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Abstract This study is a part of the source rock geochemistry project in the onshore Sabatyen Basin, Yemen. The results of this study were used to improve our understanding of the petroleum resource potential of Al-Jawf sub-basin in the north-western part of the Sabatyen Basin. The shale samples of the Late Jurassic Arwa Member from two wells (Khyawan-01 and Himyar-01) were analyzed to evaluate the characterises of the organic richness, kerogen type, thermal maturity and petroleum generation potential in Al-Jawf sub-basin based on a compilation of geochemical and petrological data. The biomarker and stable isotope results were subsequently used to evaluate the organic source input and sedimentary environmental conditions during deposition of the Late Jurassic Arwa Member shales. The Arwa shales contain low to high organic matter, with variable TOC% values between 0.58 and 6.41, indicating fair to very good source rock generative potential. The Rock-Eval HI data are ranging from 73 to 816 mg HC/g TOC and display mainly Type III and II/III kerogens with a minor contribution of Types I/II kerogen, consistent with both oil and gas source rocks. The biological sources are predominately sapropelic organic matter, with significant contribution of higher plants input in the Arwa member shales as indicated from biomarkers and carbon isotope data and petrology study. The biomarker ratios of relatively low Pr/Ph, Pr/ n -C 17 and Ph/ n -C 18 values and relatively high values of HC 34 /HC 35 indicate suboxic environmental conditions during deposition of the Arwa Member shales. The analyzed Arwa shale samples have temperatures of maximum pyrolysis yield (T max) in the range of 417–457 °C and vitrinite reflectance between 0.30 and 0.56 %Ro, consistent with immature to early-mature source rocks. It is interesting to know that the Arwa shale samples with high contents of TOC% (>1), HI (>300 mg HC/g TOC) and high thickness of more than 1000 m indicate that the Late Jurassic Arwa Member hold significant exploration potential for oil in the deeper locations. Therefore, the hydrocarbon exploration processes should be focused on the known deeper location of the Arwa Member for predicting the mature source rock. Highlights • Arwa shales were classified as fair to good potential source rocks in Al-Jawf sub-basin. • The Arwa shales contain mixed organic matter and deposited under suboxic conditions. • The Arwa shales are considered to be both oil and gas source rocks. • The Arwa shales are still at immature to early-mature stages for oil-generation in the studied wells. [ABSTRACT FROM AUTHOR]

The typical characteristics of shale gas and the enrichment differences show that some shale gases are insufficiently explained by the existing continuous enrichment mode. These shale gases include the Wufeng–Longmaxi shale gas in the Jiaoshiba and Youyang Blocks, the Lewis shale gas in the San Juan Basin. Further analysis reveals three static subsystems (hydrocarbon source rock, gas reservoirs and seal formations) and four dynamic subsystems (tectonic evolution, sedimentary sequence, diagenetic evolution and hydrocarbon‐generation history) in shale‐ gas enrichment systems. Tectonic evolution drives the dynamic operation of the whole shale‐gas enrichment system. The shale‐gas enrichment modes controlled by tectonic evolution are classifiable into three groups and six subgroups. Group I modes are characterized by tectonically controlled hydrocarbon source rock, and include continuous in‐situ biogenic shale gas (I1) and continuous in‐situ thermogenic shale gas (I2). Group II modes are characterized by tectonically controlled gas reservoirs, and include anticline‐controlled reservoir enrichment (II1) and fracture‐controlled reservoir enrichment (II2). Group III modes possess tectonically controlled seal formations, and include faulted leakage enrichment (III1) and eroded residual enrichment (III2). In terms of quantity and exploitation potential, I1 and I2 are the best shale‐gas enrichment modes, followed by II1 and II2. The least effective modes are III1 and III2. The categorization provides a different perspective for deep shale‐gas exploration. [ABSTRACT FROM AUTHOR]

The present study deals with the Jeribe Formation (Middle Miocene) in well Khabaz-17 (Long. 44° 11' 27" E; Lat. 35° 25' 16" N) belonging to Khabaz oil field in Kirkuk area, northern Iraq. Generally, the lithology of Jeribe Formation is homogeneous and it consists of limestone, dolomite, dolomitic limestone, gypsum, and nodules of chert with a thickness of about 36 m at depth 645-681 m. Petrographically, 50 thin sections have been prepared and studied under polarized microscope. Based on this, they appeared to consists mainly of genus benthonic foraminifera (Borelis melo curdica, Miliolids, Peneroplis, Nummulites and Rotalids) where they characterized by the good keeping, large volume and the thickness of the wall. On the other hand, less common fauna included Gastropods, Pelecypods, Echinodermata fragments, Algae, Ostracods and many of bioclasts, as well as nonskeletal grains intraclasts and pisoids, while the ground mass mainly compose of a micrite and micro-sparite. Several diagentic processes affected the Jeribe formation which include mainly of dolomitization, cementation, micritization, dissolution, compaction, fracturing and other types of diagenetic such as neomorphism and bioturbation. Through the petrographic study the types of porosity were identified. While, the porosity ratios was determined from the density and the neutron logs. According to the results of these analyses, the porosity of Jeribe formation changes from 11.4% and 25.6%, with an average rate of 17.3%. These values are described as good porosity, and had probably been enhanced by some diagenetic processes by dolomitization and dissolution followed by secondary effects from tectonics activities. [ABSTRACT FROM AUTHOR]

Late Devonian mass extinctions attributed to extensive anoxia and/or euxinia of the oceans are associated with widespread deposition of organic-rich shales. Also in the epeiric waters of the Canning Basin (Western Australia), photic zone euxinia (PZE) prevailed during the Givetian–Frasnian, with geochemical evidence for PZE on the northern (Lennard Shelf)–, and southern (Barbwire Terrace) margins of the Fitzroy Trough. On the Lennard Shelf, shales record episodic pulses of PZE associated with high algal activity due to enhanced nutrient supply, whereas a restricted marine setting on the Barbwire Terrace is thought to be the main driver for the development of persistent PZE and associated bacterial predominance. Structural evidence indicates that the Fitzroy Trough was a confined basin during the Late Devonian with the possibility of limited ocean circulation. Widespread PZE is expected to have developed in the poorly mixed water column, if the basin received sufficient nutrient supply for enhanced primary production. Notwithstanding the presence of anoxia during deposition of potential source rocks, only two small Devonian-sourced oil fields and numerous oil shows have been found in the Canning Basin. Biomarker assemblages show that the oils produced from the Lennard Shelf fields (i.e. Blina-1, Blina-4 and Janpam North-1) have substantially different molecular compositions to the minor oil recovered from Mirbelia-1 on the Barbwire Terrace. A correlation was established between the Lennard Shelf oils and rock extracts from the Gogo Formation at Blina-1 and McWhae Ridge-1 based on their hopane, sterane and carotenoids abundances. A definitive source correlation was not obtained for the Mirbelia-1 oil, but it did show some genetic affinity to the Givetian–Frasnian extracts from the Barbwire Terrace, suggesting that local source rocks are developed in the region. [ABSTRACT FROM AUTHOR]

Knowledge of hydrogen solubility in tall oil fractions is important for designing hydrotreatment processes of these complex nonedible biobased materials. Unfortunately measurements of hydrogen solubility into these fractions are missing in the literature. This work reports hydrogen solubility measured in four tall oil fractions between 373 and 597 K and at pressures from 5 to 10 MPa. Three of the fractions were distilled tall oil fractions their resin acids contents are respectively 2, 20 and 23 in mass-%. Additionally one fraction was a crude tall oil (CTO) sample containing sterols as the main neutral fraction. Measurements were performed using a continuous flow synthetic isothermal and isobaric method based on the visual observation of the bubble point. Composition of the flow was changed step-wise for the bubble point composition determination. We assume that the tall oil fractions did not react during measurements, based on the composition analysis performed before and after the measurements. Additionally the densities of the fractions were measured at atmospheric pressure from 293.15 to 323.15 K. A Henry’s law model was developed for the distilled tall oil fractions describing the solubility with an absolute average deviation of 2.1%. Inputs of the solubility model are temperature, total pressure and the density of the oil at 323.15 K. The solubility of hydrogen in the CTO sample can be described with the developed model with an absolute average deviation of 3.4%. The solubility of hydrogen increases both with increasing pressure and/or increasing temperature. The more dense fractions of the tall oil exhibit lower hydrogen solubility in comparison to the less dense fractions. The increase in the density of a fraction corresponds to an increased resin acid and sterol content of the sample. Sterols and resin acids exhibit lower hydrogen solubility in comparison to fatty acids. [ABSTRACT FROM AUTHOR]

A reconnaissance study of potential hydrocarbon source rocks of Paleozoic to Cenozoic age from the highly remote New Siberian Islands Archipelago (Russian Arctic) was carried out. 101 samples were collected from outcrops representing the principal Paleozoic-Cenozoic units across the entire archipelago. Organic petrological and geochemical analyses (vitrinite reflectance measurements, Rock-Eval pyrolysis, GC-MS) were undertaken in order to screen the maturity, quality and quantity of the organic matter in the outcrop samples. The lithology varies from continental sedimentary rocks with coal particles to shallow marine carbonates and deep marine black shales. Several organic-rich intervals were identified in the Upper Paleozoic to Lower Cenozoic succession. Lower Devonian shales were found to have the highest source rock potential of all Paleozoic units. Middle Carboniferous-Permian and Triassic units appear to have a good potential for natural gas formation. Late Mesozoic (Cretaceous) and Cenozoic low-rank coals, lignites, and coal-bearing sandstones also display a potential for gas generation. Kerogen type III (humic, gas-prone) dominates in most of the samples, and indicates deposition in lacustrine to coastal paleoenvironments. Most of the samples (except some of Cretaceous and Paleogene age) reached oil window maturities, whereas the Devonian to Carboniferous units shared a maturity mainly within the gas window. [ABSTRACT FROM AUTHOR]

Crude oil samples from Cretaceous and Tertiary reservoir sections in the Zagros Fold Belt oil fields, southern Iraq were investigated using non-biomarker and biomarker parameters. The results of this study have been used to assess source of organic matter, and the genetic link between oils and their potential source rocks in the basin. The oils are characterized by high sulphur and trace metal (Ni, V) contents and relatively low API gravity values (17.4–22.7° API). This indicates that these oils are heavy and generated from a marine source rock containing Type II-S kerogen. This is supported by their biomarker distributions of normal alkanes, regular isoprenoids, terpanes and steranes and the bulk carbon isotope compositions of their saturated and aromatic hydrocarbons. The oils are characterized by low Pr/Ph ratios (<1), high values of the C 35 homohopane index and C 31 -22R/C 30 hopane ratios, relatively high C 27 sterane concentrations, and the predominance of C 29 -norhopane. These biomarkers suggest that the oils were generated predominantly from a marine carbonate source rock, deposited under reducing conditions and containing plankton/algal and microorganisms source input. The presence of gammacerane also suggests water column stratification during source rock deposition. The biomarker characteristics of the oils are consistent with those of the Middle Jurassic Sargelu carbonate as the effective source rock in the basin. Biomarker maturity data indicate that the oils were generated from early maturity source rocks. [ABSTRACT FROM AUTHOR]

En la presente investigación se aislaron e identificaron 5 grupos bacterianos de 3 muestras liofilizadas de suelos contaminados. La identificación de las bacterias incluyó la tinción de Gram, tensión de oxígeno y pruebas bioquímicas. Los microorganismos, individuales y en consorcio, fueron utilizados para realizar pruebas de tratabilidad a escala de laboratorio en reactores aerobios mesofílicos por carga de 3 L, con un volumen útil de 1 L, conteniendo 0.3 L de suspensión bacteriana y 0.7 L de agua de formación de petróleo mediano. Antes y durante los 6 días de experimentación se realizaron mediciones de pH, DQO, alcalinidad total, SSV y SST del agua de formación. Los resultados considerados a partir del segundo día de tratamiento, cuando las condiciones en los reactores son más estables y los microorganismos están más adaptados al medio proporcionado, indican una eficiente disminución de la DQO, entre 62.4 y 89.8%, utilizando las diferentes cepas bacterianas, debidamente caracterizadas, y el consorcio, demostrando la eficiencia de los microorganismos, individuales y en conjunto, de biodegradar la materia orgánica compleja presente en el agua de formación utilizada, correspondiendo las mayores eficiencias en la disminución de la DQO al consorcio bacteriano (89,8%) seguido por los géneros Xanthomonas (84%) y Aeromonas (80,6%).Five groups bacteria were isolated and identified from liofilizated samples of contaminated soil. The identification of these bacteria included: Gram stain, oxygen tension and, biochemical tests. Individually and in consortium, the microorganisms isolated were used to conduct a treatability study on a laboratory scale as well as in a mesofílics aerobic reactors with load of 3 L, that have a useful volume of 1 L. The reactor cointaned 0,3 L of bacterial suspension and 0,7 L of water supplemented with a formation of mediated petroleum. Before and during the 6 days of experimentation were measured the pH, COD, total alkalinity, VSS and TSS of formation water were. The results considered were those collected from the second day of treatment, since it is then when the conditions in the reactors are more stable and the microorganisms are more adapted to medium provided. Those results indicated an efficient reduction of the COD, (between 62,4 and 89,8%), while using the different bacterial stocks properly characterized and the consortium., this finding showed the efficiency of the individual microorganisms and in groups to biodegrade complex organic matter present in the water formation used. We found that the bacterial consortium was more efficient in the reduction of the COD (89,8%), followed by Xanthomonas (84%) and Aeromonas (80,6%) genus.

The thermal evolution of sedimentary organic matter is a significant mechanism in continental oil and gas formation. This study presents a new method to estimate vertical thermal evolution trends in a lake sediment core. Twenty sediment samples from a 60-cm core recovered from Lake Bosten were heated to 600 °C at a rate of 10 °C min under a N atmosphere. The sediments were characterized by differential scanning calorimetry (DSC) and thermogravimetric analysis (TGA), and then, the samples were analyzed with total organic carbon (TOC) analyses, X-ray diffraction, and Cs isotopic dating techniques. Two main anaerobic thermal degradation processes were observed in the thermograms. The pyrolysis results showed variations with sediment age, with labile carbon (237.2 ± 42.98 °C) manifesting different thermogram patterns than recalcitrant carbon (498.35 ± 30.09 °C). There was a significant linear correlation between sample weight loss and TOC ( r = 0.972, p < 0.001), as well as between the DSC and TGA peaks ( r = 0.963, p < 0.001). As a conclusion, the thermal stability of both labile organic carbon and recalcitrant organic carbon in lacustrine sediment core increased gradually with age. These results confirm that advanced thermal techniques (DSC and TGA) operated in inert gas are potential quantitative methods to characterize the anaerobic thermal behavior of sediment organic carbon. [ABSTRACT FROM AUTHOR]

Hydrous pyrolysis experiments were conducted on immature petroleum source rocks to define the roles of pressure and hydrocarbon expulsion in deep petroleum formation. This study can contribute to estimating the deep oil and natural gas prospects of lacustrine type-I kerogen and has important implications for deep petroleum exploration. The simulation temperature was 450 °C and the heating duration was 48 h. Water pressure ranged between 50 and 1200 bar, and lithostatic pressure ranged between 125 and 2000 bar. Under semi-closed conditions, increasing water pressure leads to more oil and less gaseous hydrocarbons being generated in the source rocks. The dryness of the hydrocarbon gas primarily confirms that increasing water pressure decreases the cracking magnitude of oil, which may indicate that high water pressures retard oil cracking. The decreasing contents of S 2 , HI and H/C in the solid residue confirm that high water pressure enhances the efficiency of hydrocarbon generation. Oil cracking is enhanced in the 125–625 bar lithostatic pressure range, probably because the pyrolysis conditions gradually approach those of a closed-system. The increasing gaseous hydrocarbon yields also confirm the accelerated cracking of oil within this pressure range. As lithostatic pressure increased from 625 to 2000 bar, the decreasing trends in oil and gaseous hydrocarbon yields indicate that hydrocarbon generation rate was retarded by high pressure within the closed system. The values of S 2 , HI, H/C, R o and T max in solid pyrolysis residue confirm that high lithostatic pressure reduces the efficiency of hydrocarbon generation and maturation. Furthermore, hydrocarbon expulsion greatly impacts hydrocarbon generation within the source rocks. Increasing water pressure increases the effect of hydrocarbon expulsion and causes the pyrolysis conditions to gradually approach an open system; this phenomenon lowers the gas yields but increases oil yields. Increasing lithostatic pressure from 125 to 625 bar decreases the effect of hydrocarbon expulsion and causes the pyrolysis conditions to steadily approach a closed system, thereby lowering the oil yield but increasing gas yield. The results demonstrate that different pressures clearly have different effects on hydrocarbon generation in the source rock, and hydrocarbon expulsion also has a significant influence on hydrocarbon generation in source rock. More importantly, this study shows that the lacustrine type-I kerogen has a good potential to yield deep oil and natural gas. [ABSTRACT FROM AUTHOR]

A sequence of possible reactions occurring during evolution of deep-lying fluids, components of which could be sources of biogenous oil substances, is studied within the confines of biogenetic concept of formation of oil. Oxidative condensation transformation of methane and its immediate homologs under the action of sulfur present in some fluids might have facilitated formation of various types of hydrocarbons and organosulfur compounds. The possibility of such transformations is supported by the stable direct correlations between sulfur concentration in oils, their density, viscosity, content of asphaltic-resinous components and heavy fractions, and the scale of oil deposits. The proportion of gas in the oil-gas systems decreases with increase of sulfur content. Metals, like V and Ni, in the deep-lying fluids affect the geochemical type of oil. Vanadium oils are heavier (V > Ni), have high sulfur contents, and occur closer to the surface, while Ni oils are lighter (Ni < V), have low sulfur contents, and occur in deeper strata. These characteristics apparently stem from the different nature of catalytic properties of the metals and the structures containing them. Transformations of the oil fluid with the involvement of heterocomponents thus affect the fractional and chemical composition of oil-gas systems. [ABSTRACT FROM AUTHOR]

Crude oil foams are highly complex non-aqueous foams that tend to form from the release of dissolved gas after an abrupt decrease in the pressure. These foams are typically encountered during crude oil exploitation and refining and especially in oil–gas separation processes. These kinds of foams are widely different from aqueous ones in terms of formation and stabilization and therefore classical methods developed for the study of aqueous foams are no longer useful to reproduce crude oil foam formation conditions. For this reason, we have developed a foam test based on crude oil depressurization to simulate crude oil formation during oil production. Foams can be generated through the laboratory test in a reproducible way and can be consequently characterized in terms of foaminess, stability and kinetics of rupture. Moreover, we also have developed a new methodology to characterize foam stability and liquid foaminess by modeling the crude oil defoaming kinetics. The model we propose allows an easy comparison of the behavior of crude oils foams. By studying different crude oils of known compositions, we have found a correlation between their behavior in term of stability and foaminess and a parameter that takes into account the crude viscosity and its composition. [ABSTRACT FROM AUTHOR]

Pyrolysis experiments (open and closed systems) and kinetic modelling of primary cracking of kerogen have been carried out to investigate hydrocarbon generation characteristics and source rock facies variability within the Upper Cretaceous to Paleogene Latrobe Group in the Gippsland Basin. On the basis of Rock-Eval data, the interbedded coals, coaly shales and carbonaceous shales contain different types of kerogen (Type III, Type II–III, Type II) with variable potential for both gas and liquid hydrocarbon generation. Open system pyrolysis–gas chromatography data indicate that the organically lean marginal marine shales of the Santonian–early Campanian Tricolporites apoxyexinus and Nothofagidites senectus biozones produce gas and condensate. However, coal and coaly to carbonaceous shales sampled from the Paleocene Lygistepollenites balmei , Maastrichtian Forcipites longus , late Campanian Tricolporites lilliei and Turonian Phyllocladidites mawsonii palynological biozones are heterogeneous with the capacity to generate both low and high wax paraffinic–naphthenic–aromatic (P–N–A) oils, and paraffinic oils with a high wax content. The main phase of petroleum formation from these later biozones, assuming a constant geological heating rate of 3.3 °C/Ma, is predicted to occur between 150–179 °C, indicating different orders of kinetic stability as a result of different types of organic matter and their state of preservation. The thermally immature shales have variable bulk kinetic characteristics, but the measured compositional kinetics and phase behaviour show that they have the potential to generate black oils at early stages of kerogen cracking, and either light oils or wet gases at higher levels of thermal stress. These findings suggest that upon thermal maturation, the interbedded shales of the Latrobe Group may have contributed significant volumes of hydrocarbons to the oil and gas accumulations in the Gippsland Basin. In addition, this study not only supports the premise that over-reliance on Rock-Eval/TOC data alone can be misleading for assessment of petroleum generation, but also represents a strategy for kerogen type and generative potential determination for fluvio-deltaic coals and subordinate lithologies. [ABSTRACT FROM AUTHOR]

In this work, non-catalytic pyrolysis of Turkish pine (Pinus brutiaTen.) wood sawdust was performed in a fixed-bed reactor at various temperatures to obtain the optimum conditions to achieve a maximum bio-oil yield. The highest yield of bio-oil was obtained about 46 wt% at 550°C for non-catalytic pyrolysis. At the optimum conditions, the effects of different catalyst types (KOH, ZnCl2, and ZnO) and amount of catalyst (5, 10, 15, and 20 wt%) on the pyrolysis product yields and bio-oil properties were investigated. The presence of catalysts changed the product distribution considerably. Increasing the amount of catalyst led to a decrease in the yield of liquid product, while the gas and char yields increased compared to non-catalytic pyrolysis. The chemical compositions of bio-oil were determined with GC-MS analyses. It was determined that bio-oils contain a large variety of organic compounds, such as furans, aldehydes, ketones, phenols, acids, benzenes, alcohols, alkanes, and polycyclic aromatic hydrocarbons (PAHs). The catalysis by KOH significantly increased the levels of phenols, while it reduced the formation of acids and aldehydes. ZnCl2produced bio-oil with high percentages of aldehydes. Moreover, ZnO reduced the proportion of PAH in the bio-oil. These results demonstrated that bio-oils could improve with a catalyst. Therefore, catalyst selection for high bio-oil quality is crucial in industrial applications. [ABSTRACT FROM PUBLISHER]

The feasibility of indirect application of low frequency ultrasound for demulsification of crude oil was investigated without using chemical demulsifiers. Experiments were performed in an ultrasonic bath with frequency of 35 kHz. Synthetic emulsions with water content of 12%, 35% and 50% and median of droplet size distribution (DSD), median D (0.5), of 5, 10 and 25 μm were prepared from crude oil with API density of 19 (heavy crude oil) and submitted to the proposed ultrasound-assisted demulsification procedure. Experimental conditions as temperature, time of exposition to ultrasound and ultrasonic power were evaluated. Separation of water from crude oil emulsion was observed for all emulsions investigated. Demulsification efficiency up to 65% was obtained for emulsion with 50% of water content and DSD of 10 μm. Higher efficiency of demulsification was achieved using US temperature of 45 °C and ultrasound power of 160 W by 15 min. Results obtained in this study showed that ultrasound could be considered a promising technology for industrial crude oil treatment and respective water removal. [ABSTRACT FROM AUTHOR]

Selected organic reactants, includingn-dodecanol and stearic acid adsorbed on clays at low temperature (300 K), decomposed on heating (>400 K) to yield alkane product mixtures: thermal desorption reactions. These products showed that, while adsorbed, reactant hydrocarbon chains underwent cracking, isomerisation and hydrogen transfers. Because product distributions obtained from several different reactants were closely similar, it is concluded that these reactants extensively rearranged to form similar mixtures of surface-bonded species. From this evidence, we suggest that thermal desorption provides a realistic chemical mechanism for natural petroleum formation: it is well-known that some minerals promote kerogen breakdown. To investigate the feasibility of this mechanism in nature, the following comparisons were made.Qualitative:Our model thermal desorption reactions yielded alkanes in the C5–C8range that are usual constituents of crude oils.Quantitative:Product yields were sufficiently large to explain the amounts of crude oil found in natural reservoirs.Kinetic:Extrapolation of our measured alkane thermal desorption rates, to lower temperatures, confirmed that long (geological) time intervals are required to accumulate the amounts of crude oils found in reservoirs. We conclude, therefore, that initial adsorption of organic compounds on suitable acid catalysts, e.g. the clay montmorillonite, with subsequent slow hydrocarbon desorption after burial, is a realistic and feasible mechanism for petroleum formation in natural sediments. Thermoanalytical rate data obtained for geochemical pyrolysis reactions are critically appraised in the context of some representative kinetic studies in the literature. Furthermore, deactivation on adsorption may preserve the organic precursors of oil from rapid, early decay. [ABSTRACT FROM PUBLISHER]

In the Oil Industry, the construction steel of facilities experiences corrosion affectations. The petroleum formation water is conductive and for its heterogeneous composition, CO2, H2S and chlorides produce inside corrosion. In the steel can be formed corrosion products in competitive form between iron sulphide and the iron carbonate, according to temperature, concentration corrosive agent's and pressure. The present work has as objective: to determine corrosion rate of API 5LX-52 steel in saline polluted medium with carbon dioxide and hydrogen sulphide to 90 °C and to establish steel corrosion products generated during this evaluation. It shows high corrosion rates that were obtained by gravimetric method. The Sweep Electronic Microscopy (MEB) and Dispersive Energy Spectroscopy of X rays (EDX) techniques were used in the study. The results show different morphologies: conglomerates, stacked flakes and craters, which were compound mainly for iron and oxygen. The different morphologies and EDX spectra suggests oxides and iron oxi-hidroxides presence like main constituent and in smaller proportion, iron sulphide, what was confirmed by X Rays Diffraction. [ABSTRACT FROM AUTHOR]

This paper is devoted to a study of the characteristic features of the composition and structure of crude oils from terrigenous Devonian producing deposits in the Minnibaevskii section of the Romashkino and Pervomai fields. Using the SynOil program, we identified the features of the molecular weight distribution of n-paraffins, cyclohexanes, and monoalkylbenzenes associated with the formation and transformation conditions in the crude oil deposits. [ABSTRACT FROM AUTHOR]

Significant volumes of hydrocarbons have been produced from karstified Infracambrian dolomites in a 'buried hill' structure at depths of 5860m to 6027m and reservoir temperatures of 190-201°C in well Niudong-1 in the Baxian depression, Bohai Bay Basin. This is the deepest oil and gas discovery made in eastern China so far and structures at similar depths are targets for exploration elsewhere in the Bohai Bay Basin. However the origin and accumulation of the hydrocarbons at Niudong-1 is not clear: they may have been generated from highly mature lacustrine source rocks in the Sha-4 Member of the Eocene Shahejie Formation; or they may have been derived from thermal cracking of previously-accumulated oil. This paper investigates the organic geochemistry of the Sha-4 Member source rocks and the crude oils produced from well Niudong-1. Analyses of molecular parameters show that the hydrocarbons originated from the pyrolysis of organic matter in Sha-4 Member source rocks, rather than from cracking of previously accumulated oil. Infracambrian dolomites at the Niudong-1 location may have been charged with low-maturity oil around 34 Ma ago, when the Sha-4 Member source rocks were buried to depths of about 3500m and first entered the oil window. During further rapid burial to more than 5500m starting at about 15Ma, these source rocks became highly mature and generated significant volumes of light oil and gas. Overpressures in the source rock interval forced these hydrocarbons to migrate into unconformably-underlying Infracambrian dolomite reservoir rocks at the Niudong-1 structure. Significant risks are associated with future exploration of deep 'buried hill' structures in the Bohai Bay Basin. Not all the structures were charged with oil, and accumulations were not necessarily preserved during Neogene burial as the reservoirs may have been breached by faulting. [ABSTRACT FROM AUTHOR]

Up to now, there has not been one specific correlation published to directly estimate the bubble-point pressure in the absence of pressure-volume-temperature (PVT) analysis. Presently, there is just one published correlation available to estimate the bubble-point oil formation volume factor (FVF) directly in the absence of PVT analysis. Multiple regression analysis technique is applied to develop two novel correlations to estimate the bubble-point pressure and the bubble-point oil FVF. The developed correlations can be applied in a straightforward manner by using direct field measurement data. Separator gas oil ratio, separator pressure, stock-tank oil gravity, and reservoir temperature are the only key parameters required to predict bubble-point pressure and bubble-point oil FVF. [ABSTRACT FROM AUTHOR]

Waxy crude oil is characterized by high pour point and poor flow properties, which bring great difficulty to the oil exploitation and transportation. In this study, the fluidity of waxy crude oil with the pour point of 47°C was highly improved by emulsification with synthetic formation water used as aqueous phase. It was found that the combination of CAO-35 and sodium oleate was an effective emulsifier mixture to form stable waxy crude oil-in-water emulsion and when the mass ratio of oil to water was 7:3, the optimum composition of emulsifying additives with respect to the total mass of the emulsion was obtained as follows: emulsifier mixture (the mass ratio of CAO-35 to sodium oleate was 8:2) 0.4% (w/w), sodium triphosphate 0.028% (w/w), NaOH 0.05% (w/w), and polyacrylamide 0.15% (w/w). Diverse factors affecting the pour point of the formed emulsion were also studied. It was found that the pour point of emulsion increased as oil content increased and the optimum mixing speed and cooling rate were 600 rpm and 0.5°C/min, respectively. Under the optimum emulsifying conditions, when mixing speeds were 250 and 600 rpm, respectively, by forming O/W emulsions with the oil content of 70%, the pour point reductions were 20 and 25°C, respectively, and the corresponding viscosity reductions were 89.79% and 97.46% (40°C), respectively. Thus the pour point and viscosity of waxy crude oil are obviously reduced by forming oil-in-water emulsion, which is highly promising for the exploitation and transportation of waxy crude oil. [ABSTRACT FROM AUTHOR]

Nowadays, there exists a great interest in horizontal and hydraulically fractured wells, as they are much more productive than vertical ones. The authors propose a comparison of productivity index and drainage area for a horizontal well and a vertically fractured one. The comparison is done on the basis of well test analysis of a horizontally drilled well in Ilam formation. The study is oriented toward the numerical methods to solve complex equations describing the pressure behavior of hydraulically fractured wells. The authors show that the numerical solution is much more accurate than the analytical one which is based on the pseudo skin function concept. The drainage area and productivity index for both cases is compared. The results state that in similar conditions, hydraulic fracturing would be much more effective than a horizontal well in discussed case. [ABSTRACT FROM AUTHOR]

Abstract: This paper focuses on the idea for enhancing oil recovery by CO2 injection into oil formation as well as reducing CO2 emission into the atmosphere. The mechanism of asphaltene flocculation during CO2 flooding in oil formations is analyzed and the regressive correlation between CO2 concentration and the amount of flocculated asphaltene for an oil sample is set up for coupling with the flow governing equations for the flocculated asphaltene transport in porous media. A three-dimensional multiphase mathematical model describing CO2 transport in oil reservoirs and asphaltene precipitation is presented for predicting CO2 flooding performances for enhanced oil recovery. The finite difference method and preconditioned conjugate gradient algorithm are used to solve the discrete nonlinear equation systems. A numerical simulation software is developed to study CO2 flooding performances and the effects of asphaltene precipitation on production behaviors. The numerical result indicates that water-cut decreases from initial 92.5% down to 40.3% after continuous CO2 injection for 10 years. It is also shown that 0.130 million tons of crude oil is displaced by CO2 injection in the 1km2 of the reservoir within 10 years. Asphaltene precipitation leads to the decrease in permeability, and the decline in production rates. [Copyright &y& Elsevier]

Abstract: 3D basin modelling of the Hammerfest Basin (southwestern Barents Sea) was performed in order to address the masses of petroleum generated, accumulated and lost during the evolution of the basin. Calibration of the model, based on observed maturity (vitrinite reflectance) and present-day temperatures, took into account (1) two main erosion episodes: an Oligocene–Miocene event, due to tectonic uplift and a Plio-Pleistocene glacial erosion event, and (2) variable heat flow from Late Palaeozoic to Cenozoic. The maturity levels of the main source rocks (Kobbe, Snadd and Hekkingen formations) were reconstructed and show that the highest maturities have been reached in the western and northwestern margin of the basin. The beginning of petroleum generation in the Kobbe, Snadd and Hekkingen source rocks has been predicted to occur during Late Triassic, Early Cretaceous and Late Cretaceous, respectively. Our model reproduces satisfactorily the distribution of the main oil and gas fields and discoveries that have been found in the study area. Our results indicate that two events of hydrocarbons redistribution occurred in the basin. The first event resulted in the main oil redistribution episode, which took place during the Oligocene–Miocene associated with tectonic uplift and gas expansion, and the second was related to the main gas leakage events that occurred during the Pliocene–Pleistocene glacialinterglacial cycles in general and the episodes of glacial retreat in particular. Glacial loading and unloading cycles resulted in overpressure fluctuations in the subsurface reservoirs. Modelling results indicate that during these episodes a portion (at least 0.247 Gt) of thermogenic gas leaked from the main Stø Formation reservoirs reached the sediment interface and was released to the surface in the Hammerfest Basin. [Copyright &y& Elsevier]

Abstract: A nonlocal dynamic model of petroleum formation is used to explore possible causes and consequences of the nonlinear behavior of large petroleum systems. As a result of this nonlinearity, migration and accumulation of oil starts only after hydrocarbons in a reservoir reach a threshold amount. Significant differences in the amount of in-place resources in macroscopically similar petroleum systems may be associated with minor random changes in initial conditions. [Copyright &y& Elsevier]

Hydrocarbon generation and expulsion experiment in account of pressure and expulsion effects is an important approach in resource assessment and petroleum formation mechanism.lt is necessary to integrate hydrocarbon generation process in pyrolysis experiments with geological maturity. An immature coal is pyrolyzed in three experiment models.The first two are in confined gold reactors at temperatures from 300°C to 650°C with heating rates of 2°C. h and 20°C/h and under a pressure of 30MPa.The third is in hydrocarbon generation and expulsion simulation rig at temperatures from 250°C to 650°C with rapid healing rates and holding lime of 72 hour and under a pressure of 30Mpa. The relationship between hydrogen carbon atomic ratio and vitrinite reflectance is confirmed by the mathematical statistics of 139 geological samples. In view of indicative feature of hydrogen-carbon atomic ratio for organic maturation and hydrocarbon generation, the curves between experimental thermal parameters and geological maturity are graphed for these three series of experiments. Compared with geological maturity Ro the value of solid residue in confined gold reactors is higher by 0-0.9%, and the value at higher maturity stage in hydrocarbon generation and expulsion simulation rig is lower by 0-0.2%. The values of Easy%Ro in the three series of experiments are 0-0.8% lower than the values of geological maturity. Obviously, the vitrinite reflectance of solid residue in hydrocarbon generation and expulsion simulation rig is nearer to geological maturity than in con fined gold reactor. The conclusion reflects that pressure and hydrocarbon expulsion play an important role in thernial maturity and hydrocarbon generation process of organic mailer. Krror analysis shows thai the corrected maturity of experimental samples with hydrogen carbon atomic ratio relationship are 0.25% lower in oil window,0.5% lower in gas stage than the real geological maturity. These curves can be applied to resource assessment in coal measures regions by pyrolysis experiments. [ABSTRACT FROM AUTHOR]

The article discusses the formation of diamonds and oil in seawater that has been subducted into the earth. It references the Deep Earth Water model of chemical reactions between water and rocks developed by geochemist Dimitri Sverjensky and colleagues at Johns Hopkins University. Topics discussed include the dielectric constant of water, carbonate, the layered textures of diamonds, and experimental mineralogist Isabelle Daniel.

The article examines the formation mechanism and developmental characteristics of tight oil. It uses different materials and methods to discuss the formation mechanism and taxonomic character of tight oil. It describes the formation mechanism of tight oil on several aspects which include reservoir type, porosity, diagenesis and hydrocarbon migration fashion.