Organic geochemistry investigations of crude oils from Bayoot oilfield in the Masila Basin,east Yemen and their implication for origin of organic matter and source-related type

Thirteen crude oil samples from fractured basement reservoir rocks in the Bayoot oilfield, Masila Basin were studied to describe oil characteristics and to provide information on the source of organic matter input and the genetic link between oils and their potential source rock in the basin. The bulk geochemical results of whole oil and gasoline hydrocarbons indicate that the Bayoot oils are normal crude oil, with high hydrocarbons of more than 60%. The hydrocarbons are dominated by normal, branched and cyclic alkanes a substantial of the light aromatic compounds, suggesting aliphatic oil-prone kerogen. The high abundant of normal, branched and cyclic alkanes also indicate that the Bayoot oils are not biodegradation oils.The biomarker distributions of isoprenoid, hopane, aromatic and sterane and their cross and triangular plots suggest that the Bayoot oils are grouped into one genetic family and were generated from marine clay-rich source rock that received mixed organic matter and deposited under suboxic conditions. The biomarker distributions of the Bayoot oils are consistent with those of the Late Jurassic Madbi source rock in the basin. Biomarker maturity and oil compositions data also indicate that the Bayoot oils were generated from mature source rock with peak oil-window maturity.     

SOURCE ROCK EVALUATION AND PETROLEUM GEOCHEMISTRY, OFFSHORE SW IRAN

Mesozoic and Tertiary source rocks and crude oils from six oilfields in the Persian (Arabian) Gulf (Hendijan, Bahrgansar, Abouzar, Nowruz, Dorood and Foroozan) were studied using a variety of organic-geochemical techniques. Biomarker characteristics were combined with other geochemical data to identify the source rocks which generated the oil in these fields and to reconstruct their depositional environments, and also to characterize the diagenetic and catagenic processes which have occurred. The analyzed oils show a wide range of densities (19 to 39° API) and high sulphur contents. They were generated by Type II-S organic matter; they are not biodegraded and their maturity level is generally low.
Two main oil groups were identified from statistical analysis and can be correlated with different source rocks using age-specific biomarkers and isotope data. Group 1 oils include those from the Hendijan, Bahrgansar and Abouzar fields and were probably generated by a mid-Cretaceous argillaceous source rock. Group 2 oils include those from the Nowruz, Dorood and Foroozan fields, and originated from Jurassic to Early Cretaceous carbonate-rich source rocks.     

ORGANIC GEOCHEMISTRY OF CRUDE OILS AND UPPER CRETACEOUS SOURCE ROCKS FROM CONCESSION 11, WEST SIRTE BASIN,LIBYA

This paper reports the results of Rock‐Eval pyrolysis and total organic carbon analysis of 46 core and cuttings samples from Upper Cretaceous potential source rocks from wells in the West Sirte Basin (Libya), together with stable carbon isotope (δ¹³C) and biomarker analyses of eight oil samples from the Paleocene – Eocene Farrud/Facha Members and of 14 source rock extracts. Oil samples were analysed for bulk (°API gravity and δ¹³C) properties and elemental (sulphur, nickel and vanadium) contents. Molecular compositions were analysed using liquid and gas chromatography, and quantitative biological marker investigations using gas chromatography – mass spectrometry for saturated hydrocarbon fractions, in order to classify the samples and to establish oil‐source correlations. Core and cuttings samples from the Upper Cretaceous Etel, Rachmat, Sirte and Kalash Formations have variable organic content and hydrocarbon generation potential. Based on organofacies variations, samples from the Sirte and Kalash Formations have the potential to generate oil and gas from Type II/III kerogen, whereas samples from the Etel and Rachmat Formations, and some of the Sirte Formation samples, have the potential to generate gas from the abundant Type III kerogen. Carbon isotope compositions for these samples suggest mixed marine and terrigenous organic matter in varying proportions. Consistent with this, the distribution of n‐alkanes, terpanes and steranes indicates source rock organofacies variations from Type II/III to III kerogen. The petroleum generation potential of these source rocks was controlled by variations in redox conditions during deposition together with variations in terrigenous organic matter input. Geochemical analyses suggest that all of the oil samples are of the same genetic type and originated from the same or similar source rock(s). Based on their bulk geochemical characteristics and biomarker compositions, the oil samples are interpreted to be derived from mixed aquatic algal/microbial and terrigenous organic matter. Weak salinity stratification and suboxic bottom‐water conditions which favoured the preservation of organic matter in the sediments are indicated by low sulphur contents and by low V/Ni and Pr/Ph ratios. The characteristics of the oils, including low Pr/Ph ratio, CPI ～l, similar ratios of C₂₇:C₂₈:C₂₉ ααα‐steranes, medium to high proportions of rearranged steranes, C₂₉ <C₃₀‐hopane, low Ts/Tm hopanes, low sulphur content and low V/Ni ratio, suggest a reducing depositional environment for the source rock, which was likely a marine shale. All of the oil samples show thermal maturity in the early phase of oil generation. Based on hierarchical cluster analysis of 16 source‐related biomarker and isotope ratios, four genetic groups of extracts and oils were defined. The relative concentrations of marine algal/microbial input and reducing conditions decrease in the order Group 4 > Group 3 > Group 2 > Group1. Oil – source rock correlation studies show that some of the Sirte and Kalash Formations extracts correlate with oils based on specific parameters such as DBT/P versus Pr/Ph, δ¹³C_saturates versus δ¹³C_aromatics, and gammacerane/hopane versus sterane/hopane.     

GEOCHEMISTRY AND ORIGIN OF UPPER CRETACEOUS OILS FROM THE TERMIT BASIN,NIGER

Crude oil samples (n = 16) from Upper Cretaceous reservoir rocks together with cuttings samples of Upper Cretaceous and Paleogene mudstone source rocks (n = 12) from wells in the Termit Basin were characterized by a variety of biomarker parameters using GC and GC‐MS techniques. Organic geochemical analyses of source rock samples from the Upper Cretaceous Yogou Formation demonstrate poor to excellent hydrocarbon generation potential; the samples are characterized by Type II kerogen grading to mixed Types II–III and III kerogen. The oil samples have pristane/phytane (Pr/Ph) ratios ranging from 0.73 to 1.27, low C₂₂/C₂₁ and high C₂₄/C₂₃ tricyclic terpane ratios, and values of the gammacerane index (gammacerane/C₃₀hopane) of 0.29–0.49, suggesting derivation from carbonate‐poor source rocks deposited under suboxic to anoxic and moderate to high salinity conditions. Relatively high C₂₉ sterane concentrations with C₂₉/C₂₇ sterane ratios ranging from 2.18–3.93 and low values of the regular steranes/17α(H)‐hopanes ratio suggest that the oils were mainly derived from kerogen dominated by terrigenous higher plant material. Both aromatic maturity parameters (MPI‐1, MPI‐2 and R_c) and C₂₉ sterane parameters (20S/(20S+20R) and ββ/ (αα + ββ)) suggest that the oils are early‐mature to mature. Oil‐to‐oil correlations suggest that the Upper Cretaceous oils belongs to the same genetic family. Parameters including the Pr/Ph ratio, gammacerane index and C₂₆/C₂₅ tricyclic terpanes, and similar positions on a sterane ternary plot, suggest that the Upper Cretaceous oils originated from Upper Cretaceous source rocks rather than from Paleogene source rocks. The Yogou Formation can therefore be considered as an effective source rock.     

Characterization and correlation of crude oils from some wells in the North Western Desert,Egypt

Characterization and correlation of crude oils from some wells in the North Western Desert, based on six crude oil samples, were studied by different analytical techniques, including API gravity, sulfur content, nickel and vanadium, bulk compositions and saturated fraction obtained from gas chromatography have been studied. The results show that the crude oils are normal to medium aromatic oils, with high API gravity and high sulfur content. V, Ni, V/Ni and V/(V + Ni) reflecting oils might be sourced from non-clastic source rocks, possibly carbonates, deposited under anoxic-suboxic conditions. Bulk compositions revealing that the crude oils were derived from marine organic sources. While, the paraffins and naphthenes percent indicates that the oils belong to paraffinic to naphthenic oil types, deposited in slightly anoxic to suboxic conditions and contained marine organic matter. Thermal maturity data showed that the oil samples were generated from mature source rocks. This indicates the studied oil samples are well correlated with each other, where they are similar in their oil type maturation and source depositional environments.     

SOURCE‐ROCK MATURITY,HYDROCARBON POTENTIAL AND OIL – SOURCE‐ROCK CORRELATION IN WELL SHORISH‐1, ERBIL PROVINCE,KURDISTAN REGION,IRAQ

The Shorish‐1 exploration well is located in Erbil Province in the Kurdistan region of Iraq, on the outskirts of Erbil City near the dividing line between the Low Folded and High Folded Zones of the Zagros foldbelt. The well penetrated rocks which are between Miocene and Late Triassic in age. The depositional environment, source potential and maturity of organic‐rich intervals within the well succession were investigated using 38 cuttings samples. All samples were analysed for bulk geochemical parameters (i.e. total organic carbon, total carbon, sulphur, Rock‐Eval). A subset of 13 samples was selected for biomarker analysis, pyrolysis – gas chromatography and isotope investigations. In addition non‐commercial oil and oil impregnations were investigated for oil‐source correlations. Source rocks occur in the Jurassic Sargelu and Naokelekan Formations and the lowermost Cretaceous Chia Gara Formation. Analytical results suggest that these source rocks were deposited in a carbonate‐rich, anoxic environment in an intrashelf basin setting with free H₂S in the water column. Oxygen‐depleted conditions were favoured by salinity stratification. The average preserved TOC contents of the 100 m thick Sargelu Formation and the 25 m thick Naokelekan Formation are 2.2% and 4.6%, respectively. The TOC content of the Chia Gara Formation decreases upwards and averages 3.2% within its lower 40 m. Very high sulphur contents suggest the presence of kerogen Type II‐S, and that all the formations have generated sulphur‐rich hydrocarbons at relatively low maturities. In contrast to the oil impregnations within Jurassic strata, the oil and the oil impregnations within Cretaceous rocks are heavily biodegraded. Oil biomarker and isotope data indicate generation from the above‐mentioned Jurassic and Cretaceous source rock formations. As a result, generation from Triassic and Paleogene rocks can be excluded or is of negligible significance. Numerical models show that hydrocarbon generation rates from the Sargelu, Naokelekan and Chia Gara Formations peaked firstly at about 55 Ma (Paleocene/Eocene) and then again at 5 Ma before present (late Miocene/Pliocene). The first peak resulted from increased Paleocene subsidence, and the second peak was related to deep late Miocene/Pliocene burial. Hydrocarbon generation ceased during Recent uplift, during which ～2000 m of the Late Neogene succession was eroded.     

SOURCE ROCK QUALITY VARIATIONS OF UPPER JURASSIC – LOWERMOST CRETACEOUS MARINE SHALES AND THEIR RELATIONSHIP TO OILS IN THE VALDEMAR FIELD,DANISH NORTH SEA

The main source rocks for the hydrocarbons at the Valdemar field (Danish North Sea) are the Upper Jurassic – lowermost Cretaceous organic-rich marine shales of the Farsund Formation. However, geochemical analyses of retained petroleum in reservoir cores show variations in oil type and maturity which indicate a complex charging history. This paper reviews the organofacies and source rock quality variations in 55 samples of the Farsund Formation from the North Jens-1 well (Valdemar field) within a sequence stratigraphic framework in order to discuss the source of the hydrocarbons. Petrographic and geochemical data, including biomarker analyses, were integrated in order to characterize the kerogen composition, original source rock potential and depositional environment of the Farsund Formation. The thermal maturity, source rock quality and kerogen quality all vary at the sequence level, and in general change upwards from early mature, primarily gas-prone Type II kerogen in the Kimmeridgian Kimm-2 and Kimm-3 sequences to immature, highly oil-prone sapropelic Type II kerogen in the Volg-4 and Ryaz-1 sequences (Volgian, Ryazanian). The kerogen has a maceral composition dominated by fluorescing amorphous organic matter (AOM) and liptodetrinite, with variable but generally minor amounts of terrigenous organic matter. The stratigraphic distribution of organic matter is similar to that in regional observations from the Danish Central Graben but minor differences occur, especially in the amount of fluorescing AOM in the Kimmeridgian sequences. The decrease in terrigenous input (vitrinite) upwards through the marine shale succession likely reflects a marine transgression of the Danish Central Graben area during Late Jurassic time. The source potential of the Upper Jurassic – lowermost Cretaceous shales in the North Jens-1 well is generally lower than that observed regionally, including an absence of relatively organic-rich, oil-prone intervals in the older part of the succession which have been demonstrated to occur elsewhere in the Danish Central Graben. However, in agreement with the regional trend, back-calculated source rock data and calculated Ultimate Expulsion Potentials show that the uppermost Volgian (Volg-4) and Ryazanian (Ryaz-1) sequences are the most oil-prone intervals. The Ryaz-1 sequence represents a condensed section formed during a period characterised by low sedimentation rates and high preservation of algal organic matter. Biomarker compositions from source rock extracts from the North Jens-1 well cannot be directly correlated to Valdemar reservoir oils, suggesting that the mature organofacies which charged the oils are not represented in the samples from North Jens-1.     

MULTIPLE PETROLEUM SYSTEMS IN TERTIARY EXTENSIONAL BASINS, EAST CHINA: A CASE STUDY OF THE GUNAN-FULIN BASIN

The Gunan-Fulin Basin, a small, extensional basin of Tertiary age, is located within the Shenglipetroleum "province" which structurally corresponds to the Jiyan megabasin in East China. The Lower Tertiary succession in the Gunan-Fulin Basin is dominated by the Eocene-lower Oligocene Shahejie Formation, which is divided into four members. Major source rocks are present in the Es3 Member (Eocene), and the Es 1 Member (Oligocene). Both units were deposited during lacustrine transgressions in the Early Tertiary. They are composed of dark, organic-rich mudstones and oil shales of lacustrine origin, and contain good quality Type I-II kerogen. The Es 1 source rock was deposited in a saline lake occasionally invaded by the sea, while the Es3 unit was laid down in a fresh-water lake.
The maturity and characteristics of these source rocks and the related crude oils can be distinguished on the basis of their biomarker contents. Es 1 source rocks and related oils are of relatively low maturity, while those of Es3 derivation are mature to highly-mature. There are therefore two separate petroleum systems in the Gunan-Fulin Basin — Eocene and Oligocene.
These petroleum systems are isolated hydraulically, and have independent migration pathways in which fault planes and unconformity surfaces play important roles. The distribution of oil accumulations in the two systems is different as a result of faulting. Oil from the Eocene source rocks is trapped in reservoirs which are distributed stratigraphically from the basement to the Tertiary, while oil from the Oligocene source rock is confined to Oligocene and Miocene reservoir rocks.
The existence of multiple petroleum systems is an important feature of Tertiary extensional basins in East China, and results from multiple phases of block faulting and a high geothermal gradient.     

南美Llanos盆地中部地区烃源岩与原油地球化学特征

南美Llanos盆地中部地区为盆地内的重要产油区,对其烃源岩及原油的地球化学特征分析,能揭示出盆地内的排烃和运聚过程及原油的生物降解特征。通过岩石热解、原油组分分析等方法和手段,结合多种生标参数,对这一地区的烃源岩及原油的地球化学特征进行了系统和全面的分析,结果表明:Gacheta组烃源岩沉积在较少的陆源有机质、咸水和弱氧化—弱还原环境,为腐泥—腐殖混合型干酪根;Los Cuervos组烃源岩沉积在较多的陆源有机质、半咸水和氧化环境,为腐泥—腐殖混合型和腐殖型干酪根,2套烃源岩都处于低—中等的成熟程度,均具有较强的生烃潜力;盆地中部地区存在A、B、C三类原油,其中A类为白垩系烃源岩油;B类为古近系烃源岩油;C类系前两者的混合;在大部分的油样中含有丰富的重排甾烷,二苯并噻吩/菲含量低,而Pr/Ph值较高,这说明原油对应的烃源岩为海相页岩而非碳酸盐岩;原油组分受生物降解及二次充注过程的控制,从Santiago油田沿北东方向到La Gloria等油田生物降解作用呈减弱的趋势,而Cupiagua和Buenos Aires油田的样品受二次充注的轻质油的影响,其API远远超过La Gloria等油田。     

Burial and thermal history simulation of the subsurface Paleozoic source rocks in Faghur basin,north Western Desert,Egypt: Implication for hydrocarbon generation and expulsion history

Paleozoic Zeitoun, Desouqy and Dhiffah formations represent source rocks to hydrocarbon in Faghur basin, north Western Desert, Egypt. They are characterized by a sufficient amount of organic matter belonging to kerogen type III and mixed type II/III, which are in maturation stage. A 1D-basin modeling was performed by using geological and geochemical data of the Paleozoic source rocks from five wells in Faghur basin, north Western Desert, Egypt. These data used in 1D basin modeling for constructing and understanding of burial and thermal geo-histories of Faghur basin and for simulating and predicting the timing of petroleum and expulsion for the Paleozoic source rocks in the studied wells. Burial and thermal history models indicate that the Zeitoun Formation entered onset of oil generation in the studied wells during Late Cretaceous (100.10–91.65 my) with transformation ratio (TR) 10–25, peak oil during Late Cretaceous (91.65–79.30 my) with TR 25–50 and late oil stage at Late Cretaceous (79.30 my-0) to present day with TR 50–60.45. Desouqy Formation entered onset of oil generation also during Late Cretaceous (94.43–73.60 my) with TR 10–25 in the studied wells, peak oil during Late cretaceous (73.60–62.40 my) with TR 25–50 and Late oil stage during Late Cretaceous to present day (62.40 my-0) with TR 50–61.82. Dhiffah Formation entered onset of oil generation in the studied wells during Early to Late Cretaceous (102.11–92.27 my) with TR 10–25, peak oil during Late Cretaceous (92.27–86.40 my) with TR 25–50 and late oil stage at Late Cretaceous to present day (86.40 my-0) with TR 50–67.27. No cracking oil to gas in the studied Paleozoic source rocks in the studied wells. These basin modeling results also suggest that the Paleozoic source rocks act as an effective source rock where a significant amount of petroleum is expected to be generated and expelled to any nearby prospect reservoir rocks in the Faghur basin.     

GEOCHEMICAL CHARACTERIZATION OF POTENTIAL JURASSIC/CRETACEOUS SOURCE ROCKS IN THE SHUSHAN BASIN, NORTHERN WESTERN DESERT, EGYPT

Some 180 core and cuttings samples of shales and limestones from the Middle Jurassic – Late Cretaceous succession (Khatatba, Masajid, Alam El-Bueib, Alamein, Kharita, Bahariya and Abu Roash Formations) were collected from wells Ja 27–2, Tarek-1 and Jb 26–1 in the central, structurally-low part of the Shushan Basin and from well Lotus-1 in the structurally-elevated western part of the basin. All samples were screened for total organic carbon (TOC) content. Selected samples were then analyzed by Rock-Eval pyrolysis, and extracted for biomarker analyses. Visual kerogen analysis and vitrinite reflectance measurements were also undertaken and oil - source rock correlations were attempted. The results indicate that the thermal maturity of the samples can be correlated closely with burial depth. Samples from the central part of the basin are more mature than those from the west. Samples from the central part of the basin (except those from the Albian Kharita Formation) have reached thermal maturities sufficient to generate and expel crude oils. Extracts from the Middle Jurasic Khatatba and Early Cretaceous Alam El-Bueib Formations can be correlated with a crude oil sample from well Ja 27–2.
In well Lotus-1 in the west of the basin, four distinct organic facies can be recognized in the Jurassic-Cretaceous interval. One of the facies ("facies 4") has a sufficiently high TOC content to act as a source rock. Thermal maturities range from immature to peak oil generation, and the top of the oil window occurs at approximately 8000 ft.     

Thermal modeling and hydrocarbon generation of the Late Jurassic-Early Cretaceous Chia Gara Formation in Iraqi Kurdistan region,northern Zagros Fold Belt

The Late Jurassic-Early Cretaceous Chia Gara Formation is an important oil-source rock in Iraqi Kurdistan region. Chia Gara source rock is characterised by high organic matter and sulphur content with Type II_S kerogen. 1D basin models were integrated with geological information and geochemical data from Chia Gara Fm at four well locations in Kurdistan region, northern Iraq. The models of the burial/thermal history indicate that Chia Gara Fm is presently in the peak-oil generation window and some oil cracked to gas during Late Eocene to Late Miocene time. Onset of oil-generation began during the Middle Paleocene- Early Oligocene (60–30?Ma). Oil was generated during the Late Eocene to Late Miocene (48–9 Ma). The models also suggest that the oil was expelled from Chia Gara source rock during the Late Eocene to Late Miocene (37–9 Ma), with a transformation ratio more than 50%. The high transformation ratio of more than 80% in two wells suggests that the generated oil was cracked to gas during the end of Middle Miocene time and continued to present day. The basin modeling results further suggest that Chia Gara Formation acts as a prolific petroleum-source rock and significant of oil and limited of gas have been generated and expelled to any nearby prospect reservoir rocks in the Kurdistan region.     

Oil: Source rock correlations of Al Baraka oil field,Komombo basin,South Egypt: An implication from biomarkers characteristics

The objectives of this study are the correlation between the oil samples recovered from the Lower Cretaceous reservoirs and Lower and Upper Cretaceous source rocks. The investigated biomarkers of five oils indicated the oils were derived from mixed marine and terrigenous (lacustrine) organic matter and deposited under suboxic to anoxic conditions. These oils were also generated from source rocks of high thermal maturity at the peak oil window. So, based on the molecular indicators of organic source input,depositional environment and maturity parameters of oils and extracts, we can conclude that the oil recovered from Al Baraka oil field were derived from Lower Cretaceous source rocks especially KomOmbo (B) source rocks where it reached the oil window. Furthermore, we can indicate that the other lower Cretaceous formations as Abu Ballas Formation will have the opportunity to generate and expel oil at the deeper part of the basin as shown in the eastern part of the basin.     

准噶尔盆地主要烃源岩生烃模拟实验及地质意义

对准噶尔盆地五大生烃岩系八套生烃层组的主要烃源岩进行了室内的热模拟实验。结果表明, 产烃率的变化取决于有机质类型和生源环境, 富氢源岩具有较高的产油率, 但产气率有别;强还原环境的富氢源岩可提前进入生烃门限, 生成低熟油;另外, 模拟产物液态烃和气态烃及干酪根随模拟温度的升高均发生不同的热分馏效应;模拟实验还再现了干酪根元素和各官能团的演化规律, 从而揭示了不同类型源岩的成烃机理。在此基础上, 提出除了在盆地范围内继续寻找与石炭—二叠系烃源岩有关的原生或次生油气藏和在盆地南缘寻找与三叠—侏罗系烃源岩有关的次生油气藏外, 南缘山前凹陷西侧下白垩统和下第三系具有生成低熟油气的地质地化条件应引起高度重视。     

松江盆地白垩系烃源岩地球化学特征及油源对比

松江盆地白垩系发育大砬子组和长财组两套烃源岩。通过对烃源岩及原油进行常规有机地化分析和生物标志化合物测试,研究了烃源岩和原油的地球化学特征并探讨油源关系。有机地化分析表明,其白垩系烃源岩有机质丰度高,Ⅱ₁-Ⅱ₂型有机质,低成熟-成熟。大砬子组烃源岩生烃潜力大,长财组次之。生物标志化合物分析表明,白垩系部分烃源岩和原油遭受了一定程度的生物降解作用。长财组烃源岩可分为3类,第Ⅰ和第Ⅱ类生烃母质以高等植物为主,为偏氧化的淡水和微咸水沉积,第Ⅲ类伽马蜡烷和β胡萝卜烷含量丰富,为咸水环境沉积。大砬子烃源岩为咸化的还原环境沉积,生烃母质为混合源。经油源对比表明,长财组下段原油来源于长财组第Ⅰ类烃源岩,长财组上段原油来源于第Ⅱ类烃源岩,而偏还原的大砬子组原油来源于大砬子组上段烃源岩。     

Hydrocarbon potentiality and thermal maturity of the Cretaceous rocks in Al Baraka oil field,KomOmbo basin,south Egypt

This paper aims to evaluate the hydrocarbon potentiality and thermal maturity of the Cretaceous source rocks in Al Baraka oil field in KomOmbo basin, south Egypt. To achieve this aim, geochemical analyses (TOC), Rock eval pyrolysis and vitrinite reflectance measurements (R0) were carried out on the studied rocks. The analytical results of the samples that were collected from five exploratory oil wells revealed that almost Lower Cretaceous formations (Sabaya, Abu Ballas, Six Hills and KomOmbo C, B, A) and Upper Cretaceous formations (Dakhla, Duwi, Quseir, Taref and Maghrabi) are ranged from fair to excellent source rocks for hydrocarbon generation. Oil and gas are mainly the future products of the thermally transformed organic matters within almost samples of the Cretaceous formations, where the Lower and Upper Cretaceous formations contain mixed type II/III and III kerogen besides type II kerogen in KomOmbo (B) and Dakhla formations. The thermal maturity parameters clarified that the Lower Cretaceous formations are belonged to marginally mature (in Sabaya and Abu Ballas formations), whereas the rocks of KomOmbo (B) Formation are mature source rocks and fall in the stage of oil generation and reach to the late stage of oil generation (R0?=?1.25). On the contrary the Upper Cretaceous formations are ranged from immature to marginally mature source rocks and reach only the early stage of oil generation in Maghrabi Formation. This study indicated that there is still a good chance to find oil generated from the Dakhla, Duwi, Maghrabi, Sabaya and Abu Ballas formations if buried in greater depths as well as, KomOmbo B and A intervals which are source rock potentials.     

Source Rock Characterization Within the Stratigraphic Settings of the Orange Basin,South Africa

abstract

The petroleum source rock potential of different system tracts of a Cretaceous unit of the Orange Basin, South Africa, was evaluated using Rock-Eval pyrolysis. Forty rock samples from eight wells were obtained within the systems tract, Lowstand System Tracts (LST), Transgressive System Tracts (TST), and Highstand System Tracts (HST), in the basin. The results revealed that LST is characterized by mainly marginally organic rich shale samples with a few organic rich rocks, variable organic matter types ranging from Type II to Type IV, and a few samples that are thermally mature but have low organic matter quality. Four samples from two wells (A_F1 and O_A1) in the LST had good petroleum generative potential but were not sufficiently mature for petroleum generation. TST is characterized with a few samples being marginally organic rich, with only one being organic rich, mainly Type III kerogen with few Type IV kerogen, and only a few samples are thermally mature that have low organic matter quality. HST is characterized by many marginally organic rich rock samples, mainly Type III with a few mixed Type II/III kerogen, and only a few samples were thermally mature. The results of this study show that the LST has the best prospect in terms of petroleum generation potential, followed by HST and TST in that order. The study also reveals that limited petroleum source rocks exist, which are also impacted by low thermal maturity levels. The basin is more gas prone than oil.     

SOURCE ROCK CHARACTERIZATION BASED ON BIOLOGICAL MARKER DISTRIBUTIONS OF CRUDE OILS IN THE SOUTHERN GULF OF SUEZ, EGYPT

The depositional environment and maturity of source rocks in the southern Gulf of Suez were evaluated using biomarker and isotope data from crude oils derived from a variety of source rock types of different geological ages. Two oils families were identified and are referred to as types A and B. Type A oils are characterized by a predominance of oleanane and relatively low gammacerane concentrations, suggesting that they were derived from a terrigenous source rock with a significant input of angiosperm material inferred to occur within the marginally-mature syn-rift Lower Miocene Rudeis Shale. By contrast, type B oils are distinguished by a predominance of gammacerane and relatively low oleanane concentrations, suggesting that they were generated from mature marine carbonate source rocks inferred to occur within the Upper Cretaceous Brown Limestone and Middle Eocene Thebes Formation. Maturity parameters including the sterane isomerisation ratios C ₂₉αββ/(αββ+ααα), C₂₉ααα20S/(S+R) and TAS/(TAS+MAS), together with aromatic sulphur compound ratios (4-MDBT / I-MDBT; 4,6- / 1,4-DMDBT; 2,4–/ 1,4-DMDBT; and DBT / phenanthrenes), support the higher thermal maturity of type B oils relative to type A oils.
The biomarker variablility reflects the occurrence of two distinct source rocks in the southern Gulf of Suez and suggests that two independent petroleum systems are present here. These appear to be confined to the pre-rift (pre-Miocene) and syn-rift megasequences respectively.     

鸡西盆地下白垩统煤系烃源岩生油潜力

应用有机地球化学的多种分析方法,对鸡西盆地下白垩统烃源岩的有机岩石学特征、有机质丰度、成熟度及有机质的类型进行了讨论。有机显微组分以壳质组为主,煤岩和碳质泥岩的镜质组含量较高;有机碳、热解氢指数I_H及产烃潜量(S₁+S₂)反映烃源岩达到中等—好的级别。有机质为Ⅲ型干酪根,部分Ⅱ_B型,镜质体反射率R_o主要集中于0.5%~1.1%.依据Ⅲ型干酪根的成烃模式,正处于产生液态烃的高峰期,具备生成油气的潜力。与典型的煤成油盆地如Gippsland盆地和吐哈盆地有很好的可比性,具有很好的油气勘探前景。