OILS FROM CENOZOIC RIFT-BASINS IN CENTRAL AND NORTHERN THAILAND: SOURCE AND THERMAL MATURITY

Oil is produced from the Suphan Buri, Phitsanulok and Fang Basins onshore central and northern Thailand. Most of the Cenozoic rift‐basins onshore Thailand are 2–4 km deep, but the Phitsanulok Basin is the deepest with a basin‐fill up to 8 km thick. In this basin, the Sirikit field produces ～18,000–24,000 bbl/day of crude oil. In the Suphan Buri Basin, about 400 bbl/day of crude oil is produced from the U Thong and Sang Kajai fields. Approximately 800 bbl/day of crude oil is produced from the Fang field (Fang Basin), which in reality consists of a number of minor structures including Ban Thi, Pong Nok, San Sai, Nong Yao and Mae Soon. A total of eight oil samples were collected from these structures and from the Sirikit, U Thong and Sang Kajai fields. The oils were subjected to MPLC and HPLC separation and were analysed by gas chromatography (GC) and gas chromatography‐mass spectrometry (GC‐MS and GC‐MS‐MS). The U Thong oil was investigated in more detail by separating the oil into a number of fractions suited for the analysis of various specific compounds. The Sirikit oil appears to be the most mature, whereas the Suphan Buri oils and the oil from the San Sai structure (Fang Basin) are the least mature. Apart from the San Sai oil, the other oils in the Fang Basin are of similar maturity. The oils contain small amounts of asphaltenes and the asphaltene‐free fractions are completely dominated by saturated hydrocarbons (generally >60%). Long‐chain n‐alkanes extend to at least C₄₀ and the oils are thus highly waxy. In general the oils were generated from freshwater lacustrine source rocks containing a large proportion of algal material, as indicated by the presence of long‐chain n‐alkanes, low C₃₁22R/C₃₀ hopane ratios, the presence of 28‐Nor‐spergulane, T26/T25 (tricyclic triterpanes) ratios of 1.07–1.57 and tetracyclic polyprenoid (TTP) ratios close to 1. Occasional saline conditions may have occurred during deposition of the Sirikit, Ban Thi and Pong Nok source rocks. The Fang Basin oils were sourced from two different kitchens, one feeding the Ban Thi and Pong Nok structures and one feeding the Mae Soon, Nong Yao and San Sai structures. The presence ofcadalene, tetracyclic C₂₄ compounds, oleanane, lupane, bicadinane and trace amounts ofnorpimarane or norisopimarane indicate a contribution from higher land plant organic matter to the oils. The terrestrial organic matter may occur disseminated in the lacustrine facies or concentrated in coal seams associated with the lacustrine mudstones. Thermally immature oil shales (lacustrine mudstones) and coals exposed in numerous basins in central and northern Thailand could upon maturation generate oils with a composition comparable to the investigated oils.     

BIOMARKER CHARACTERISTICS OF CRUDE OILS FROM THE MURZUQ BASIN,SW LIBYA

Twenty crude oil samples from the Murzuq Basin, SW Libya (A‐, R‐ and I‐Fields in Blocks NC115 and NC186) have been investigated by a variety of organic geochemical methods. Based on biomarker distributions (e.g. n‐alkanes, isoprenoids, terpanes and steranes), the source of the oils is interpreted to be composed of mixed marine/terrigenous organic matter. The values of the Pr/Ph ratio (1.36–2.1), C₃₀‐diahopane / C₂₉ Ts ratio and diasterane / sterane ratio, together with the low values of the C₂₉/ C₃₀‐hopane ratio and the cross‐plot of the dibenzothiophene/phenanthrene ratio (DBT/P) versus Pr/Ph ratio in most of oil samples, suggest that the oils were sourced from marine clay‐rich sediments deposited in mild anoxic depositional environments. Assessment of thermal maturity based on phenanthrenes, aromatic steroids (e.g. monoaromatic (MA) and triaromatic (TA) steroid hydrocarbons), together with terpanes, and diasterane/sterane ratios, indicates that crude oils from A‐Field are at high levels of thermal maturity, while oils from Rand I‐Fields are at intermediate levels of thermal maturity. Based on the distributions of n‐alkanes and the absence of 25‐norhopanes in all of the crude oils analysed, none of the oils appear to have been biodegraded. Correlation of the crude oils points to a single genetic family and this is supported by the stable carbon isotope values. The oils can be divided into two sub‐families based on the differences in maturities, as shown in a Pr/nC₁₇ versus Ph/nC₁₈ cross‐plot. Sub‐family‐A is represented by the highly mature oils from A‐Field. Sub‐family‐B comprises the less mature oils from R‐ and I‐Fields. The two sub‐families may represent different source kitchens of different thermal maturity or different migration pathways. In summary, the geochemical characteristics of oil samples from A‐, R‐, and I‐Fields suggest that all the crude oils were generated from similar source rocks. Depositional environment conditions and advanced thermal maturities of these oils are consistent with previously published geochemical interpretations of the Rhuddanian “hot shale” in the Tanezzuft Formation, which is thought to be the main source rock in the Murzuq Basin.     

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.     

GEOCHEMISTRY OF CRUDE OILS,SEEPAGE OILS AND SOURCE ROCKS FROM BELIZE AND GUATEMALA: INDICATIONS OF CARBONATE‐SOURCED PETROLEUM SYSTEMS

This study reviews the stratigraphy and the poorly documented petroleum geology of the Belize‐Guatemala area in northern Central America. Guatemala is divided by the east‐west trending La Libertad arch into the North and South Petén Basins. The arch is the westward continuation of the Maya Mountains fault block in central Belize which separates the Corozal Basin in northern Belize from the Belize Basin to the south. Numerous petroleum seeps have been reported in both of these basins. Small‐scale oil production takes place in the Corozal Basin and the North and South Petén Basins. For this study, samples of crude oil, seepage oil and potential source rocks were collected from both countries and were investigated by organic geochemical analyses and microscopy. The oil samples consisted of non‐biodegraded crude oils and slightly to severely biodegraded seepage oils, both of which were generated from source rocks with similar thermal maturities. The crude oils were generated from marine carbonate source rocks and could be divided into three groups: Group 1 oils come from the North Petén Basin (Guatemala) and the western part of the Corozal Basin (Belize), and have a typical carbonate‐sourced geochemical composition. The oils correlate with extracts of organic‐rich limestones assigned to the Upper Cretaceous “Xan horizon” in the Xan oilfield in the North Petén Basin. The oils were generated from a single source facies in the North Petén Basin, but were charged from two different sub‐basins. Group 2 oils comprise crudes from the South Petén Basin. They have characteristics typical of carbonate‐sourced oils, but these characteristics are less pronounced than those of Group 1 oils. A mixed marine/lacustrine source facies deposited under strongly reducing conditions in a local kitchen area is inferred. Group 3 oils come from the Corozal Basin, Belize. A carbonate but also a more “shaly” source rock composition for these oils is inferred. A severely biodegraded seepage oil from Belmopan, the capital of Belize, resembles a nearby crude oil. The eastern sub‐basin in the North Petén Basin may potentially be the kitchen area for these oils, and for the seepage oils found in the western part of the Corozal Basin. The seepage oils from the Corozal and Belize Basins are moderately to severely biodegraded and were generated from carbonate source rocks. Some of the seepage oils have identical C_27–29 sterane distributions to the Group 2 oils, but “biodegradation insensitive” biomarker ratios show that the seepage oils can be divided into separate sub‐groups. Severely and slightly biodegraded seepage oils in the Belize Basin were probably almost identical prior to biodegradation. Lower Cretaceous limestones from the Belize Basin have petroleum generation potential, but the samples are immature. The kitchen for the seepage oils in the Belize Basin remains unknown.     

THE MIDDLE CAMBRIAN SUCCESSION IN THE CENTRAL BALTIC BASIN: GEOCHEMISTRY OF OILS AND SANDSTONE RESERVOIR CHARACTERISTICS

Some 36 oilfields, all producing from Middle Cambrian (Deimena Group) sandstones, are located in the central Baltic Basin in an area covering onshore Lithuania and Kaliningrad (Russia) and the adjacent offshore. This paper presents new data on the composition of crude oils from fields in this area and reviews the reservoir properties of the Deimena Group sandstones. Twenty‐one crude oil samples from fields in Lithuania and Kaliningrad were analysed by standard techniques including GC and GC‐MS. The oils had densities of 790.5 to 870.0 kg/m³, and had low asphaltene (<2.2%) and sulphur (<0.44%) contents. The gasoline fraction (b.p. >200°C) ranged from 12–34%. The saturated hydrocarbon content was 35.3 to 77.8%, and the ratio of saturate to aromatic hydrocarbons was 2.1–5.2, indicating long‐distance migration or high thermal maturities. GC analyses of saturate fractions indicated a composition dominated by n‐alkanes with a maximum at C₁₃–C₁₅ and reduced abundance in the C₂₀–C₃₅ range. The analysed crude oil samples are characterized by relatively low concentrations of steranes and triterpanes. Biomarker data indicated an algal origin for the precursor organic matter and a clastic‐dominated source rock. Sterane isomerization ratios imply that the oils are in general relatively mature. Exceptions are samples from the Juzno Olempijskoye and Deiminskoye fields, Kaliningrad, which were early mature. Oil from well Gondinga‐l (Lithuania) was lightly fractionally evaporated and has a relatively higher density, higher viscosity, higher asphaltene content and lower content of saturated fractions. Stable carbon isotope ratios of crude oils and saturated and aromatic fractions were analysed. Whole oils showed little carbon isotope variation, but there were significant differences in δ¹³C ratios for saturated and aromatic fractions. The geochemical data show differences in oil sourcing and indicate the possible existence of different kitchen areas in the Kaliningrad region. Vertical and lateral variations in Deimena Group reservoir properties are controlled by variations in quartz cementation. In fields in western Lithuania, sandstone porosity ranges from 0.7 to 20% and permeability from 20 mD to 300 mD; in fields onshore Kaliningrad, porosity is up to 34% and gas permeability up to 4.8 D. Wide variations in porosity and permeability occur at a field scale.     

Distribution and geochemical significance of phenylphenanthrenes and their isomers in selected oils and rock extracts from the Tarim Basin,NW China

Twenty-two oil samples and eight source rock samples collected from the Tarim Basin,NW China were geochemically analyzed to investigate the occurrence and distribution of phenylphenanthrene(PhP),phenylanthracene(PhA),and binaphthyl(BiN) isomers and methylphenanthrene(MP) isomers in oils and rock extracts with different depositional environments.Phenylphenanthrenes are present in significant abundance in Mesozoic lacustrine mudstones and related oils.The relative concentrations of PhPs are quite low or below detection limit by routine gas chromatography-mass spectrometry(GC-MS) in Ordovician oils derived from marine carbonates.The ratio of 3-PhP/3-MP was used in this study to describe the relative abundance of phenylphenanthrenes to their alkylated counterparts-methylphenanthrenes.The Ordovician oils in the Tabei Uplifthave quite low 3-PhP/3-MP ratios(0.10),indicating their marine carbonate origin,associating with low Pr/Ph ratios(pristane/phytane),high ADBT/ADBF values(relative abundance of alkylated dibenzothiophenes to alkylated dibenzofurans),low C_(30) diahopane/C_(30)hopane ratios,and low Ts/(Ts+Tm)(18α-22,29,30-trisnorneohopane/(18α-22,29,30-trisnorneohopane+17α-22,29,30-trisnorhopane)) values.In contrast,the oils from Mesozoic and Paleogene sandstone reservoirs and related Mesozoic lacustrine mudstones have relatively higher 3-PhP/3-MP ratios(0.10),associating with high Pr/Pli,low ADBT/ADBF.high Ts/(Ts + Tm).and C_(30) diahopane/C_(30) hopane ratios.Therefore,the occuirence of significant amounts of phenylphenanthreiies in oils typically indicates that the organic matter of the source rocks was deposited in a suboxic environment with mudstone deposition.The phenylphenanthreiies may be effective molecular markers,indicating depositional environment and lithology of source rocks.     

BIOMARKER GEOCHEMISTRY OF PALEOGENE CRUDE OILS AND SOURCE ROCKS FROM THE RAOYANG SAG,BOHAI BAY BASIN,NE CHINA: AN OIL – SOURCE ROCK CORRELATION STUDY

This study presents a systematic geochemical analysis of Paleogene crude oils and source rocks from the Raoyang Sag in the Jizhong sub-basin of the Bohai Bay Basin (NE China). The geochemical characteristics of fifty-three oil samples from wells in four sub-sags were analysed using gas chromatography (GC) and gas chromatography – mass spectrometry (GC-MS). Twenty core samples of mudstones from Members 1 and 3 of the Eocene-Oligocene Shahejie Formation were investigated for total organic carbon (TOC) content and by Rock-Eval pyrolysis and GC-MS to study their geochemistry and hydrocarbon generation potential. The oils were tentatively correlated to the source rocks. The results show that three groups of crude oils can be identified. Group I oils are characterized by high values of the gammacerane index and low values of the ratios of Pr/Ph, Ts/Tm, 20S/(20S+20R) C₂₉ steranes, ββ/(ββ+αα) C₂₉ steranes, C₂₇ diasteranes/ C₂₇ regular steranes and C₂₇/C₂₉ steranes. These oils have the lowest maturity and are interpreted to have originated from a source rock containing mixed organic matter deposited in an anoxic saline lacustrine environment. The biomarker parameter values of Group III oils are the opposite to those in Group I, and are interpreted to indicate a highly mature, terrigenous organic matter input into source rocks which were deposited in suboxic to anoxic freshwater lacustrine conditions. The parameter values of Group II oils are between those of the oils in Groups I and III, and are interpreted to indicate that the oils were generated from mixed organic matter in source rocks deposited in an anoxic brackish–saline or saline lacustrine environment. The results of the source rock analyses show that samples from Member 1 of the Shahejie Formation were deposited in an anoxic, brackish – saline or saline lacustrine environment with mixed organic matter input and are of low maturity. Source rocks in Member 3 of the Shahejie Formation were deposited in a suboxic to anoxic, brackish – saline or freshwater lacustrine environment with a terrigenous organic matter input and are of higher maturity. Correlation between rock samples and crude oils indicates that Group I oils were probably derived from Member 1 source rocks, while Group III oils were more likely generated by Member 3 source rocks. The Group II oils with transitional characteristics are likely to have a mixed source from both sets of source rocks.     

ORGANIC GEOCHEMICAL CHARACTERIZATION AND SHALE GAS POTENTIAL OF THE PERMIAN BARREN MEASURES FORMATION,WEST BOKARO SUB‐BASIN,EASTERN INDIA

This study investigates the shale gas characteristics of the Permian Barren Measures Formation (Gondwana Supergroup) in the West Bokaro sub‐basin of the Damodar Valley Basin, eastern India. A total of 23 core shale samples collected from a borehole located in the western part of the sub‐basin were analysed using organic geochemical techniques and scanning electron microscopy. The samples are black carbonaceous shales composed chiefly of quartz, mica and clay minerals. Rock‐Eval pyrolysis data show that the analysed samples contain a mixture of Type II and Type III kerogen with TOC values of 2.7 to 6.2%. Rock‐Eval T_max values ranging from 443 to 452 °C correspond to calculated vitrinite reflectance of approximately 0.8–0.9%. A cross‐plot of hydrogen index versus T_max indicates that the samples have reached peak oil to wet gas maturities. A pristane/n‐C₁₇ versus phytane/n‐C₁₈ cross‐plot, together with biomarker parameters such as the dominance of C₂₉ over C₂₇ and C₂₈ steranes and high moretane/hopane ratios (0.22–0.51), demonstrate that the shale samples contain terrigenous organic matter deposited in a suboxic environment. Scanning electron microscopy images of shale samples show the presence of a complex, mostly intergranular pore network. Both micropores (>0.75μm) and nanopores (<0.75μm) were observed. Some pores are elongated and are associated with layer‐spaces in sheet silicate minerals; others are non‐elongated and irregular in shape. The organic geochemical parameters and the observed pore attributes suggest that the Barren Measures Formation has good shale gas potential.     

喀麦隆里奥—德雷盆地泥岩底辟构造与油气分布规律

里奥-德雷（Rio del Rey）盆地位于喀麦隆境内、尼日尔三角洲（Niger Delta）东北缘,油气资源十分丰富,已有30余年油气勘探开发历史。古新世以来发生的长期海退和三角洲沉积作用,形成了现今的里奥-德雷被动大陆边缘盆地,其主要发育3个地层单元,自下而上分别为阿卡塔（Akata）组、阿格巴达（Agbada）组和贝宁（Benin）组。在三角洲进积推进过程中,由于大陆边缘的重力作用和三角洲泥岩的塑性推覆作用,由陆向海、自北向南形成了3个构造区,即伸展构造区、泥岩底辟构造区和逆冲推覆构造区。其中,在泥岩底辟构造区形成了许多与泥岩底辟或泥岩脊相关的辟顶背斜、断背斜构造圈闭或辟边岩性遮挡圈闭,现今已发现的大型油气田主要与这些圈闭有关。同时,泥岩底辟的活动也形成了储集和运移方面的优势条件,促使油气在泥岩底辟构造区富集高产。因此,未来泥岩底辟构造区以及与泥岩底辟相关的圈闭仍然是里奥-德雷盆地进一步寻找勘探潜力的主要地区。      

IN‐RESERVOIR FRACTIONATION AND THE ACCUMULATION OF OIL AND CONDENSATES IN THE SURMA BASIN,NE BANGLADESH

Petroleum in the Surma basin, NE Bangladesh (part of the Bengal Basin) ranges from waxy crude oils to condensates. The origin and source rocks of these hydrocarbons were investigated based on the distributions of saturated and aromatic hydrocarbons in 20 oil samples from seven oil and gas fields. The relative compositions of pristane, phytane and adjacent n‐alkanes suggest that the source rock was deposited in a non‐marine setting. The abundance and similar distribution of biphenyls, cadalene and bicadinanes in most of the crude oils and condensates indicates a significant supply of higher‐plant derived organic matter to the source rocks. Maturity levels of the crude oils and condensates from the Surma basin correspond to calculated vitrinite reflectance (R_c) values of 1.0–1.3%, indicating hydrocarbon expulsion from the source rock at a comparatively high maturity level. The R_c values of oils from the Titas field in the southern margin of the Surma basin are relatively low (0.8–1.0%). Some oils were severely biodegraded. The similar distribution of diamondoid hydrocarbons in both biodegraded and non‐biodegraded oils indicated similar types of source rocks and similar maturity levels to those of oils from the Surma basin. The Oligocene Jenam Shale and/or underlying non‐marine deposits located at greater depths may be potential source rocks. The diversity of the petroleum in the Surma basin was likely due to evaporative fractionation, resulting in residual waxy oils and lighter condensates which subsequently underwent tertiary migration and re‐accumulation. Evaporative fractionation due to modification of the reservoir structure occurred during and after the Pliocene, when large‐scale tectonic deformation occurred in and around the Bengal Basin.     

HYDROCARBON POTENTIAL OF UPPER CRETACEOUS MARINE SOURCE ROCKS IN THE TERMIT BASIN,NIGER

Upper Cretaceous mudstones are the most important source rocks in the Termit Basin, SE Niger. For this study, 184 mudstone samples from the Santonian–Campanian Yogou Formation and the underlying Cenomanian–Coniacian Donga Formation from eight wells were analyzed on the basis of palaeontological, petrographical and geochemical data, the latter including the results of Rock‐Eval, biomarker and stable isotope analyses. Samples from the upper member of the Yogou Formation contain marine algae and ostracods together with freshwater algae (Pediastrum) and arenaceous foraminifera, indicating a shallow‐marine to paralic depositional environment with fresh‐ to brackish waters. Terrestrial pollen and spores are common and of high diversity, suggesting proximity to land. Samples from the lower member contain marine algae and ostracods and arenaceous foraminifera but without freshwater algae, indicating shallow‐marine and brackish‐water settings with less freshwater influence. The wide range of gammacerane index values, gammacerane/C₃₀ hopane (0.07–0.5) and Pr/Ph ratios (0.63–4.68) in samples from the upper member of the Yogou Formation suggest a low to moderately saline environment with oxic to anoxic conditions. In samples from the lower member, the narrower range of the gammacerane index (0.23～0.35) and Pr/Ph ratios (0.76–1.36) probably indicate a moderately saline environment with suboxic to relatively anoxic conditions. Petrographic analyses of the Yogou Formation samples show that organic matter is dominated by terrestrial higher plant material with vitrinite, inertinite and specific liptinites (sporinite, cutinite and resinite). Extracts are characterized by a dominance of C₂₉ steranes over C₂₇ and C₂₈ homologues. Results of pyrolysis and elemental analyses indicate that the organic matter is composed mainly of Type II kerogen grading to mixed Type II‐III and Type III material with poor to excellent petroleum potential. Mudstones from the upper member of the Yogou Formation have higher petroleum generation potential than those from the lower member. Mudstones in the Donga Formation are dominated by Type III organic matter with poor to fair petroleum generation potential. Geochemical parameters indicate that in terms of thermal maturity the Yogou Formations has reached or surpassed the early phase of oil generation. Samples have T_max values and 20S/(20S+20R) C₂₉ sterane ratios greater than 435°C and 0.35, respectively. 22S/(22S+22R) ratios of C₃₁ homohopanes range from 0.50 to 0.54. The results of this study will help to provide a better understanding of the hydrocarbon potential of Upper Cretaceous marine source rocks in the Termit Basin and also in coeval intracontinental rift basins such as the Tenere Basin (Niger), Bornu Basin (Nigeria) and Benue Trough (Nigeria).     

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.     

Oil-source correlation and the impact of oil-filling process on geochemical composition of the different states of oils in the Upper Triassic Chang 7 Formation,Ordos basin,China

Five crude oil samples from five wells and 33 oil-containing sandstone reservoir rock samples from six wells of Chang 7 sub-unit were systematically studied to determine hydrocarbons in these oil reservoirs whether are the mixtures of oil components derived from different source rocks or from the same source rock during oil filling process over geological times. Sequential extraction was applied to the oil-containing reservoir rocks to deserve the free and adsorbed oils. The distribution of alkanes, hopanes and steranes and the correlation diagram of Pr/n-C₁₇ versus Ph/n-C₁₈ show that these oil components and crude oils have similar parent materials. And on this basis we compared the thermal maturity of the crude oils, the free oils and adsorbed oils and found that the thermal maturity of these oils is different. The cross plot of C₂₉αα-20S/(20S+20R) versus C₂₉ββ/(αα+ ββ) and the correlation diagram of Pr/n-C₁₇ versus Ph/n-C₁₈ both show that the crude oils have highest thermal maturity, followed by the free oils and then the adsorbed oils. The ratios of ∑C₂₁^?/∑C₂₂⁺ for the crude oils and free oils are greater than the adsorbed oils, indicating the crude oils and free oils have suffered more thermal stress and extensive cracking than that of the adsorbed oils. These geochemical data reveal that hydrocarbons in these oil reservoirs and crude oils were derived from the same source rock with different thermal maturity over geological times.     

POTENTIAL PETROLEUM SOURCE ROCKS IN THE TERMIT BASIN,NIGER

Potential source rocks from wells in the Termit Basin, eastern Republic of Niger, have been analysed using standard organic geochemical techniques. Samples included organic‐rich shales of Oligocene, Eocene, Paleocene, Maastrichtian, Campanian and Santonian ages. TOC contents of up to 20.26%, Rock Eval S₂ values of up to 55.35 mg HC/g rock and HI values of up to 562 mg HC/g TOC suggest that most of the samples analysed have significant oil‐generating potential. Kerogen is predominantly Types II, III and II–III. Biomarker distributions were determined for selected samples. Gas chromatograms are characterized by a predominance of C₁₇– C₂₁ and C₂₇– C₂₉ n‐alkanes. Hopane distributions are characterized by 22S/(22S+22R) ratios for C₃₂ homohopanes ranging from 0.31 to 0.59. Gammacerane was present in Maastrichtian‐Campanian and Santonian samples. Sterane distributions are dominated by C₂₉ steranes which are higher than C₂₇ and C₂₈ homologues. Biomarker characteristics were combined with other geochemical parameters to interpret the oil‐generating potential of the samples, their probable depositional environments and their thermal maturity. Results indicate that the samples were in general deposited in marine to lacustrine environments and contain varying amounts of higher plant or bacterial organic matter. Thermal maturity varies from immature to the main oil generation phase. The results of this study will contribute to an improved understanding of the origin of the hydrocarbons which have been discovered in Niger, Chad and other rift basins in the Central African Rift System.     

OCCURRENCE AND DISTRIBUTION OF n-ALKANESAND n-FATTY ACIDS IN SAUDI ARABIAN CRUDE OILS

ABSTRACT

Ten crude oil samples, covering wide range of maturity (API gravity = 18·5–36·1), were assembled from Safaniya, Abqiq, Ain Dar, Wafra. Marjan and Zuluf oil fields in the area of Arabian Gulf. n-Alkanes of were separated from the petroleum distillate ((150°C–450°C) of the crude oils by urea adduction. n-Fatty acids were separated from the fraction of n-alkanes by treatment with aqueous solution of KOH. Distribution of n-alkanes and n-fatty acids has been investigated by means of gas chromatography. The studied crude oils showed symmetrical distribution curves of n-paraffins and fatty acids of low molecular weight were abundant as compared with n-paraffins. The n-paraffins distribution curve of Wafra/Iucene biodegraded immature crude oil showed three maxima at C₁₇, C₁₉, and C₃₁ whereas the maxima of n-fatty acids are located at C₁₄,C₂₂and C₂₄. The results were interpreted in terms of origin, maturation and depositional environments of the crude oils.     

LOWER CARBONIFEROUS SHALES IN THE EASTERN TAURIDE BELT,SOUTHERN TURKEY: SOURCE ROCK CHARACTERISTICS

Lower Carboniferous (Tournaisian‐Visean) shales, sandstones and limestones are exposed at the surface in autochthonous units in the Eastern Taurides, southern Turkey. This study investigates the organic geochemical characteristics, thermal maturity and depositional environments of shale samples from two outcrop locations in this area (Belen and Naltas). The total organic carbon (TOC) contents range from 0.11 to 5.61 wt % for the Belen samples and 0.04 to 1.74 wt % for the Naltas samples. T_max values ranging from 432–467 °C indicate that the samples are in the oil generation window T_max and are thermally mature. Rock‐Eval pyrolysis data indicate that the organic matter in the shales is composed mainly of Type II and III kerogen. Solvent extract analyses of the samples show a unimodal n‐alkane distribution with a predominance of low carbon number (C₁₃‐C₂₀) n‐alkanes. Pr/Ph ratios and CPI values range from 1.57–1.66 and 1.08–1.11, respectively Pr/n‐C₁₇ and Ph/n‐C₁₈ ratios also indicate that the shales consist of mixed Type II/III organic matter. Sterane distributions are C₂₇>C₂₉>C₂₈ as determined by the sum of normal and isosteranes, suggesting marine depositional conditions 20S/(20S+20R) and ββ (ββ+αα) C₂₉ sterane ratios range from 0.51–0.54 and 0.53–0.57, respectively. These values are high and 20S/(20S+20R) sterane isomerisation has reached equilibrium values. Tricyclic terpanes are abundant on m/z 191 mass chromatograms and C₂₃ tricyclic terpanes are the dominant peak, which indicates a marine depositional setting. C₂₉ norhopane has a higher concentration than C₃₀ hopane, and C₃₀ diahopane and C₂₉Ts are present in all the samples. Ts and Tm were recorded in similar abundances. Moretane/hopane ratios are very low. 22S homohopanes are dominant over 22R homohopanes, and the C₃₂ 22S/(22R + 22S) C₃₂ homohopane ratios are between 0.58 and 0.59, indicating that homohopane isomerisation has reached equilibrium. C₃₁ homohopanes are dominant and the abundance of homohopanes decreases towards higher numbers. Although regional variations in the level of thermal maturity of Upper Palaeozoic sediments throughout the Taurus Belt region largely depend on burial depth, organic geochemical data indicate that the Lower Carboniferous shales in the eastern Taurus region (Naltas and Belen locations) have potential to generate hydrocarbons. These shales are thermally mature and have entered the oil generation window.     

GENETIC CLASSIFICATION OF OIL FAMILIES IN THE CENTRAL AND SOUTHERN SECTORS OF THE GULF OF SUEZ,EGYPT

The results of geochemical analyses were used to classify ten oil samples from six fields in the central and southern sectors of the Gulf of Suez, Egypt. The samples were collected from sandstone pay‐zones ranging in age from Early Palaeozoic (Nubia‐C) to Miocene (Kareem Formation) at various present‐day depths. Molecular and stable isotope analyses indicate the presence of two genetic oil families (Families I and II) and suggest their probable source rocks. The biomarker characteristics of Family 1 oils include low Pr/Ph ratio, CPI < 1.0, depleted rearranged steranes, very low diahopane concentrations, high sulphur content, high metal content and V/Ni ratio, low oleanane index, abundance of gammacerane and C₂₇ steranes, and high relative abundance of homohopanes and C₃₀ 24‐n‐propylcholestanes. Source rock deposition took place under anoxic marine‐carbonate and hypersaline conditions. The NCR and NDR 24‐norcholestane ratios together with the presence of highly‐branched isoprenoids in this oil family are consistent with Upper Cretaceous – Lower Paleogene source rocks. These characteristics suggest that the Upper Cretaceous Duwi Formation/Brown Limestone or Lower Eocene Thebes Formation are the source rocks for the oils in this family, which occur in the central sector of the Gulf of Suez. Family II oils have geochemical characteristics that point to a mature source rock deposited in a weakly reducing or suboxic setting under normal salinity conditions. Abundant oleananes, high 24‐ to 27‐norcholestane ratios and abundant C₂₅ highly‐branched isoprenoids suggest a Paleogene source rock. The Lower Miocene Rudeis Formation is the best candidate to have generated these oils which occur in the southern sector of the Gulf of Suez.     

HYDROCARBON GENERATION POTENTIAL AND DEPOSITIONAL ENVIRONMENT OF SHALES IN THE CRETACEOUS NAPO FORMATION,EASTERN ORIENTE BASIN,ECUADOR

Marine shale samples from the Cretaceous (Albian‐Campanian) Napo Formation (n = 26) from six wells in the eastern Oriente Basin of Ecuador were analysed to evaluate their organic geochemical characteristics and petroleum generation potential. Geochemical analyses included measurements of total organic carbon (TOC) content, Rock‐Eval pyrolysis, pyrolysis — gas chromatography (Py—GC), gas chromatography — mass‐spectrometry (GC—MS), biomarker distributions and kerogen analysis by optical microscopy. Hydrocarbon accumulations in the eastern Oriente Basin are attributable to a single petroleum system, and oil and gas generated by Upper Cretaceous source rocks is trapped in reservoirs ranging in age from Early Cretaceous to Eocene. The shale samples analysed for this study came from the upper part of the Napo Formation T member (“Upper T”), the overlying B limestone, and the lower part of the U member (“Lower U”).The samples are rich in amorphous organic matter with TOC contents in the range 0.71–5.97 wt% and Rock‐Eval T_max values of 427–446°C. Kerogen in the B Limestone shales is oil‐prone Type II with δ¹³C of ?27.19 to ?27.45‰; whereas the Upper T and Lower U member samples contain Type II–III kerogen mixed with Type III (δ¹³C > ?26.30‰). The hydrocarbon yield (S₂) ranges from 0.68 to 40.92 mg HC/g rock (average: 12.61 mg HC/g rock). Hydrogen index (HI) values are 427–693 mg HC/g TOC for the B limestone samples, and 68–448 mg HC/g TOC for the Lower U and Upper T samples. The mean vitrinite reflectance is 0.56–0.79% R₀ for the B limestone samples and 0.40–0.60% R₀ for the Lower U and Upper T samples, indicating early to mid oil window maturity for the former and immature to early maturity for the latter. Microscopy shows that the shales studied contain abundant organic matter which is mainly amorphous or alginite of marine origin. Extracts of shale samples from the B limestone are characterized by low to medium molecular weight compounds (n‐C₁₄ to n‐C₂₀) and have a low Pr/Ph ratio (≈ 1.0), high phytane/n‐C₁₈ ratio (1.01–1.29), and dominant C₂₇ regular steranes. These biomarker parameters and the abundant amorphous organic matter indicate that the organic matter was derived from marine algal material and was deposited under anoxic conditions. By contrast, the extracts from the Lower U and Upper T shales contain medium to high molecular weight compounds (n‐C₂₅ to n‐C₃₁) and have a high Pr/ Ph ratio (>3.0), low phytane/n‐C₁₈ ratio (0.45–0.80) with dominant C₂₉ regular steranes, consistent with an origin from terrigenous higher plant material mixed with marine algae deposited under suboxic conditions. This is also indicated by the presence of mixed amorphous and structured organic matter. This new geochemical data suggests that the analysed shales from the Napo Formation, especially the shales from the B limestone which contain Type II kerogen, have significant hydrocarbon potential in the eastern part of the Oriente Basin. The data may help to explain the distribution of hydrocarbon reserves in the east of the Oriente Basin, and also assist with the prediction of non‐structural traps.     

Light hydrocarbon geochemistry of crude oils from Eastern Niger Delta

Abstract

Geochemical evaluation of oil samples from the eastern part of the Niger Delta divided into western, eastern, and central sections of the study area was carried out for the characterization of their light hydrocarbons content in order to correlate oils from different parts. The hydrocarbons in the oil samples were determined using gas chromatographic (GC) technique. The results obtained showed that CPI, Pr/Ph, Pr/nC₁₇, and Ph/nC₁₈ ratios ranged from 0.99–1.55, 2.19–4.79, 0.92–2.35, and 0.27–0.47, respectively. The Pr/nC₁₇ versus Ph/nC₁₈ plot showed that the oils were derived from terrestrial organic materials that were deposited under oxic to suboxic conditions. They are moderately matured with minimal effect of biodegradation on most of the oil samples although two of the oils showed relatively higher degradation. Both bivariate and multivariate plots of the light hydrocarbon ratios differentiated the western and central oils from the eastern oils. The classification of the oils into families was not based on origin but rather on post generative alterations that include reservoir conditions and possibly migration effects. The light hydrocarbon parameters identified can be used in the correlation tools.