Tricyclic terpane geochemistry of source rocks from Northwestern and Central Niger Delta

This distribution of tricyclic terpanes in source rocks from the northwestern and central Niger Delta was used to evaluate their origin, depositional environment and thermal maturity. The rock samples were extracted using Soxhlet extraction method and the saturated hydrocarbon fraction was analysed for biomarkers using gas chromatography-mass spectrometry (GC-MS). The values of soluble organic matter (SOM) and total hydrocarbons for wells AW and OP source rock samples exceeded the minimum 500 ppm and 300 ppm, respectively with values indicating very good to excellent potential source rocks. The tricyclic terpane source parameters and the complementary distribution of hopanes, regular C₂₇-C₂₉ steranes, n-alkanes and acyclic isoprenoid hydrocarbons showed that samples from well AW consist of mixed marine/terrestrial organic matter while those from well OP consist of organic matter largely from terrestrial origin. The values of Pr/Ph ratio for source rock samples from wells AW and OP indicate deposition of the organic matter under suboxic conditions. Sterane and hopane biomarker maturity parameters indicated that the source rock samples from wells AW and OP are at onset of oil generation and main oil window, Most of the source rock samples from well AW are more thermally mature than those from well OP. The results of tricyclic terpane maturity parameters indicated low thermal maturity for the rock samples from both wells with samples from well AW more thermally mature than those from well OP.     

Preliminary hydrocarbon analysis of crude oils from Umutu/Bomu fields,south west Niger Delta Nigeria

Seven different crude oil samples were collected from two oil fields in the Niger Delta Nigeria. The bulk properties of these crude oils which include API gravity, reid vapour pressure; kinematic viscosity, dynamic viscosity, moisture, gum content and cloud point were analysed. Aliphatic biomarkers were used as supporting tool to deduce the geochemical characteristics such as thermal maturity, depositional environments, source of organic matter and extent of biodegradation. Results show that API° gravity ranged from 29.00° to 85.00°, specific gravity 0.65 to 0.88, 3.00 to 9.00, reid vapour pressure 3.00 to 9.00 kPa, kinematic viscosity 0.90 to 10.10 cSt, dynamic viscosity 0.70 to 8.90 cP, moisture content 0.13% to 26.00%, gum content 6.27 to 45.84 mg/L, cloud point 3.00 to 12.00 °C, pour point ?7.00 to 4.00 °C and flash point <30.00 °C. Distribution of n-alkanes (Pr/Ph, and isoprenoide/n-alkanes ratios) reflects that the oil samples originated mainly from terrestrial organic sources deposited in an oxic paleoenvironment.     

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 geochemistry of Gadvan and Kazhdumi formations (Cretaceous) in South Pars field,Persian Gulf,Iran

In Southern Iran, Gadvan (Barremian-early Aptian) and Kazhdumi (Albian) formations are the most effective source rocks and have produced the majority of hydrocarbons reserved in the Zagros Basin especially in Dezful Embayment and Persian Gulf area. In this article, hydrocarbon potential of Gadvan and Kazhdumi formations is investigated in the South Pars field which is southern extension of the North field of Qatar Country. This field is located in Persian Gulf waters and is actually the northern extension of Qatar Arc Paleohigh where geological history of Gadvan and Kazhdumi formations is different from nearby area regarding depositional setting, burial history and source rock maturity.In this study, Gadvan and Kazhdumi formations as source rock candidates, which underlay Upper Dariyan and Mauddud members, respectively, were sampled in two drilled wells of the South Pars field for routine geochemical analysis to investigate hydrocarbon potential of these formations and source rock identification of trapped oil in the Upper Dariyan and Mauddud members. Several samples from top to the bottom of the formations were taken and analyzed by Rock-Eval pyrolysis. The average TOC content of Gadvan and Kazhdumi formations is 0.79 wt. % and 0.49 wt. %, respectively. Rock-Eval results (e.g. HI vs. Tmax) represent that TOC content of these formations contains type II-III kerogens which haven't suffered sufficient thermal maturity (Ro < 0.5%) in this study area. Moreover calculated S2/S3 ratio implies that these formations in central part of Qatar Arc, South Pars field couldn't produce noticeable liquid hydrocarbon.As it is believed, Gadvan and Kazhdumi formations to be source of trapped oil in the system, therefore, in the South Pars field reserved hydrocarbon in Upper Dariyan (Aptian) and Mauddud (late Albian) members which overlie Gadvan and Kazhdumi formations, respectively, are probably generated from Gadvan and Kazhdumi formations of the nearby through and flanks of the Qatar Arc where the burial depth and temperature increase then generated hydrocarbons in downdip area are migrated to the upper carbonate reservoirs in the crest part of the Qatar Arc. Long path migration of the hydrocarbon and source rock with lower organic matter are caused hydrocarbon accumulation in the South Pars Oil Layer (Al-Shaheen) which is approved by professional petrophysical and geological studies of the field.     

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.     

Petroleum that has migrated into an outcropping of the Jurassic Ayad Salt Dome of Shabwah depression,Yemen

Two oil seep samples were collected from outcropping Jurassic Ayad Salt Dome of Shabwah depression. The results of this study have been used to provide information of the origin of the oil seeps and the type of organic matter and maturity of their potential source rock in the basin. Although these are surface oil seeps, their high saturated hydrocarbon content indicates that they are non-degraded oils, probably due to an arid environment of the thick salt sediments. The analyzed oil seep samples are characterized by full complement of n-alkanes, a very high component of phytane, relatively low CPIs of less than unity, and an unusually high content of aliphatic HCs. These features suggest that the analyzed oil seeps are generated from an algal marine organic matter in the source rock that deposited under highly anoxic hypersaline conditions and indicate a moderately low level of maturity. The geochemical characteristics of the analyzed oil seeps in this study are similar and consistent with the source rock characteristics of the Safer Member in the Sabatayn Basin.     

十万大山盆地古油藏沥青地球化学特征及来源

根据沥青产状、族组成、饱和烃色谱、生物标志化合物、碳同位素以及沥青热演化程度等,对广西十万大山盆地北缘的老虎山古油藏、上屯古油藏二叠系灰岩中固体沥青的地球化学特征进行了系统分析,并结合有关烃源岩地球化学特征及油气成藏研究成果对其来源和成因进行了探讨.结果表明,古油藏沥青抽提物含量低,族组成中芳烃和非烃含量高,饱和烃含量低,芳烃含量最高可达58.60%.饱和烃气相色谱分析表明,沥青具还原环境、以低等水生生源为主的母质来源及较高的热演化程度.沥青稳定碳同位素为-27.8‰~-28.7‰,反映其生烃母质以低等生源为主.沥青中的甾、萜烷含量很低,且以低分子量化合物占绝对优势,其中甾烷系列中具很高的孕甾烷含量,萜烷则以三环萜烷为主,反映其高热演化特征.沥青几乎不含芳香甾烷,与本区上二叠统泥质烃源岩特征相似;沥青反射率为1.9%~2.5%,结合本区生烃成藏演化史分析结果,反映其经历过230℃高温.最后结合相关烃源岩地球化学特征及有关油气成藏信息,综合认为古油藏沥青与上二叠统泥质烃源岩有较好的亲缘关系,是古油藏早期原油高温裂解的产物之一,即焦沥青.     

Kinetics and physicochemical studies of surfactant enhanced remediation of hydrocarbons contaminated groundwater

Kinetics and physicochemical studies of surfactant enhanced remediation of hydrocarbons contaminated groundwater were investigated for efficiency and effectiveness. 10% pollution was simulated in the laboratory by contaminating groundwater samples with crude oil, automatic gasoline oil (diesel) and domestic purpose kerosene (DPK) in replicates of five. Physicochemical properties of the hydrocarbons contaminated groundwater samples and a control sample were investigated before and after treatments. Total petroleum (TPH) hydrocarbon as target contaminant was monitored periodically to assess the extent of the remediation process. TPH was determined by molecular spectrophotometry technique. Other physicochemical parameters such as pH, turbidity, alkalinity, dissolved oygen (DO), biochemical oxygen demand (BOD), chemical oxygen demand (COD), condutiivity, ammonia, nitrate, phosphate, salinity, total dissolved solids (TDS), total suspended solids (TSS) and total solids (TS) were obtained using standard methods while heavy metals levels were determined by atomic absorption spectrophotometry. Different kinetics models were tested to determine the appropriate kinetics model. The pseudo-first order kinetics is established with rate constant as 1.80 × 10⁴; 1.78 × 10⁴; 1.53 × 10⁴ mg^?1 L h^?1 for crude oil, diesel and kerosene respectively at 30 °C. At the end of the remediation after 6 h there was 89.11%; 93.21%; 87.76% reduction in TPH as crude oil, diesel and kerosene for the treated samples in that order. The application of surfactant enhanced remediation using sodium dodecyl sulphate is found be very efficient, effective and rapid in reducing total petroleum hydrocarbon as crude oil, kerosene and diesel as target contaminants. There is the need for post-treatments after remediation for most of the physicochemical parameters are impaired and do not meet the Guideline and Standards for Environmental Pollution Control in Nigeria set by Federal Ministry of Environment and World Health Organization for drinking water and agricultural uses in order to make them fit for these purposes.     

Physical and geochemical properties of crude oils in relation to their source rocks,Alif field,Marib Sub-basin,Yemen

Physical and geochemical properties were performed on three crude oils from Alif-01 well in the Marib sub-basin. The analyzed samples comprise medium specific gravity (37^° API), reflecting mature source rocks. The thermal maturity of the analyzed oils is also indicated from the high content of aliphatic hydrocarbons (HC). The compositions of HC further suggest that analyzed oils belong to paraffinic oils. The n-alkane and isoprenoid distributions reveal that the analyzed oils are derived from marine source rock, containing mixed organic matter, with some terrestrial input and deposited under relatively reducing conditions. The features of the analyzed oils are consistent with the Madbi source rock characteristics in the basin.     

Petrophysical evaluation and volumetric estimation within Central swamp depobelt,Niger Delta,using 3-D seismic and well logs

Estimation of hydrocarbon volume is a critical issue for the economic aspect of the petroleum industry. It is very key in production to estimate reserves and after considerable production, to determine the efficiency of recovery and also as a basis for advanced studies such as reservoir simulations. The petrophysical parameters and hydrocarbon volume within the Central swamp depobelt in the Niger Delta has been evaluated from seismic and well logs data. Two reservoirs, GA and GB were delineated from the logs. The lithologies are sand and shale sequences. The trapping system were interpreted from seismic sections as anticlinal and fault closures. Two horizons and several faults were mapped from the seismic sections. The faults mapped are mainly synthetic and antithetic, characteristic of the Niger Delta. The seismic to well tie shows a fairly good match. The average porosity and permeability estimated for reservoir GA are 20% and 1338 md respectively. Similarly, the estimated average porosity and permeability for reservoir GB are 21% and 1392 md respectively. The results show that the oil bearing zones in the reservoirs are porous and highly permeable. There was no gas present in either of the reservoirs. The estimated initial hydrocarbon in place for reservoirs GA and GB are 57.84 MMSTB and 48.43 MMSTB respectively. The results of the research shows that the field has a decent hydrocarbon potential and can be economically produced from.     

Density and viscosity of tight oil from Yanchang Formation,Ordos Basin,China and the geochemical controls

For assessing the density and viscosity of tight oil and their geochemical controls, 47 tight oil samples across the Ordos Basin were analyzed. The oil density and viscosity lay in the ranges of 0.81–0.88 g/ml and 1.9–13.36 mPa·s, which are low in overall. The average saturated hydrocarbon content is higher than 80%. The molecular compositions suggest a source dominated organic matter by lacustrine type I/II with minor input of terrestrial type III kerogen. The oils were mainly generated at relatively high maturities. Fractionation during the oil expulsion may also result in the depletion of heavy-ends compounds. These are the main controlling factors for the overall good quality of the Ordos tight oil.     

Kinetics of thermal degradation of a Japanese oil sand

Thermal degradation characteristics of a Japanese oil sand at different heating rates (10, 20, and 30 °C/min), and 30 ml/min air flow rate have been investigated. The kinetic parameters have been calculated based on three stages of weight loss and/or the conversion of the sample. These include, stage 1 (SI): volatilization of moisture content and the light hydrocarbon (20–227 °C), stage 2 (SII): combustion of heavy hydrocarbon (227–527 °C), and stage 3 (SIII): oxidative decomposition of carbonaceous organic matter (502–877 °C). The results showed that the rate of change of the oil sand conversion with time $\left(\frac{d\alpha }{\mathit{dt}}\right)$ was affected by the heating rate. The time taken by the system to reach 0.99 conversion was observed as 85, 50, and 35 min at the heating rates of 10, 20, and 30 °C/min, respectively. The frequency factor, A, at SI was between 0.09 and 0.54 min^?1, while the activation energy, E_a, was 11.2–12.5 KJmol^?1 (the percentage weight loss, W_t, was 0–3.6 %w/w; and the conversion, α, was 0–0.2.). At SII, the values of A and E_a were 2.1–5.5 min^?1 and 17.6–19 KJmol^?1, respectively (W_t = 3.1–15.88 %w/w; α = 0.17–0.86.). The value of A at SIII was 5.5E11–1.1E13 min^?1, while E_a was 160–200 KJmol^?1 (W_t = 15.33–17.99 %w/w; and α = 0.84–0.99).     

塔里木盆地塔深1井寒武系油气地球化学特征

塔深1井是中国及亚洲陆上最深的探井。在埋深8400m左右、温度160℃、压力80MPa环境下的上寒武统白云岩溶洞储集体中发现了褐黄色的液态烃。研究表明,井深6800~7358m的下奥陶统—上寒武统气样的烃类气体含量为97%,干燥系数为0.97,甲烷碳同位素平均值为-37.9‰,对应的气源岩R_o为1.65%~1.91%,属于典型高演化油型干气,天然气轻烃指纹分析表明与塔河天然气具有相似的母质来源;塔深1井(8406.4~8407.37m)液态烃的正构烷烃齐全,OEP为1.029,C₂₁-/C₂₁+为0.49~1.46,Pr/Ph为0.762~0.991,具有植烷优势,反映了还原—强还原环境的海相腐泥型烃源岩;从表征原油成熟度变化的Pr/nC₁₇,Pr/nC₁₈及芳烃甲基菲指数等分析,与塔河油田奥陶系原油有较大区别,与来自中下寒武统烃源岩的塔东2井、T904井原油相似,其族组分碳同位素δ¹³C分布于-29.13‰~-25.84‰,具C₂₇>C₂₈<29甾烷特征,初步认为其来自于中下寒武统烃源岩,而高地层压力可能是其保存的重要原因。     

蓬莱19-3油田未熟—低熟油特征及形成条件

蓬莱19-3油田是中国海域发现的最大油田,该油田所产原油部分为未熟—低熟油。利用大量的原油和烃源岩等实验资料,对蓬莱19-3油田未熟—低熟油的原油物性、族组分和生物标志化合物等特征进行了系统分析,并从烃源岩沉积环境、烃源岩特征和成烃母质等方面对未熟—低熟油的形成条件进行了探讨。研究结果表明:蓬莱19-3油田未熟—低熟油密度高、黏度高、含硫量中等、含蜡量低,具有饱和烃含量低、饱/芳比低、非烃含量偏高、非/沥比高、Pr/Ph低、重排甾烷丰度低和TsTm等特征;半咸水—咸水沉积环境、烃源岩有机质类型好且丰度高、有机质演化程度低是烃源岩生成未熟—低熟油的有利地质条件。     

Geochemistry,generation and maturation of the hydrocarbons at Wadi Al-Rayan oil field,Western Desert of Egypt

`The present work aims to study the organic chemistry, the generation and maturation of the hydrocarbons encountered at Abu Roash Formation, Wadi El Rayan oil field. The analysis of source rocks indicates the presence of two organic facies. The first is characterized by high total organic carbon of 0.93–3.39%, strongly oil-prone (Type II), and good potential for oil generation (pyrolysis S2 yields 4.54–23.26 mg HC/g rock and HI 488–705 mg HC/g TOC). The second attains good range of organic carbon from 0.90% to 1.57%, which is a mixed oil and gas (Type II–Type III) of fair hydrocarbon generation (pyrolysis S2 yield of 1.98–5.33 mg HC/g). The kerogen type consists of unstructured lipids and some terrestrial material. Plot of Pr/n-C17 versus Ph/n-C18 indicates that the crude oil was derived from mixed source rock, while the maturity profile assigns oil windows (0.6 R_o%) matching topmost of Abu Roash G Member.     

Assessment of n-alkanes and acyclic isoprenoids (geochemical markers) in crudes: A case study of Iraq and Niger delta,Nigeria

This study was designed to determine the ratios of the isoprenoids and n-alkanes in an imported crude oil sample (Bassrah from Iraq) and four crude oil samples (Bodo, Bonny-Export, Escravos and Penningston) from the Niger Delta region of Nigeria to ascertain the levels of maturity and as an indicator of the depositional environment of the crudes. The physical properties of the crudes: viscosity, density and °API gravity were also determined. Fractionation of the crudes was done using a new approach coded NAASAR, (n-alkanes, asphaltenes, aromatics and resins) comprising urea adduction followed by gas chromatographic analyses (for n-alkanes), n-heptane precipitation (for asphaltenes) and column chromatography (for resins). Results showed °API gravities Bassrah 28.03°, Bodo 31.89°, Bonny-Export 33.8°, Escravos 33.8°, and Penningston 33.8° indicating that Escravos, Penningston and Bonny-Export crudes are light crudes while Bodo and Bassrah crudes are medium crudes. The n-alkanes profiles of the five crudes were determined by gas chromatography ranged from n-C₈H₁₈ to n-C₄₀H₈₂ with total weight percent n-alkane yield Bassrah 11.2, Bodo 47.41, Bonny-Export 32.47, Escravos 5.58, Penningston 30.75 were obtained by urea adduction. The pristane to phytane ratios were computed, Bassrah 1.51, Bodo 1.48, Bonny-Export 1.08, Escravos 1.01 and Penningston 2.41. Isoprenoids to n-alkane ratios Pr/n-C₁₇ in the same order of the crudes were 0.85, 0.83, 0.67, 0.65, 0.95 while phytane to n-C₁₈ ratios were 0.61, 0.55, 0.62, 0.61 and 0.43. The results established the increasing level of maturity as obtained from Pr/n-C₁₇ ratio in the order: Penningston < Bassrah < Bodo < Bonny-Export < Escravos. The result of Pr/Ph ratios show the same trend in the level of maturity. Penningston crude with Pr/Ph ratio 2.41 shows that the crude is deposited in fluviomarine and coastal swamp environment while Bassrah, Bodo, Bonny-Export and Escravos crudes indicate aquatic depositional environment (anoxia) condition.     

Characterization of biosurfactants produced by novel strains of Ochrobactrum anthropi HM-1 and Citrobacter freundii HM-2 from used engine oil-contaminated soil

Microbial surfactants are widely used for industrial, agricultural, food, cosmetics, pharmaceutical, and medical applications. In this study, two bacterial strains namely, Ochrobactrum anthropi HM-1 and Citrobacter freundii HM-2, previously isolated from used engine oil contaminated soil, and capable of producing biosurfactants, were used. Their cell-free culture broth showed positive results toward five screening tests (hemolysis in blood agar, drop collapse, oil displacement, emulsification activity (E₂₄), and surface tension (ST) reduction). They reduced the ST of growth medium (70 ± 0.9) to 30.8 ± 0.6 and 32.5 ± 1.3 mN/m, respectively. The biosurfactants were classified as anionic biomolecules. Based on TLC pattern and FT-IR analysis, they were designated as glycolipids (rhamnolipid). Waste frying oil was feasibly used as a cheap and dominant carbon source for biosurfactants production; 4.9 and 4.1 g/l were obtained after 96 h of incubation, respectively. Compared with non-irradiated cells, gamma-irradiated cells (1.5 kGy) revealed enhanced biosurfactant production by 56 and 49% for HM-1 and HM-2, respectively. The biosurfactants showed good stability after exposure to extreme conditions [temperatures (50–100 °C for 30 min), pH (2–12) and salinity (2–10% NaCl)], they retained 83 and 79.3% of their E₂₄, respectively, after incubation for a month, under extreme conditions. Biosurfactants effectively recovered up to 70 and 67% of the residual oil, respectively, from oil-saturated sand pack columns. These biosurfactants are an interesting biotechnological product for many environmental and industrial applications.     

Oil Families and Their Potential Sources in the Southern Gulf of Suez,Egypt

Abstract

Four oil families are identified in the southern Gulf of Suez, through high-resolution geochemical studies including gas chromatography, gas chromatography–mass spectrometry, and carbon isotope analyses. Biological features characterize oils in family 1a, suggesting tertiary carbonate source rocks for these oils, rich in type II organic matter and deposited under anoxic depositional environment. Family 1b oil shows minor variations in the source of organic matter and the depositional environment, as it was derived from carbonate source rock with more algal and bacterial contribution and minor input of terrestrial organic sources, deposited under less saline condition compared to family 1a oil. Family 2 oil, although genetically related to family 1a oil, has some distinctive features, such as diasterane to sterane and pristane to phytane ratios, which suggest clay-rich source rocks and a more oxic depositional environment. Also, the lack of oleanane indicates pre-tertiary source rocks for this oil. In contrast, family 3 oil is of mixed sources (marine and non-marine), generated from low sulfur and clay-rich source rock of tertiary and/or younger age. Family 4 oil seems to be mixed from family 1b and family 3 oils, sourced mainly from carbonate source rocks rich in clay minerals with algal and bacterial contributions. Family 4 oil is highly mature, family 1b oil lies within equilibrium values (peak oil generation stage), while the other families are more or less near equilibrium.     

Evaluation of organic matters,hydrocarbon potential and thermal maturity of source rocks based on geochemical and statistical methods: Case study of source rocks in Ras Gharib oilfield,central Gulf of Suez,Egypt

In this study, we apply geochemical and statistical analyses for evaluating source rocks in Ras Gharib oilfield. The geochemical analysis includes pyrolysis data as total organic carbon (TOC%), generating source potential (S2), production index (PI), oxygen and hydrogen indices (OI, HI) and (Tmax). The results show that the Cretaceous source rocks are poor to good source rocks with kerogen of type III and have the capability of generating gas while, the Miocene source rocks are good to excellent source rocks with kerogen of type III–II and type II and have the capability of generating oil and gas. The analyzed data were treated statistically to find some factors, clusters, and relations concerning the evaluation of source rocks. These factors can be classified into organic richness and type of organic matter, hydrocarbon potentiality and thermal maturity. In addition, cluster analysis separated the source rocks in the study area into two major groups. (1) Source rocks characterized by HI >300 (mg/g), TOC from 0.76 to 11.63 wt%, S1 from 0.44 to 9.49 (mg/g) and S2 from 2.59 to 79.61 (mg/g) indicating good to excellent source rocks with kerogen of type III–II and type II and are capable of generating oil and gas. (2) Source rocks characterized by HI <300 (mg/g), TOC from 0.31 to 2.07 wt%, S1 from 0.17 to 1.29 (mg/g) and S2 from 0.31 to 3.34 (mg/g) indicating poor to good source rocks with kerogen of type III and are capable of generating gas. Moreover, Pearson’s correlation coefficient shows a strong positive correlation between TOC and S1, S2 and HI and no correlation between TOC and Tmax, highly negative correlation between TOC and OI and no correlation between Tmax and HI.     

渭河盆地新发现原油的特征及其油气地质意义

渭河盆地地热井中意外发现有石油产出，打破了该盆地无油的历史定论。为了认识该原油的特征及其油气地质意义，对采集的地热井原油的物性、族组分含量、饱和烃含量、甾烷与萜烷组成、饱和烃单体烃碳同位素组成进行了系统分析。分析表明，原油以饱和烃为主、芳香烃和沥青质次之，胶质含量最低，属于正常含蜡、低硫、轻胶质原油。饱和烃色谱呈双峰型，主峰为C₁₅和C₂₂，CPI和OEP值分别为0.93和0.90。原油母质成熟度较高且主要来自浮游水生生物和少量高等植物，并有藻类有机质的贡献。正构烷烃中低碳数（C₁₄-C₂₂）的碳同位素值随碳数增加而从-27.1‰降低到-30.3‰；当碳数高于C₂₂后，碳同位素值在-29.3‰和-30.4‰之间变化；姥鲛烷（Pr）和植烷（Ph）的碳同位素值重，分别为-26.1‰和-24.9‰。相对较高的伽马蜡烷含量表明了原油母质形成于较高盐度的水体中。通过邻区对比发现，该原油特征与鄂尔多斯盆地二叠系、三叠系延长组、侏罗系等已知产油层位的原油差别较大，显示出明显的地球化学与成因的特殊性。新发现原油表明渭河盆地应具有尚未发现的生烃源岩，对渭河盆地的油气勘探具有重要的指导意义，同时也可为鄂尔多斯周缘盆地新层系油气调查提供借鉴。