Petroleum Occurrences Research Articles

Unravelling Cenozoic carbonate platform fluid expulsion: Deciphering pockmark morphologies and genesis in the Tanintharyi shelf of the Andaman Sea as promising hydrocarbon reservoirs

Pockmarks, intriguing seafloor geological and geomorphological features, are commonly observed in marginal basins with hydrocarbon potential. As a Cenozoic marginal sea, the Andaman Sea is known for its significant petroleum reserves, and exploring its back-arc continental margin has revealed favourable conditions for petroleum occurrences. This study focuses on the Tanintharyi passive continental margin in the Andaman Sea, employing extensive stratigraphic and morphological analyses based on 2D and 3D seismic data interpretation techniques. Specifically, sub-seafloor characteristics of the Tanintharyi shelf region were investigated, focusing on comprehensively understanding pockmark morphologies, including their generation, evolution, migration, preservation, and the complete process leading to seabed leakage. This study revealed the potential of the Oligocene/Early Miocene carbonate platform in the Tanintharyi shelf region as a significant hydrocarbon reservoir for the upwelling buoyant fluids from the deep East Andaman Basin. Besides reservoir function, this carbonate platform serves as a passageway for the migration of fluids from the deep-sea area to the shallow-sea area, thereby playing a pivotal role in supporting fluid expulsion mechanisms in shaping a pockmark train adjacent to truncated sedimentary formations surrounding a geomorphological high on the contemporary seafloor. Additionally, the study examines the influence of changes in sedimentary facies and the tectonic setting of the Andaman Sea on pockmark evolutions, with a specific emphasis on the role of the uppermost shallow marine shale beds in developing sub-seafloor overpressure systems due to their impermeable seal rock properties. The article presents substantial evidence for the initiation of pockmark fields during the Middle Miocene period, followed by their transformation into pockmark trains on the present-day seafloor, attributed to the triggering effect of sub-seafloor overpressure systems due to changes in sedimentary dynamics in the Andaman Sea.

The “Golden Zone” temperature distribution of oil and gas occurrence examined using a global empirical database

We present here a straightforward empirical correlation between petroleum occurrence in sedimentary basins and reservoir temperature that can be integrated with other methods of analysis to reduce exploration risk. Global amounts of recoverable oil, gas, and gas-condensate in 1175 well characterized reservoirs from 954 of the world's largest fields, constituting 54% of the world's documented recoverable conventional oil and 50% of gas, are examined in terms of present-day reservoir temperature. Most volumes (74%) occur within the range of 60–120 ± 2 °C (140–248 ±4 °F), corresponding with the isotherm-bounded depth interval in petroliferous basins previously defined as the “Golden Zone” for exploration. Only 6% of the global total occurs at higher temperatures and 20% at lower temperatures. The decrease <58 °C is gradual in most regions, whereas the drop-off of discovered volumes >122 °C is precipitous. The low-temperature limit is suggested to reflect both poor sealing capacity of diagenetically immature shales and biodegragation, but many low-temperature accumulations survive because of uplift from previous maximum burial. The high-temperature limit is interpreted as resulting mainly from diagenetically induced overpressure that causes seal failure and remigration. Similarity between the distributions of both oil and gas with temperature indicates that the controlling processes are unrelated to petroleum generation. The distributions are also similar for sandstone and carbonate reservoirs and for reservoirs with shale, evaporite, and carbonate seals, indicating little lithologic influence. Although the ultimate controls can be debated and are certainly in need of continuing study, the observed temperature dependence of petroleum volumes is entirely empirical and can be used as an independent exploration risk factor. Nevertheless, the proportions of total estimated ultimate recovery above and below the Golden Zone temperature limits vary significantly between major petroleum-producing regions, so local calibration is essential.

Comparison of the Ediacaran and Cambrian petroleum systems in the Tianjingshan and the Micangshan uplifts, northern Sichuan Basin, China

Several different types of petroleum occurrences (including solid bitumens, oil sands, and oil seeps) are observed in various strata (e.g., the Ediacaran, Cambrian, Devonian, Permian, Triassic, and Jurassic strata) of the Tianjingshan and the Micangshan uplifts, northern Sichuan Basin, China. However, the sources of these petroleum occurrences are still in dispute, because of the severe biodegradation, strong thermal alteration, and multiple tectonic movements. At present, such uncertainty in the potential source rock systems has hindered oil and gas exploration in the study areas. In this study, methods including catalytic hydropyrolysis and trace elements analysis were introduced into the oil-source correlation study, to avoid the influence of biodegradation and/or thermal alteration. The results show that the petroleum shows that occur in the Cambrian-Jurassic strata of the Tianjingshan area are characterized by low maturity (equivalent vitrinite reflectance (EqVRo) < 1.0%), light organic carbon isotopic ratios (δ13Corg values ranging from −34.0‰ to −38.4‰), a predominance of C29-steranes, enrichment in V and Mo, and strong depletion in Bi elements. In contrast, the solid bitumens in the Ediacaran Dengying Formation in the Micangshan area have high maturity (EqVRo > 2.0%), slightly heavier δ13Corg values ranging from −27.5‰ to −36.0‰, a predominance of C27-steranes, weak enrichment in Mo and strong depletion in Rb and Bi elements. In addition, the Ediacaran and the Lower Cambrian source rocks can be discriminated by the bound sterane distributions, trace element concentrations, and bulk δ13Corg values. Further oil-source correlation indicates that the petroleum shows in the Cambrian-Jurassic strata in the Tianjingshan area were dominantly derived from the Lower Cambrian Qiongzhusi Formation, while those in the Ediacaran Dengying Formation in the Micangshan area were mainly sourced from the Ediacaran Doushantuo Formation. Finally, the results of oil-source correlation, combined with the tectonic evolution history of the investigated areas further elucidate the occurrence and distribution of petroleum, which can assist in oil and gas exploration in the investigated uplifts and the adjacent areas.

Organic compounds residues investigation in groundwater at Assiut governorate, Egypt

However the adverse impact of organic pollutants and their occurrence in the food chain in Egypt, scarce studies have dealt with these pollutants in water resources. The aim of this work is the non-targeted organic compounds investigation in Assiut Governorate groundwater, Egypt. Thirty-four samples were collected and analyzed for their chemical oxygen demand (COD), and three of them were selected for the non-targeted survey of organic compounds by GC-MS instrument. The COD values ranged from 0 to 216 mg O2/l, indicating the pollution of some samples with organic compounds. The GC-MS results indicated the occurrence of plastic, petroleum, pesticides and pharmaceutical residues in the analyzed samples. The source of these compounds may be household effluents, improper disposal of wastewater through absorption septic tanks, improper application of panned pesticides and leakage from fuel tanks. Finally, the groundwater needs targeted investigation of organic pollutants in the study area.

Pore Structure Characterization and Reservoir Quality Evaluation of Analcite-Rich Shale Oil Reservoir from the Bohai Bay Basin

Pore characteristics and shale oil reservoir quality strongly influences the petroleum occurrence, enrichment, and economic production. In this work, to characterize the pore system and evaluate the reservoir quality of analcite-rich shale oil reservoir, a total of 33 shale samples from the second member of the Paleogcene Kongdian Formation (Ek₂) of Bohai Bay Basin were examined using a suite of techniques, including total organic carbon (TOC) content, X-ray diffraction (XRD), field emission SEM, gas (CO₂ and N₂) physisorption, and mercury injection porosimetry (MIP). Six typical shale lithofacies are identified, and their pore characteristics are compared to reveal the factors affecting shale reservoir quality. The mineral matrix-related pore (e.g., intergranular and intragranular pores) is the dominant pore type in different shale lithofacies, with few organic matter (OM)-hosted pores being observed. Analcite-rich siliceous shale exhibits the largest specific surface area (SSA) and micropore volume, while the smallest is observed in analcite-rich mixed shale lithofacies. In contrast, the volume and SSA values of mesopores for siliceous shale are the largest, while mixed shale has the smallest values. Multipermeabilities of five connected pore networks were determined using the Katz-Thompson equation, and the permeability of microfractures or interlayer bedding cracks is at the micro-Darcy scale, as reflected by the first two inflection points. Permeability values for the other three inflection points reflect the matrix pore system within a nano-Darcy range. Siliceous shale has the high matrix permeability and good pore connectivity, which is favorable for fluid flow. Authigenic analcite mineral has different effects on pore development and reservoir quality depending on the shale mineral composition and diagenesis processes. Some primary pores were lost during the filling of analcite mineral in the early diagenesis period, but some intergranular pores were also protected by the rigid framework formed by analcite minerals. In addition, some secondary dissolution pores are generated during the reaction between analcite and organic acids discharged from the source rocks within the oil generation window, and the reservoir porosity and permeability can be greatly improved. Except for analcite, the TOC content is also an important factor controlling reservoir quality.

Quantitative evaluation of transport efficiency of fault-reservoir composite migration pathway systems in carbonate petroliferous basins

Carbonate petroliferous basins usually develop fault-reservoir composite migration pathway systems. Accurate estimates of transport efficiency are important for locating oil and gas prospects, which is of considerable interest to oil explorers. The Cambrian Longwangmiao Formation in the Moxi–Gaoshiti area in the Sichuan Basin, the largest single monoblock gas accumulation in China with complicated migration pathway systems, was selected as an example to demonstrate the method. Using a combination of geologic, statistical, experimental data analyses, and quantitative characterization, a quantitative method for calculating the fault-reservoir composite transport efficiency is established for the first time. The results show that fault-reservoir composite migration pathway systems control the hydrocarbon accumulation. The analysis of data from 17 drilling wells using this method indicated a strong correlation between well productivity and composite transport efficiency, and the matching degree of actual and predicted results was as high as 83%. The best locations for oil and gas exploration are near areas with a high composite transport efficiency. Project planners can quickly find oil and gas prospects by matching calculated composite transport efficiencies to observed petroleum occurrences in a basin to avoid costly drilling mistakes. The method will have wide application in other carbonate basins around the world.

Diamondoid geochemistry of Niger Delta source rocks: implication for petroleum exploration

ABSTRACT Investigation on the use of diamondoids to assess the extent of thermal maturity, depositional environment, and origin of Niger Delta source rocks was carried out. This was done to evaluate the significant of diamondoids in petroleum exploration in the basin. Pulverized rock samples selected from four Niger Delta oil wells, were extracted with Soxhlet extraction technique. The biomarkers content of saturated hydrocarbons fraction was assayed by gas chromatography-mass spectrometry (GC-MS) while the diamondoids content was analyzed using GC-MS-MS. The distribution of saturated hydrocarbons; n-alkanes, pristane, pyhtane, steranes, and terpanes revealed that samples from well AW were sourced from mixed terrestrial/marine organic matter while samples from wells OP, GB, and OT were sourced largely from terrestrial organic matter origin. The Pr/Ph ratio values indicated that the organic matter of wells AW and OP samples were deposited under suboxic conditions while those of wells GB and OT were deposited under anoxic conditions. Hopane and sterane thermal maturity geochemical parameters showed that the organic matter in source rocks from the four wells are thermally mature. Diamondoids source parameters indicated that well AW source rock samples had mixed marine/terrestrial organic matter input, while samples from wells OP, GB, OT were sourced from terrestrial organic matter, which is in perfect agreement with the results of other source geochemical parameters, thus indicating that diamondoids are good tools in determining the origin of petroleum. Diamondoid maturity parameters showed that all the samples from the four wells are thermally mature with maturity level ranging from early to main oil window. This study revealed that diamondoids can be used to evaluate petroleum occurrence in the study area or any other sedimentary basins.

PETROLEUM POTENTIAL OF THE EDIACARAN SUCCESSION RELATED TO GEOLOGICAL AND GEOCHEMICAL CONDITIONS IN THE VOLYN-PODILIAN

This work is concerned with the studying of Ediacaran petroleum potential within Volyn-Podyllian. For the first time ever, the lithostratigraphycal, geological, geothermal, geochemical and paleohistorical analysis was provided for the whole Ediacaran section to determine its petroleum potential.The description of Precambrian succession in the world with its hydrocarbon occurrence was included. In addition to that, this work contains methodology and methods of the basin analysis study, which was perfomed. The potential source rocks, reservoirs and seals within the study area were defined and described.Based on the computer-integrated instruments, for the Neoproterozoic deposits were created: third-dimensional model of its succession, depth map, schematic map of katagenetic zones and concentration model of organic carbon. The paleoconditions of deposition and maturation processes of organic matter were reconstructed. Key words: Ediacaran deposits, Volyn-Podillian, oil-and-gas potential, computer modelling, basin analysis, sedimentary

Temperature-depth control of petroleum occurrence in the sedimentary section of the South Caspian basin

This study analyses the temperature and depth control of well productivity (oil and gas), density of hydrocarbons (HC) and gas/liquid HC ratio (GLR) of petroleum fields in the South Caspian Basin (SCB). The database includes more than 700 field data from 54 onshore and offshore fields, which were processed to provide graphical and statistical analysis using standard computer programs. It was established that the peak of initial production and proven oil reserves falls in the temperature range 50–70 °C. The oils of this interval are characterized by medium (about 890 kg/m3) and light (about 806 kg/m3) density. The maximum condensate and gas production are in the temperature range 100–120 oС, associated with the discovery and operation of large gas condensate fields in the deepwater part of the SCB. Liquid HC are represented in this temperature interval by “volatile” oils and condensates with an average density of 777–802 kg/m3. Low values of GLR are typical for temperatures below 70 °C, associated both with poor gas conservation conditions and relatively high volumes of oil production. The carbon isotope composition of methane indicates an exclusively catagenetic (thermal) origin at temperatures >50 °C and both catagenetic and mixed (microbiological-catagenetic) at temperatures <50 °C. Based on the results, a forecast is provided for the discovery of new commercial HC accumulations.

Petroleum occurrences in the carbonate lithologies of the Gohta and Alta discoveries in the Barents Sea, Arctic Norway

Investigation of petroleum inclusions in carbonate samples from the Senilix well in the Barents Sea reveals petroleum entrapment in Paleozoic carbonates at reservoir temperatures from as low as 87.3°C to more than 130°C. Using corrected bottom hole temperatures, this corresponds to depths of 2800–4100 m, compared to the present-day depth of these samples of only 1965.9–2020.5 m. The oil in the Gohta and Alta discoveries is concluded to be of either Lower Triassic or Paleozoic origin based on the isomer distribution of triaromatic dimethylcholesteroids (TA-DMC). A potential source-rock candidate is the Ørret Formation, which is the time-equivalent to the Ravnefjeld Formation in Greenland. These oils are of a different origin compared to oils in the nearby Skrugard (renamed to Johan Castberg) discovery which contain oil sourced from the Upper Jurassic Hekkingen Formation. Evidence is presented to suggest that the Gohta and Alta oils represent blends of petroleum expelled at maturities ranging from about 1.0% calculated vitrinite reflectance (Rc) to more than 1.3%Rc, and this corroborates the inferences made from the petroleum inclusions. This emerging play is significant to exploration in the karst developed on the Barents Shelf and the Bjarmeland Platform during the Permo-Carboniferous. Karst reservoirs have been linked to eustatic sea-level changes, and analogous karst reservoirs may be present elsewhere in the Circum-Arctic: for example, in the Sverdrup Basin.

Petroleum geology of the 2018 offshore acreage release areas

A total of 21 areas were released in 2018 for offshore petroleum exploration. They are located in the Bonaparte, Browse, Northern Carnarvon, Bight, Otway and Gippsland basins. All release areas were supported by industry nominations, indicating that interest in exploring Australia’s offshore basins remains strong, despite the significant decrease in the number of exploration wells drilled in recent years. Sixteen areas are being released under the work program bidding system with two rounds, one closing on 18 October 2018 and the other on 21 March 2019. Five areas are being released for cash bidding and include the producible La Bella gas accumulation in the Otway Basin. Prequalification for participation in the cash-bid auction closes on 4 October 2018 with the auction scheduled for 7 February 2019. Geoscience Australia continues to support industry activities by acquiring, interpreting and integrating pre-competitive datasets that are made freely available as part of the agency’s regional petroleum geological studies. The regional evaluation of the petroleum systems in the Browse Basin has been completed and work continues on assessing the distribution of Early Triassic source rocks and related petroleum occurrences across the North West Shelf. A wealth of seismic and well data, submitted under the Offshore Petroleum and Greenhouse Gas Storage Act 2006, are made available through the National Offshore Petroleum Information Management System. Additional datasets are accessible through Geoscience Australia’s data repository.

Petroleum systems in Southeast Asian Tertiary basins

Productive Tertiary basins in Southeast Asia have essentially similar geodynamic developments, and share many hydrocarbon habitats and active petroleum systems. In order to facilitate understanding of the essential elements that contribute to the success of petroleum systems I have classified them into a number of groups or ‘associations’ according to their sedimentary facies. This facilitates use of them as valuable analogues. Five such facies associations, containing characteristic and distinct petroleum parameters have been recognised: (i) lacustrine (ii) paralic (iii) open marine shelf (iv) deeper marine and (v) pre-Tertiary. They belong to particular cycles or stages in basin development that provide the context within which the depositional environments and palaeogeography evolve. Lacustrine facies typify the early stages of synrift development in basins closer or more proximal to the Sundaland province in northern and western SE Asia. Open marine facies, on the other hand, typify the early postrift period and basins in palaeogeographically more distal areas, such as eastern Indonesia and The Philippines. Paralic and bathyal facies characterise the later stages of the synrift and postrift cycles and are widespread throughout the proximal and intermediate parts of the area. Pre-Tertiary source facies, which provide charge in parts of eastern Indonesia and Thailand, are mainly terrestrial in nature. These differences have important implications for petroleum occurrence, which can be summarised accordingly: • More proximal basins are dominated by lacustrine to paralic facies in the synrift cycle and have a mainly non-marine sedimentary fill. Petroleum systems with oil charge are dominant. • More distal basins are dominated by rapid postrift subsidence. In the open marine facies carbonate reservoirs are well-developed, while petroleum systems are mainly gas-prone. • Around Borneo thick late postrift passive margin delta sequences with oil- and gas-prone coaly source rocks and clastic reservoirs are developed in delta-top environments. Transported terrigenous organic material is commonly found in related deep marine environments and contributes to a marine source facies. Both give rise to prolific petroleum systems. • Many basins in the Sunda Shelf area lie in an intermediate situation, where a non-marine synrift is followed by a marine postrift cycle. Such basins benefit from lacustrine and paralic source rock and reservoir sequences in both the syn- and the postrift, and are often characterised by multiple petroleum systems. Evaluation of petroleum potential in Southeast Asian Tertiary basins requires a special approach: in most parts of the World, such as the Middle East and Northwest Europe, source rocks are of marine origin, are relatively consistent in type and quality and are located in well-defined formations of regional extent. In SE Asia the terrestrial and lacustrine source rocks are more difficult to locate, are variable in quality and are often distributed in thin beds throughout thick sequences. These differences mean that predictive extrapolations of charge quality and maturity, and therefore of basin prospectivity, are much more difficult in Southeast Asia: This probably explains why discoveries continue to be made after almost 130 years of exploration!

An unusual Proterozoic petroleum play in Western Africa: the Atar Group carbonates (Taoudeni Basin, Mauritania)

Abstract The Taoudeni Basin is the largest sedimentary basin in Africa. This intracratonic basin, which forms the sedimentary cover of the West African Craton, records episodic sedimentation since the Proterozoic. It is a largely unexplored basin, with only eight exploration wells drilled to date, although its petroleum prospectivity was established in 1974 when gas and liquids were tested in the Abolag-1 well. This paper focuses on the identification and assessment of potential source rocks and reservoirs in the Taoudeni Basin in Mauritania and aims to establish a geochemical genetic link between the occurrence of petroleum and potential sources. Various disciplines and techniques were integrated to reach a better understanding of the petroleum systems potentially existing in this basin. We also define and describe the elements and processes of the Atar-Atar (!) petroleum system. This study is an example of the exploration of an unusual and high-risk play in some of the oldest sedimentary rocks on Earth, with a long, polyphase structural evolution, a complex thermal history (where burial might not be the only controlling factor), a massively diagenetized carbonate reservoir, and large uncertainties on the timing of generation, trap formation and preservation.

Touchable topography: 3D printing elevation data and structural models to overcome the issue of scale

The fundamental problem of geology is scale. Geological length scales range from angstroms for atoms to thousands of kilometres for planets. Geological processes are often very slow (and geological events so very infrequent). Since the beginning of our discipline, it has been the business of geologists to integrate observations at a variety of length and time scales to answer questions about Earth's history and to make predictions about its future. While this may sound like one of the most academic of pursuits, multi‐billion dollar decisions are routinely made by governments and the largest multi‐national corporations on the basis of geological studies that, for example, model groundwater or petroleum occurrence.

Geochemical Investigation of Vertical Migration of Petroleum through Mudstones I: Origin of the Hydrocarbon Shows

Hydrocarbon shows and seeps are frequently associated with petroleum migration through caprocks. However, leakage of petroleum from reservoirs does not necessarily result in surface seeps, nor do all occurrences of surface petroleum result from trap leakage. Cretaceous Shetland Group mudrocks which serves as caprock (seal) for the petroleum reservoir of the Heidrun Field was observed to contain liquid hydrocarbon as evidenced from UV florescence. Is this oil indigenous of the caprock or from the underlying reservoir thereby indicating possible failure of the seal? Samples from the caprock were analysed with the aim of establishing the origin of the oil stains. The investigation comprised bulk geochemical analyses in order to estimate various leakage indicators (S1 & PI). High Extractable Organic Matter (EOM) values of up to 6 mg/g rock were obtained in most of the samples. The high S1 and PI values obtained from the samples suggest oil staining. Furthermore, Iatroscan SARA analysis was used to identify compositional variability between the oil present in the caprock and the reservoir oil. The reservoir oil predominantly consisted of saturated hydrocarbons, which, in contrast, represent only a fraction of the caprock EOM. The caprock EOM is dominated by polar compounds, and the saturate fraction increases with increasing proximity to the caprock/reservoir boundary. High gas wetness of more than 80% was recorded at caprock/reservoir boundary, suggesting a good relationship between the distribution of gaseous hydrocarbons in the caprock and the gas content of the reservoir oil. The oil stains in the caprock are therefore established to be sourced from the reservoir.

Chapter 1 Introduction to the Petroleum Geology of Myanmar

Before the birth of the modern, mechanized, petroleum industry, Myanmar (formerly Burma) was an exporter of oil products from its hand-dug wells in the centre of the country. It is now an important exporter again, but of gas from its offshore fields, and the international petroleum companies are keen to obtain acreage both onshore and offshore; in the lead-up to the 2013 offshore round no fewer than 60 companies pre-qualified with the Ministry of Energy of the Myanmar government. It was not until the incorporation of Burma into British India in 1885 that extensive geological research was initiated in the country, with many of these articles (up to independence in 1948) being published in reports of the Geological Survey of India. Historically important publications by their geologists included a study of the all-important Tertiary rocks by Noetling (1895) followed by his account of the country's petroleum occurrences (Noetling 1897). A more detailed study followed, covering the core petroleum-bearing area (what we now call the Salin Basin in the Central Burma Depression, Fig. 1.1) by Grimes (1898). As a modern petroleum industry became established following the formation of the Burmah Oil Company in 1886, the Geological Survey of India (Pascoe 1912) published a major update of what the author described had become ‘… .one of the most important industries of the Indian Empire.’ Accounts of the oil fields by industry geologists included those by Stamp (1927), Evans (1941) and Tainsh (1950); meanwhile, a major study of the wider geology of Burma was published by Chhibber (1934 a ) and of its mineral resources by the same author (Chhibber 1934 b ). In many respects those works by Chhibber remain standard references on Burmese geology, as does the later study by Pascoe (1950–1964). Fig. 1.1. Myanmar, the largest country in mainland …

Tracing migration pathways by integrated geological, geophysical, and geochemical data: A case study from the JX1-1 oil field, Bohai Bay Basin, China

Tracing petroleum migration pathways is essential for predicting petroleum occurrence and reducing exploration risks associated with hydrocarbon charge, but a difficult task because of rapid lateral and vertical facies changes in lacustrine basins. An integration of geological, geophysical, and geochemical analysis is employed to investigate the origin of crude oil, the carrier-bed architecture, and migration pathways from source to trap in the JX1-1 oil field, Liaodong Bay subbasin, Bohai Bay Basin. Detailed geochemical studies suggest that three potential source-rock intervals (, , and ) exist in the Liaodong Bay subbasin, and crude oil in the JX1-1 field was derived from the and source rocks. The carrier beds from and source rocks to the trap were characterized using geophysical data. The fan-delta sandstone in the Member has an immediate contact with source rock and served as dominant conduit for the expulsion and migration of oil generated from source rock. The braided-delta sandstones overlying the source rock served as dominant conduit for -sourced oil. The focusing of petroleum migration pathways and the merge of migration pathways in and sandstones account for the accumulation of the JX1-1 field and the mixing of - and -sourced oil in the field. This study suggests that the distribution of permeable sandstones and their stratigraphic contact with the source rocks are key for petroleum migration and occurrence, and integration of geophysical, geological, and geochemical studies provide an effective way to trace petroleum migration pathways.

Control of differential tectonic evolution on petroleum occurrence in Bohai Bay Basin

The Bohai Bay Basin (BBB) is the most petroliferous Cenozoic basin in the east of China. It consists of seven depressions. Each depression has been subjected to different stress states and then has experienced varying faulting processes since the Neogene, especially during the Neotectonism (from the Pliocene to the present). On the basis of the investigation of fault patterns, fault densities and fault activity rates (FARs) for each depression, this paper demonstrates the discrepancy of faulting development and evolution across the BBB. The dynamic mechanism for the differences in faulting is also discussed by the analysis of the regional stress state. The Bozhong Depression is just situated in the transtensional zone induced by the two active strike-slip faults, namely Yingkou-Weifang and Beijing-Penglai. In this depression, the major faults which cut through the Paleogene or the Cenozoic have had higher than 10 m/Ma FARs since the Neogene, and the highest FARs have reached or exceeded 25 m/Ma during the Neotectonism. As a result, most of the petroleum has migrated along these major faults and accumulated within the Neogene. In contrast, in the other depressions of the BBB away from the Bozhong Depression, the FARs of the major faults were decreased to lower than 10 m/Ma since the Neogene, and tended to be zero during the Neotectonism. Therefore, the major faults could not serve as vertical conduits for petroleum migration, and the petroleum was entrapped in the Paleogene. Consequently, the faulting since the Neogene, especially during the Neotectonism, controlled the petroleum richness in vertical strata.

Remedy for shortage or risk for national security? The search for oil in Switzerland

Over several decades, geologists, entrepreneurs, politicians, and public authorities dealt with a potential petroleum occurrence in Switzerland. They provided scientific expertise, granted concessions, invested capital and sank bore holes. Although the endeavour was never successful economically, it reveals how closely related geopolitical situations and the exploitation of natural resources were. This article investigates the search for crude oil in Switzerland from the 1930s until the 1960s, combining a history of science and technology perspective with a history of the political regulations and economic considerations concerning the extractive industry. It traces the changing fears and hopes about potential oil occurrences in Switzerland: From an investment to overcome future shortages, to the risk of imperial desires if oil would be found in abundance.

Use of stripping tower and reverse osmosis in removal of petroleum hydrocarbons from water

The universality of occurrence and usage of petroleum leads to higher water environment pollution by oil derivatives products. Taking into account their high toxicity on living organisms, effective methods of water treatment should be found in order to protect health of consumers and natural water resources. In the paper, the issue of petroleum hydrocarbons’ removal from C7 to C35 from model water, which means distilled water with addition of diesel fuel and petroleum, was analyzed. The experiments were conducted in order to assess the efficiency of their removing from water with the use of the following combination: stripping tower and reversed osmosis. Technological experiments were done on stripping tower in the conditions of different concentration, stable aeration intensity, and hydraulic load of 1 [m3/m2 h]. Reverse osmosis was done with pressure of 1.1 MPa and line speed over membrane of 1.1 m/s. Two series were done with the concentration of 252.96 and 192.62 μg/dm3. Analyzed water was brought to stripping tower, and then, it was exposed to reverse osmosis process. The determination of petroleum hydrocarbons was done on gas chromatograph according to Polish Norm PN-C-04643 and classified as index of mineral oil. As a result of this process, 80% effect of petroleum hydrocarbons removal was obtained.