determined to be produced by organic matter of the sapropel type of marine facies in the main oil window (MC₂). Condensate from the natural seep was generated at higher catagenesis grades (MC_2–3) by organic matter of the sapropel–humus type of littoral facies. Uzon oil shows are demonstrated to be formed in a continental environment by organic matter of the humus–sapropel type and were not genetically related to oil from the Paleogene–Neogene source rocks of the Bogachevka Formation.     

Origin of oils in the Eastern Papuan Basin,Papua New Guinea

The geochemical characteristics of 16 oils/condensates/seep oil/oil shows (collectively called oils) from the Eastern Papuan Basin (EPB) and one seep oil from the Western Papuan Basin (WPB) are integrated with data from previous studies of oils, fluid inclusion oils and solid bitumens from the EPB and WPB, Papua New Guinea. The combined set of samples can be divided in two major families of hydrocarbons. The Family A oils, mostly occurring in the WPB region, were generated from clay rich marine source rocks, containing predominantly terrigenous higher plant derived organic matter (OM) deposited in a sub-oxic to oxic environment. Source rock(s) for Family A oils are likely to be of Middle to Upper Jurassic, e.g., the Upper Jurassic Imburu Formation. The Family B oils, distributed mainly in the EPB region, were generated from Cretaceous or younger marine carbonate source rock(s) deposited under anoxic to sub-oxic conditions, and containing predominantly prokaryotic OM with some terrigenous higher plant inputs. The EPB natural gases analyzed in this study may be co-genetic to the co-occurring Family B oils in the EPB. Both Family A and B oils were generated at similar thermal maturities of 1.0–1.3% vitrinite reflectance equivalent. Although no source interval to date has been firmly identified in the EPB, post-Jurassic strata are a viable option, because (1) Late Cretaceous and Paleogene carbonate and clastic marine sediments including possible source lithologies are present, and (2) this section of the Papuan Basin sustained rapid sedimentation and tectonic loading, particularly in the Cenozoic.     

Stable carbon isotopic compositions of individual aromatic hydrocarbons as source and age indicators in oils from western Australian basins

The present study aims to establish the factors controlling the stable carbon isotopic compositions (δ¹³C) of individual aromatic hydrocarbons analysed by compound specific isotope analysis (CSIA) in crude oils from western Australian petroleum basins of varying age and facies type. This paper reports δ¹³C values of individual aromatic hydrocarbons, like alkylbenzenes, alkylnaphthalenes, alkylphenanthrenes and methylated biphenyls. The main aims are to confirm the origin (source) and age of these oils based on CSIA of selected aromatic compounds and to understand why the Sofer plot is ineffective in establishing the source of western Australian petroleum systems. The bulk δ¹³C of saturated and aromatic hydrocarbon fractions of crude oils have been previously used to differentiate sources, however, many Australian crude oils are not classified correctly using this method. The oils were classified as marine by the δ¹³C values of individual aromatic compounds and as terrigenous based on the bulk δ¹³C data (Sofer plot).The oils where the δ¹³C values of 1,6-DMN and 1,2,5-TMN isomers are most negative are indicative of a marine source, whereas oils with a less negative values for the 1,6-DMN and 1,2,5-TMN isomers are derived from marine source rocks that contain a significant terrigenous component. Similarly, oils with the least negative δ¹³C values for the 1-MP and 1,9-DMP isomers reflect varying inputs of terrigenous organic matter to the their marine source rocks. Plots of P/DBT and Pr/Ph concentration ratios versus δ¹³C values of DMP, 1,6-DMN, 1,2,5-TMN, 1-MP and 1,9-MP are constructed to establish the relative amount of terrigenous organic matter contributing to the source rock of a series of marine oils. The ratios of P/DBT and Pr/Ph plotted against the δ¹³C values of the aromatic isomers (such as 1,6-DMN, 1,2,5-TMN, 1-MP and 1,9-MP) provide a novel and convenient way to discriminate crude oils derived from different source rocks that contain varying amounts of marine and terrigenous organic matter.     

Phenanthrene biomarkers in the organic matter of Precambrian and Phanerozoic deposits and in the oils of the Siberian Platform

The composition and distribution of phenanthrenes (polyaromatic compounds) have been studied in chloroform extracts from dispersed organic matter (OM) of clayey, siliceous, carbonate, and terrigenous rocks of different ages and facies and from some oils of the Siberian Platform. Phenanthrenes have been analyzed by gas chromatography-mass spectrometry. High contents of 1,7,8-trimethylphenanthrene and 1,1,7,8-tetramethyl-1,2,3,4-tetrahydrophenanthrene are present in the OM of Vendian and Cambrian carbonate-shale deposits and in ancient oils of the Nepa-Botuobiya and Anabar anteclises. The OM of Permian continental deposits and oils of the Vilyui syneclise is dominated by 1-methyl-7-isopropylphenanthrene (retene). A triangular diagram for identification of the types of original OM of rocks and classification of genetically related oils has been constructed based on the assessment of phenanthrene biomarker distribution. Putative pathways of the formation of phenanthrene biomarkers are discussed.     

华北中元古代陆表海氧化还原条件

文石海底沉淀是地球早期大气高CO2浓度、海洋贫氧条件下,CaCO3过饱和而直接沉淀于海底所形成的自生碳酸盐,可反映古海洋贫氧状态.对华北中元古界雾迷山组(ca 1.50～1.45 Ga)碳酸盐岩的研究发现:潮下带下部黑色纹层石由针状文石假晶等厚层与微生物席层交互堆叠而成;潮下带中部凝块石白云岩(A单元)主要由针状文石假...     

Biomarker geochemistry of marine organic matter in the Hushan and Chaohu areas,Lower Yangtze region

Marine strata are widely exposed in the Hushan and Chaohu areas, Lower Yangtze region. As biomarker geochemistry of the strata has not been well documented, this paper deals with the biomarker composition of representative samples collected from the Silurian, Carboniferous and Triassic systems and their geological implications, thus providing clues to marine organic matter. On the basis of experimental results, it is shown that abundant biomarkers (e.g. n-alkanes, isoprenoids, terpanes and steranes) were detected. As organic matter in the strata is highly to over mature in general based on petrologic microobservation, some biomarkers (mainly n-alkanes) except terpanes and steranes cannot reflect the source, depositional environment and maturity of organic matter. Thus, primarily based on analyses of the terpanes and steranes, it is suggested that organic matter in the Silurian and Carboniferous strata is derived mainly from lower organisms, while higher plants are predominant in the Triassic organic matter. This further indicates that the depositional environment may have transformed from the marine to continental facies in the Late Triassic. These results provide new evidence for the study of regional depositional evolution, and have enriched the study of biological composition of organic matter. In addition, the biomarker geochemistry of organic matter at high to over maturation stage is addressed.     

海相、陆相油气及其成因概述

国外油气主要在海相地层中发现,而中国油气主要在陆相地层中找到,根本原因在于地层形成顺序两者相反,前者浅层以海相为主,后者浅层则以陆相为主,大量油气是通过壳深断裂从深部垂直向上运移所形成,储集于浅部的首先被勘探开发。中国海相油气勘探中面临三大问题:(1)海相碳酸盐岩的有机碳含量均很低,难以形成大规模的烃源岩;(2)无法解决碳酸盐岩中的油气运移问题;(3)一些海相地层油气田的油气来源存在争议。共可归纳出三种油气生成模式,即壳源有机质、壳—幔相互作用以及费-托合成。目前人们过于执着于壳源有机质生成,而对费-托合成模式还没有足够认识和重视,这种思维定势阻碍了油气勘探在理论和实践上的进一步发展。大量油气是在地幔深部通过费-托合成或在地壳深部通过壳—幔相互作用形成,并沿深大断裂向上运移,除了浅部有大量聚集,在地壳深部的花岗岩、火山岩、变质岩等基岩中,在我国深部的海相地层和国外深部的陆相地层中同样可以大量聚集。     

Correlation and migration studies of North Central Sumatra oils

The Central Sumatra Basin (CSB) is a prolific petroleum-producing basin and its petroleum systems have been extensively studied. The widely occurring Tertiary lacustrine shale, Brown Shale, has long been recognized as the main source rock for tens of billions of barrels of oil in place. The oils produced from different fields display significant variation in source characteristics that have been attributed to variation in source facies. Despite this generalized recognition of the oil source, the links between major oil accumulations and many possible source kitchens throughout the basin have not been established as detailed oil-source correlation, and oil migration routes are not well defined. For continued exploration in the region, detailed genetic grouping and migration routes of the oils were evaluated through geochemical characterization of numerous oils from various fields in the northern part of Central Sumatra. Biomarker and carbon isotopic data indicate that the oils are quite similar geochemically but form several genetic groups on the basis of subtle but persistent differences in source facies. The groupings appear geographically meaningful and show association of the different oil groups with various troughs. Carbazole distributions show consistency in suggesting differences in relative migration distance among the oils within each genetic group. By combining the oil grouping and carbazole distributions with geological data, models of migration directions and pathways for oils in North Central Sumatra have been constructed.     

焉耆盆地侏罗纪煤系源岩显微组分组合与生油潜力

焉耆盆地为我国西部含煤、含油气盆地, 侏罗系含煤地层是最重要的潜在源岩.对侏罗纪煤系中的暗色泥岩、碳质泥岩和煤层分别进行了有机岩石学、Rock-Eval热解分析和核磁共振分析.泥岩、碳质泥岩和煤层具有不同的有机岩石学和有机地球化学特征, 其中煤层具有3种有机显微组分组合类型, 不同显微组分组合类型的煤层具有不同的生油、生气潜力或倾油、倾气性.基质镜质体、角质体、孢子体等显微组分是煤中的主要生烃组分.侏罗系泥岩、碳质泥岩和煤层具有不同的生物标志物分布特征, 生物标志物组合分析表明焉耆盆地已发现原油是泥岩、碳质泥岩和煤层生成原油的混合产物.含煤地层的地球化学生烃潜力分析和已发现原油的油源对比均表明, 含煤地层不仅是重要的气源岩, 而且可成为有效的油源岩.      

青海柴达木盆地南八仙油气田油源与成藏机理

柴达木盆地南八仙油气田不同油气藏间原油性质特征变化明显,油层在纵向井段上分布范围逾3000余m。通过地球化学实验并结合构造等地质条件分析,认为该区各种深、浅层油气藏中的原油具有煤成烃的基本地球化学特征,并且为同一来源,油源为临近地区较深部位中侏罗统煤系地层;该区深、浅层原油物性间的差异也反映在地球化学指标上,其成因或成藏机理是：深部早期油藏在断裂等地质作用下发生了明显的蒸发分馏作用,其分馏出的产物在浅部再次聚集成藏。     

渤海东部潮流沉积特征及MIS4以来的沉积环境演化

渤海东部发育了典型的潮流沉积,由老铁山水道冲刷槽、辽东浅滩沙脊和渤中浅滩沙席组成。该文基于中国海洋地 质调查最新获取的高分辨率单道地震数据,与水深变化进行对比,将该区的潮流沉积特征与其地震相特征进行精细分析, 同时结合晚第四纪CD5孔的岩性、14C测年和层序地层划分,识别出晚更新世以来的四期层序地层,分别是MIS4以细砂为 主的陆相地层、MIS3以粉砂和黏土为主的滨浅海相沉积地层、MIS2末次盛冰期形成的以粉砂质粘土和细砂质粉砂为主的陆 相沉积地层和全新世（MIS1） 发育的以粉砂质黏土和细砂组成的海相沉积地层。其中全新世地层分别由早期的滨海相沉 积、中期的浅海沉积和晚期的潮流沉积组成。通过这四期层序的研究,揭示了该区MIS4期以来的沉积环境演化。     

Hydrocarbon genesis of Jurassic coal measures in the Turpan Basin, China

A typical case of coal-derived oils in China, i.e. the crude oils from the Middle-Lower Jurassic coal measure strata in the Turpan Basin, is presented. By means of oil-source correlation, it is confirmed that low maturity crude oil in the Shengjinkou oil field is derived from the coal-bearing Qiketai Formation of Middle Jurassic age, a brackish lacustrine sediment. Mature crude oils in the Qiketai oil field, and in well Taican 1, are sourced from the Badaowan Formation of Lower Jurassic age, which contains coal seams as thick as 100 m. Results show that commercial accumulations of liquid crude oils can be generated from coals and coal measure strata containing high volatile coal of bituminous rank. Despite unfavourable types of source material, the total hydrocarbon-generating potential can be great due to the unusual abundance of organic matter.