High Petroleum Potential Research Articles

Petroleum Potential and Organic-Matter–Oil Correlation in the Rocks of the Upper Riphean Iremeken Formation in the Kamo Arch of the Baikit Anteclise (Siberian Platform)

Abstract —A complex of laboratory studies of Riphean rocks and oils was carried out by the organic-geochemistry methods to construct a basin model for the Kamo arch of the Baikit anteclise of the Siberian craton. We compared the parameters of the organic matter (OM) and oils of the Upper Riphean Iremeken carbonaceous member by biomarker hydrocarbons. Analysis of the obtained chromatography–mass spectrometry data showed an unordinary group hydrocarbon composition of extracts from the OM and oils and low contents of cheilanthanes and steranes in them. Within the Kamo arch, the Upper Riphean Iremeken OM-enriched deposits with a high petroleum potential might have reached the peak of petroleum generation only in the deepest part of the Madra trough; thus, the traps could not be completely filled with oil. The distribution of tricyclic terpanes in the rock bitumens from the studied wells testifies to immature OM in the Iremeken Formation. However, in the most submerged zones of the Kamo arch and in the adjacent areas, oil was generated from the OM of the Iremeken Formation. This is evidenced by the oils of the Upper Iremeken Subformation in the Kuyumbinskoe field and the Ter’-Kamo license area.

Stratigraphy of the Cenozoic succession in eastern Azerbaijan: Implications for petroleum systems and paleogeography in the Caspian basin

The Cenozoic succession in the Lower Kura Basin includes largely uniform, often carbonate-free mudstones. Because age dating of these sediments has proved difficult, the stratigraphy of the Cenozoic succession and the distribution of organic-rich strata are poorly known. A better understanding of the Cenozoic succession is not only important for petroleum-systems-analysis, but also for the understanding of the Cenozoic evolution of the Caucasus region. Therefore, bulk geochemical data (carbonate, TOC, sulphur, Rock-Eval) of 885 samples and biostratigraphic data were collected along seven outcrop profiles. This enabled the establishment of a continuous stratigraphic record from the Middle Eocene to the Late Miocene (Pontian). The study results show that potential source rocks are present in three stratigraphic units: the Middle Koun (Middle Eocene), Maikop Group (Oligo-Miocene) and Diatom Formation (Upper Miocene). The Middle Koun is about 100 m thick near the Caspian Sea and contains highly oil-prone sediments (2–24 wt% TOC; HI 300–577 mgHC/gTOC), which may generate 1.5 tHC/m2. The Maikop Group contains on average 1.8 wt% TOC, but is often gas-prone. Highly oil prone layers (2–5 wt% TOC; HI 300–450 mgHC/gTOC) are rare. Nevertheless, the Upper Maikop Formation may generate ∼2 tHC/m2. The Diatom Formation contains paper shales with high TOC contents (3–22 wt%) and HI values (350–770 mgHC/gTOC). The paper shale unit is more than 60 m thick near the Caspian Sea and can generate 3.8 tHC/m2. Previously it was thought that the Maikop Group had the highest petroleum potential, whilst Upper Miocene and Middle Eocene source intervals were overlooked. The Middle Eocene to Lower Oligocene succession in the Kura Basin is largely carbonate-free. In contrast, coeval successions elsewhere in the Caucasus region contain sediments with varying, but often high carbonate contents. Differences in carbonate content imply greater water depth during deposition in the Kura Basin.

Ресурсный потенциал гряды Чернышева (Тимано-Печорский бассейн) в контексте новых данных о строении и продуктивности соленосных надвиговых поясов

The salt bearing thrust belts are among the most prolific petroleum provinces in the world, including the fold belts flanking the Persian Gulf Basin, the Tarim Basin, the Terek-Sunzha Zone of the Eastern PreCaucasus etc. They are characterized by peculiar structural styles of deformation, large oil and gas pool sizes, significant flow rates. The Chernyshev Swell is among prospective salt bearing thrust belts. It is located in the Cis-Uralian part of the Timan Pechora Basin. Several exploration wells have been drilled in the area so far failed to deliver the anticipated oil and gas deposits. Post mortem study indicated that the main reason for the past failures was the mismatch between the complexities of the geological settings and the used exploration technologies. Integrated study of the area, conducted by the North Uralian Petroleum Company, using modern technologies, including 3D seismic surveying and magnetotelluric sounding, has enabled a far better understanding of this area’s structure and petroleum habitat. It is shown that high petroleum potential is attributed to the transition zone between the Chernyshev Swell and the Kosyu Rogov Foredeep Basin. This study indicated that the area of the Povarnitsa High is of priority interest for explration. This area provides supplementary opportunities in addition to the commercialization of the petroleum exploration potential. It includes production of rare earth and metals in brine of the evaporate deposits. The subsalt reservoirs of the Chernyshev Swell could be used for the storage of gas and CO2 sequestration. Integrated development of the resource potential of the Povarnitsa High may become a key driver of the economic development of the north-eastern part of the Republic of Komi.

Origins and deep petroleum dynamic accumulation in the southwest part of the Bozhong depression, Bohai Bay Basin: Insights from geochemical and geological evidences

Latest exploration practices revealed appreciable petroleum resources in the deep pre-Cenozoic reservoirs in the southwest area of the Bozhong depression; however, the origins and accumulation mechanisms of deep hydrocarbons remain not fully understood. Here, an integrated study of the geochemical characteristics of overlying source rocks, maturity evaluation of petroleum, and origin of natural gas was conducted to characterize the dynamic petroleum accumulation and illustrate the main factors influencing the differential phases of petroleum distribution in the research area. The third member of the Dongying Formation (Ed3) mudstone in the research area displays high organic richness and is characterized by oil-prone organic matter, indicating high petroleum potential. The oils contained in the CFD18 and BZ13 buried-hill traps were mainly derived from the Ed3 and Shahejie Formation (Es) source rocks, respectively, with natural gas of kerogen cracking origin. Buried-hill oil from the BZ13 field displays a high thermal maturity than that of the CFD18 oils, which was evidenced by maturity parameters of saturated and aromatic hydrocarbons and concentrations of stigmastane. Nevertheless, maturity index of diamondoids and carbon isotopic composition of natural gas indicate the possible presence of mixing of higher mature Es fluids for the CFD18 field. This research underlines the contribution of the overlapped effective source rocks to the buried-hill traps. The causes of multiple petroleum phases in the deep reservoirs in the research area are mainly linked to dynamic petroleum accumulation rather than source rock type and oil secondary cracking. Although faults are present to act as vertical migration conduits due to late-stage activation with high intensity, abundant petroleum supply due to near-source charge and favorable constitution relationship of source rock and reservoir rock provide crucial conditions for deep petroleum accumulation in a tectonic activation zone.

An ABC-optimized fuzzy ELECTRE approach for assessing petroleum potential at the petroleum system level

AbstractAn inevitable aspect of modern petroleum exploration is the simultaneous consideration of large, complex, and disparate spatial data sets. In this context, the present article proposes the optimized fuzzy ELECTRE (OFE) approach based on combining the artificial bee colony (ABC) optimization algorithm, fuzzy logic, and an outranking method to assess petroleum potential at the petroleum system level in a spatial framework using experts’ knowledge and the information available in the discovered petroleum accumulations simultaneously. It uses the characteristics of the essential elements of a petroleum system as key criteria. To demonstrate the approach, a case study was conducted on the Red River petroleum system of the Williston Basin. Having completed the assorted preprocessing steps, eight spatial data sets associated with the criteria were integrated using the OFE to produce a map that makes it possible to delineate the areas with the highest petroleum potential and the lowest risk for further exploratory investigations. The success and prediction rate curves were used to measure the performance of the model. Both success and prediction accuracies lie in the range of 80–90%, indicating an excellent model performance. Considering the five-class petroleum potential, the proposed approach outperforms the spatial models used in the previous studies. In addition, comparing the results of the FE and OFE indicated that the optimization of the weights by the ABC algorithm has improved accuracy by approximately 15%, namely, a relatively higher success rate and lower risk in petroleum exploration.

Organic Geochemistry and Microfossils of the Upper Jurassic and Lower Cretaceous Strata in the Lower Reaches of the Olenek River (Northeastern Framing of the Siberian Platform, Arctic Siberia)

Abstract —The organic-geochemistry data reveal two levels in the reference Upper Jurassic–Lower Cretaceous section of the lower reaches of the Olenek River: lower (Volgian–lower Boreal Berriasian (diasterene)) and upper (Boreal Berriasian–Valanginian (hopane)). The Volgian beds are composed of clays with abundant prasinophytes Leiosphaeridia and Tasmanites and various dinocyst assemblages and have the highest content of organic carbon (Corg), up to 9%. Isoprenoids, in particular, pristane and phytane, are highly predominant among aliphatic hydrocarbons; their content is more than three times higher than that of coeluting n-alkanes, which is typical of buried chlorophyll-containing plankton (dinocysts and prasinophytes). Sedimentological, biofacies, and paleoecological analyses show that the highly carbonaceous beds of the Buolkalakh Formation formed under oxygen deficit conditions. An integrated analysis demonstrated that the pristane/phytane ratio does not always reliably reflect the reducing or oxidizing conditions of organic-matter accumulation and diagenesis. The discrepancy between the geochemical identification of organic matter according to the pristane/phytane ratio and the biofacies and sedimentological data is due to the low catagenetic maturity of OM. The Volgian was marked by a significant transgression of the Anabar–Lena sea, which was gradually changed by a successive regression of its basin at the end of this stage and in the Boreal Berriasian. The Corg contents in the coastal and subcontinental sediments decreased. Diasterenes and 4-methyldiasterenes disappeared from the balance of biomarker molecules, and the portion of hopanoids increased. Aerobic environments prevailed in the subbottom waters. Earlier, three biomarker horizons were identified according to geochemical criteria in the synchronous sections of Anabar Bay (Laptev Sea coast): terpane, diasterene, and hopane ones. In the section of the Olenek basin, the upper two horizons are well identified by specific biomarkers, and the lower one is absent because of the sedimentation break. Stratigraphic analysis of the location of these geochemical levels in different parts (and bathymetric zones) of the Anabar–Lena basin shows their diachronous formation. According to all geological and geochemical criteria, the Volgian Stage and the lower beds of the Boreal Berriasian Stage of this basin have a high petroleum potential. In the axial zone of the basin and, especially, on the Laptev Sea shelf, there were probably favorable conditions for the generation and accumulation of hydrocarbons genetically related to the Upper Jurassic highly carbonaceous rocks.

The use of compiled thermal methods in the characteristics of source rocks on the example of menilite beds

The aim of the research was to compare the results of the thermal decomposition of organic matter using different research methods. Experiments were carried out to assess interpretation methods in the characterization of the generation potential of source rocks. The research was conducted for samples of Menilite shales, recognized on the basis of long-term geochemical studies as good quality source rocks. The samples represented the Menilite Beds of the Silesian Unit, taken from the outcrops in the Carpathians. Research using known methods: Rock-Eval pyrolysis (RE), thermogravimetric and calorimetric methods (TG/DSC), and pyrolysis methods combined with gas chromatography analysis (PY-GC), were performed on the same samples- both on rock samples, as well as isolated kerogen. Such integrated studies have so far not been conducted on any rock material. The applied research methods showed a significant comparability of the results obtained. A number of correlations were found between the parameters from individual methods, including: the amount of hydrocarbons separated during PY-GC in the temperature range of 300–650°C, and the parameter S2 from RE, and mass loss in the TG analysis in the same temperature range; S2 values of rock samples and kerogen with weight loss as a result of pyrolysis from TG/DSC analysis at temperatures in the range of 300–650°C; temperature values of the maximum peak S2 (Tpk2) of rock samples with the maximum mass loss temperature during TG analysis; residual carbon content (RC) from RE analysis of rock and kerogen samples with a mass loss as a result of burning residual organic matter from TG/DSC analysis at temperatures in the range of 650–1050°C. The mass loss determined during thermogravimetric analysis, combined with the percentage share of individual hydrocarbon fractions, in which the C9+ fraction is significant, confirms the high petroleum potential of the organic substance contained in the Menilite Beds. Comparative studies of pyrolytic methods: Rock Eval, TG/DSC and PY-GC have proved the compatibility of the results obtained with all methods. Each of the methods also makes it possible to obtain mutually complementary information relating to the TOC, the degree of thermal maturity and type of generated hydrocarbons and other non-hydrocarbon compounds. The conducted tests and performed correlations showed the usefulness of a set of thermal methods to obtain complete information on source rocks.

Oligocene and Lower Miocene source rocks in the Paratethys: palaeogeographical and stratigraphic controls

Abstract Oligocene and Lower Miocene deposits in the Paratethys are important source rocks, but reveal major stratigraphic and regional differences. As a consequence of the first Paratethys isolation, source rocks with very good oil potential accumulated during Early Oligocene time in the Central Paratethys. Coeval source rocks in the Eastern Paratethys are characterized by a lower source potential. With the exception of the Carpathian Basin and the eastern Kura Basin, the source potential of Upper Oligocene and Lower Miocene units is low. In general, this is also valid for rocks formed during the second (Kozakhurian) isolation of the Eastern Paratethys. However, upwelling along a shelf-break canyon caused deposition of prolific diatomaceous source rocks in the western Black Sea. Overall, Oligocene–Lower Miocene sediments in the Carpathian Basin (Menilite Formation) can generate up to 10 t HC m −2 . Its high petroleum potential is a consequence of the interplay of very high productivity of siliceous organisms and excellent preservation in a deep silled basin. In contrast, the petroleum potential of Oligocene–Lower Miocene (Maikopian) sediments in the Eastern Paratethys is surprisingly low (often <2 t HC m −2 ). It is, therefore, questionable whether these sediments are the only source rocks in the Eastern Paratethys.

Inventory of Onshore Hydrocarbon Seeps in Romania (HYSED-RO Database)

Seeps are the expression of the migration of hydrocarbons from subsurface accumulations to the surface in sedimentary basins. They may represent an important indication of the presence of petroleum (gas and oil) reservoirs and faults, and are a natural source of greenhouse gas (methane) and atmospheric pollutants (ethane, propane) to the atmosphere. Romania is one of the countries with the largest number of seeps in the world, due to the high petroleum potential and active tectonics. Based on a review of the available literature, and on the field surveys performed by the authors during the last 17 years, we report the first comprehensive GIS-based inventory of 470 seeps in Romania (HYSED-RO), including gas seeps (10.4% of the total), oil seeps (11.7%), mud volcanoes (50.4%), gas-rich springs (12.6%), asphalt (solid) seeps (4.3%), unclassified manifestations (4.0%), and uncertain seeps (6.6%). Seeps are typically located in correspondence with major faults and vertical and fractured stratigraphic contacts associated to petroleum reservoirs (anticlines) in low heat flow areas, and their gas-geochemistry reflects that of the subsurface reservoirs. The largest and most active seeps occur in the Carpathian Foredeep, where they release thermogenic gas, and subordinately in the Transylvanian Basin, where gas is mainly microbial. HYSED-RO may represent a key reference for baseline characterization prior to subsurface petroleum extraction, for environmental studies, and atmospheric greenhouse gas emission estimates in Romania.

Geochemistry, composition, and structure of protoasphaltenes in organic matter of recent lacustrine sediments

Asphaltenes and asphaltogene acids of organic matter (OM) of lacustrine sediments in the Novosibirsk and Tomsk Regions of West Siberia have been investigated by applying physical and physicochemical methods (elemental and X-ray diffraction analyses, IR, NMR, and EPR spectroscopy, Rock Eval pyrolysis, and electron microscopy). Compared with asphaltenes of dispersed OM at the early catagenesis stages, asphaltenes of OM at the diagenesis stage have a high number of hydrogen atoms and heteroatoms, a low degree of aromaticity, a low concentration of paramagnetic centers, a large number of carbon atoms in the long paraffin chains and oxygen-containing groups. Tetravalent vanadium is absent from asphaltenes of recent lacustrine sediments, and only complex compounds of copper have been identified. The sediments contain not asphaltenes but their precursors, protoasphaltenes. These are less condensed compounds with a looser nongraphite structure and a rather high petroleum potential. At the diagenesis stage, protoasphaltenes are immature protokerogen blocks.

Geologic prerequisites for high petroleum potential of the northern Siberian Platform

We analyze geologic and geophysical factors enhancing the prerequisites for the high petroleum potential of East Siberia that were formulated by A. A. Trofimuk in 1960. The main updates concern the northern Siberian Platform, where it is indeed possible to significantly increase its petroleum potential and to refine the localization of large and giant, mostly oil accumulations.

The experience in estimating the sedimentary basin petroleum potential on the basis of study of mud volcanic breccia clasts (an Example from the Deep Part of the Gulf of Cadiz)

Mud volcanism is a natural phenomenon well-known for on-shore and off-shore environments. Its major driving forces are deeply seated fluid accumulations and lithology and tectonism favorable for creating overpressure within deep strata with subsequent breakthrough of solid, liquid, and gaseous products of mud volcanism towards a ground surface. The mud breccia clasts provide information about the sedimentary section (up to several kilometers thick) through which the mud volcano erupted. Geochemical investigation of mud breccia clasts with characteristics of source rocks can help in understanding the petroleum potential of entire basin prior to expensive offshore exploration drilling. This is an especially important and useful method for initial estimation of petroleum potential of deep continental margin basins. The method of geochemical investigation of organic matter in the mud breccia clasts allowed to identify the Miocene and Upper Cretaceous clayey and carbonate deposits in the sedimentary sequence in the deep part of the Gulf of Cadiz as having the highest petroleum potential.

Lithologic and facies characteristics of the Lower Cambrian Usolka Formation and its age analogs in the Cis-Yenisei sedimentary basin, West Siberia

Based on the correlation between Lower Cambrian sections of deep wells on the left bank of the Yenisei River and outcrops in the westernmost Yenisei Ridge, the sedimentologic characteristics of the Usolka Formation and coeval deposits are compared. Three paleogeographic regions (subbasins) are distinguished in the Cis-Yenisei basin in Usolka time. The leading role in the sediment genesis was played by the region of barrier reefs stretching northwestward and northward as a ~70 km wide band to their joint with the reefs of the Igarka-Noril’sk facies region in the north. The salt basin east of the barrier reef ridge was a bay of the East Siberian salt basin, separated from the latter by the Yenisei paleoislands (at the place of the Yenisei Ridge). Sedimentation in that basin was controlled by evaporite processes, the supply of terrigenous material from the islands and carbonate debris from the opposite side (barrier reef), and the predominance of storm processes. The subbasin west of the barrier reefs evolved under different scenario. Since the Early Cambrian, a trough has been forming here, which was initially characterized by a regime of starvation and the first appearance of carbonaceous rocks (Lower Churbiga Subformation), regarded as Domanic oil source rocks, in the general Cambrian section. On the estimation of the prospects for the distribution of reservoirs whose origin depends on the facies regularities, the leading role is played by the barrier reef region. Importantly, the Lower Cambrian section of the Cis-Yenisei basin contains two large adjacent paleogeomorphologic structures and the corresponding facies zones of a starved prereef depression with the Domanic oil source rocks of the Lower Churbiga Subformation at the early stage of evolution and a potentially productive barrier reef system with a steep slope toward the basin. The favorable combination of these factors suggests that the Cis-Yenisei basin has a high petroleum potential.

A Comparison between Statistical Analysis and Grey Model Analysis on Assessed Parameters of Petroleum Potential from Organic Materials

This study aims to investigate the impact of changes in the Tmax and Ro% on the assessed parameters (S1, S2, S1+S2, HI, QI, BI, PI, TOC) of petroleum potential of organic materials. The samples studied include coals and coaly shales of Mushan Formation, Shihti Formation and Nanchuang Formation in NW Taiwan, coals and an oil shale from Mainland China, the well-drilled chip samples from NW Australia, in addition to the data of samples were included from literatures. This work will get on the detecting data of 10 parameters (S1, S2, S1+S2, TOC, HI, QI, BI, PI, Ro%, Tmax) and progressing statistical analysis, and focus the study on comparison between grey forecast of grey relational grade and regression model forecast. The results from statistical analysis (include temperature-treated samples were individually subjected to Rock-Eval analysis) of the all parameters data for all samples in this research project, not only be executed a linear regression, curve regression between any two parameters, and multivariate regression, but also be carried on the forecast of grey correlation grade of grey theory (include grey relational generating (Nominal-the-better-:Ro%; Larger-the-better-: Tmax, HI, QI, BI, S2, S1+ S2, S1; smaller-the-better-: TOC, PI) and globalization grey relational grade). So far, obtain roughly the consistency of results from two type predictive analysis. The constructed HI, QI and BI bands were broad at low maturities and gradually narrowed with increasing thermal maturity. The petroleum generation potential is completely exhausted at a vitrinite reflectance of 2.0-2.2% or a Tmax of 510-520°C. An increase in HI and QI suggests extra petroleum potential related to changes in the structure of the organic material. A decline in BI signifies the start of the oil expulsion window and occurs within the vitrinite reflectance range 0.75-1.05 % or a Tmax of 440-455 oC. Furthermore, petroleum potential can be divided into four different parts based on the cross-plot of HI vs. %Ro. The area with the highest petroleum potential is located in sectionⅡ with %Ro=0.6-1.0%, and HI>100. Oil generation potential is rapidly exhausted at section Ⅲ with %Ro >1.0%. This result is in accordance with the regression curve of HI and QI with %Ro based on 97 samples with %Ro=1.0~5.6%.

Surface geochemical exploration for hydrocarbons in the area of prospective structures of the Lublin Trough (Eastern Poland)

The search for crude oil and natural gas deposits is dominated by expensive seismic methods. However, less expensive and faster surface methods are available, which may improve the effectiveness of petroleum exploration. One of these methods is the surface geochemical survey. The objective of this method is to detect, record and analyse the trace amounts of hydrocarbons in soil gas samples. Our paper presents the results of such research carried out over the prospective structures of the Lublin Trough in the Eastern Poland. Three hundred fifty five soil gas samples were collected from 1.2 m depth below the surface, which were analysed by gas chromatographic analysis for their molecular composition. Sampling sites were arranged along 5 sampling lines with 200 m spacing. Maximum concentrations of CH4, total alkanes C2–C4, total alkenes C2–C4, H2, CO2 and O2 detected in our samples were: 0.16 vol.%, 0.95 ppm, 6.79 ppm, 0.37 vol.%, 5.01 vol. % and 21.6 vol.% respectively. The results demonstrate that alkanes recorded in the soil gas which are heavier than methane, originated from the deeper hydrocarbon accumulations. These components migrated to the near-surface zone due to their active microseepage along the tectonic discontinuities and cracks in the overburden. Weak correlation of H2 and CO2 with alkanes were found, which precludes the application of both components as additional prospective indicators in the study area. Diverse activity of partial oxidation of alkanes to alkenes, perhaps due to different rate of microseepage of hydrocarbons, has been determined using the C2H6/C2H4 (C2/C2=) ratio. The presence of numerous tectonic dislocations intensifies the microseepage and increases the amplitudes of geochemical anomalies recorded at the surface. Normalization of concentrations of methane, total alkanes C2–C4 and total alkenes C2–C4 with their of background values, which were calculated for separate subsets of C2/C2= ratio values, significantly reducing the ranges and the amplitudes of hydrocarbons anomalies. It allowed for modification of the anomalous pattern due to diverse activity of partial oxidation of alkanes to alkenes. Statistical analysis of C2H6/C3H8 (C2/C3) ratio values showed that in the study area accumulations of gas condensate and dry gas dominate with the strongest surface geochemical signals.The surface geochemical results were integrated with the structural map of the top of Devonian formations as well as we when displayed as trend integrated with geological cross-sections. The surface alkane anomalies generally occur along the major, NW–SE-trending chain of structural uplifts located between Abramów, Glinnik and Nasutów. This zone is most prospective and indicates the highest petroleum potential. Changes in normalized concentrations of total alkanes C2–C4 allowed the identification of 9 anomalous zones, indicating the presence of deep hydrocarbon sources. The no. 2 anomaly, which was localized at the intersection of the B–B′ and the E–E′ sampling lines, seems to be the most prospective. The accumulations of dry gas or gas condensate likely occur in the anticline formed by Devonian and/or Carboniferous strata. This zone should be opened for confirmation by drilling. The geochemical lead should now be integrated with all available geological/seismic data for prospect development. Our study demonstrates that the results of surface geochemical surveys combined with the results of geological studies and geophysical surveys provide a valuable source of comprehensive information about the explored area.

Investigation of the Various Spectral Decomposition Methods to Detect and Explore Hidden Complex Reef Reservoir Structures and Their Hydrocarbon Potentials in Northwestern Part of the Persian Gulf

The Persian Gulf and its coastal areas are recognized as one of the biggest hydrocarbon basins in the world as world's largest petroleum reservoirs are located through its offshore and onshore oil and gas fields. Coastline countries of the Persian Gulf produce about 25% of the world's oil yearly and they have nearly two-thirds and one-third of the world's crude oil and natural gas reserves, respectively. In the Persian Gulf and south of Iran, Zagros orogeny process has a most important structural role as it causes many petroleum reservoirs into folds with northwest-southeast trends that are parallel with Zagros orogeny direction. However, there is good potential to explore new petroleum reservoirs in the Persian Gulf yet. One of these potential oilfields located northwestern of the Persian Gulf includes high petroleum potential, but with structural complexity and this investigation is focused to explore reservoir in its other horizons, specially Sarvak formation as the famous reservoir in the area. To achieve essential information from reservoir and locating it, we applied two useful seismic methods. Authors considered different advantages of the fast Fourier transform (FFT) and the continuous wavelet transform (CWT) as the most commonly applicable spectral analysis of seismic methods in an experimental investigation besides geological new findings. We found that the FFT can provide a good image from reservoir stratigraphic characteristics; it has specifically proven efficient even in carbonate reservoirs allowing individualization of geological bodies not easily defined in amplitude maps. Besides that, the CWT can provide an accurate and clear image from reservoir structural characteristics and low frequency shadows under petroleum reservoirs. We will prove our claims by using theoretical and experimental evidences. Objectives of this paper, beside geological evidences, are to show abilities of these two methods and to describes how, (1) the FFT method shows the distribution of the hidden reef boundaries and (2) the CWT shows the probable presence of hydrocarbons in purpose structure much better than the original seismic data and others methods.

Analysis of relationships between geochemical parameters of petroleum potential in related source and carbonaceous materials

A worldwide data set of 1,085 samples containing organic matter of the type II/III kerogen from Carboniferous to Cenozoic was used to analyse the evolution of the hydrogen index (HI), quality index (QI), and bitumen index (BI) with increasing thermal maturity. The HImax, QImax and BImax lines were defined, based on statistical analysis and cross-plots of HI, QI and BI versus the vitrinite reflectance (%Ro) and T max (°C). The constructed HI, QI and BI bands were broad at low maturities and gradually narrowed with increasing thermal maturity. The petroleum generation potential is completely exhausted at a vitrinite reflectance of 2.0–2.2 % and T max of 510–520 °C. An increase in HI and QI suggests extra petroleum potential related to changes in the structure of the organic material. A decline in BI signifies the start of the oil window and occurs within the vitrinite reflectance range 0.75–1.05 % and T max of 440–455 °C. Furthermore, petroleum potential can be divided into four different parts based on the cross-plot of HI versus %Ro. The area with the highest petroleum potential is located in “Samples and methods” with %Ro = 0.6–1.0 %, and HI > 100. Oil generation potential is rapidly exhausted at “Results and discussion” with %Ro > 1.0 %. This result is in accordance with the regression curve of HI and QI with %Ro based on 80 samples with %Ro = 1.02–3.43 %. The exponential equation of regression can thus be achieved: HI = 994.81e−1.69Ro and QI = 1,646.2e−2.003Ro (R 2 = 0.72). The worldwide organic material data set defines two range of oil window represented by the upper and lower limits of the BI band: %Ro 0.75–1.95 %, T max 440–525 °C, and %Ro 1.05–1.25 %, T max 455–465 °C, respectively.

Origin of the unusually high dibenzothiophene oils in Tazhong-4 Oilfield of Tarim Basin and its implication in deep petroleum exploration

Unusually high dibenzothiophene (DBT) concentrations are present in the oils from the Tazhong-4 Oilfield in the Tazhong Uplift, Tarim Basin. Positive-ion electrospray ionization Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS) was used in combination with conventional geochemical approaches to unravel the enrichment mechanisms. Significant amounts of S1 species with relatively low DBE values (0–8), i.e., sulfur ethers, mercaptans, thiophenes and benzothiophenes, were detected in three Lower Ordovician oils with high thermal maturity, which were suggested to be the products of thermochemical sulfate reduction (TSR) in the reservoir. The occurrence of TSR was also supported by the coexistence of thiadiamondoids and abundant H2S in the gases associated with the oils. Obviously low concentrations of the DBE=9 S1 species (mainly equivalent to C0–C35 DBTs) compared to its homologues were observed for the three oils which were probably altered by TSR, indicating that no positive relationship existed between TSR and DBTs in this study. The sulfur compounds in the Tazhong-4 oils are quite similar to those in the majority of Lower Ordovician oils characterized by high concentrations of DBTs and dominant DBE=9 S1 species with only small amounts of sulfur compounds with low thermal stability (DBE=0–8), suggesting only a small proportion of sulfur compounds were derived from TSR. It is thermal maturity rather than TSR that has caused the unusually high DBT concentrations in most of the Lower Ordovician oils. We suggest that the unusually high DBT oils in the Tazhong-4 Oilfield are caused by oil mixing from the later charged Lower Ordovician (or perhaps even deeper), with high DBT abundances from the earlier less mature oils, which was supported by our oil mixing experiments and previous relevant investigations as well as abundant authigenic pyrite of hydrothermal origin. We believe that TSR should have occurred in the Tazhong Uplift based on our FT-ICR MS results. However, normal sulfur compounds were detected in most oils and no increase of δ13C2H6–δ13C4H10 was observed for the gas hydrocarbons, suggesting only a slight alteration of the oils by TSR currently and/or recently. We suspect that the abnormal sulfur compounds in the Lower Ordovician oils might also be a result of deep oil mixing, which might imply a deeper petroliferous horizon, i.e., Cambrian, with a high petroleum potential. This study is important to further deep petroleum exploration in the area.

The subsurface record of the Late Palaeozoic glaciation in the Chaco Basin, Bolivia

Abstract The Late Palaeozoic glaciation was the longest of the Phanerozoic era. It is recorded in numerous Gondwanan basins, with some, such as the Chaco Basin, having a high petroleum potential. In this basin, the quality of the available seismic, well and outcrop data permits us to characterize the Late Palaeozoic glacial record. Palaeovalleys that are c . 500 m deep and c . 7 km wide have been analysed here. Focusing on the glaciogenic Carboniferous deposits, seismic data with well ties and outcrop analogues provide new sedimentological insights. The palaeovalley infill is imaged as a chaotic seismic facies overlain by an aggrading–prograding prism, interpreted as tillites covered by a fluvio-deltaic system. Tillites form both under the ice and during rapid ice recession, whereas fluvio-deltaic systems can only originate from a stable ice margin and last until the ice sheets withdraw inland. These two depositional modes are repeated several times, generating a progressive burial of the Carboniferous palaeovalleys. This succession of erosions and fills records major glacial stages, including a series of glacial and interglacial phases from the Late Devonian to the Early Permian. Depicting the Late Palaeozoic glacial history of the Chaco Basin seems crucial for the localization of potential good reservoirs.

Statistical analysis of relations between petrographic and geochemical indices of oil generation potential in organic matter

To establish reliable indices for the synthetic assessment of petroleum potential using reworked sediment from mixed datasets, multivariate statistical analysis and cross-plots were used. New guidelines for improved assessment of generative potential and thermal maturity are suggested. Based on statistical analysis and cross-plots of HI, QI and BI versus the vitrinite reflectance (%Ro) and Tmax (°C), the HImax, QImax and BImax lines are defined between the vertex of the upper and lower limits of the HI-band, QI-band and BI-band as defined by a majority of the samples. The constructed HI, QI and BI bands were broad at low maturities and gradually narrowed with increasing thermal maturity. The petroleum generation potential is completely exhausted at a vitrinite reflectance of 2.0–2.2% or a Tmax of 510–520°C. An increase in HI and QI suggests extra petroleum potential related to changes in the structure of the organic material. A decline in BI signifies the start of the oil expulsion window and occurs within the vitrinite reflectance range 0.75–1.05% or a Tmax of 440–455°C. Furthermore, petroleum potential can be divided into four different parts based on the cross-plot of HI versus %Ro. The area with the highest petroleum potential is located in section II with %Ro = 0.6–1.0%, and HI > 100. Oil generation potential is rapidly exhausted at section III with %Ro > 1.0%. This result is in accordance with the regression curve of HI and QI with %Ro based on 80 samples with %Ro = 1.02–3.43%. The exponential equation of regression can thus be achieved: curve, HI = 994.81e−1.69Ro (R2 = 0.72) and QI = 1646.2e−2.003Ro (R2 = 0.72). The worldwide organic material dataset defines two oil expulsion windows represented by the upper and lower limits of the BI band: %Ro ~ 0.75 to ~1.95% or Tmax ~ 440 to ~525°C, and %Ro ~ 1.05 to ~1.25% or Tmax ~ 455 to ~465°C, respectively. The start of the oil expulsion window occurs within the %Ro range of ~0.75–1.05 %Ro or the Tmax range ~440–455°C and the total oil window extends to %Ro = ~ 1.25–1.95 or Tmax = ~ 465–525°C.