Oil Source Rocks Research Articles

Structure and petroleum potential of the Laptev Sea region

Analysis of specific features of the structure and petroleum potential of the Aptian Laptev Sea region is presented. Age and lithological composition of the sedimentary cover of the shelf are predicted. Oil- and-gas source sequences, catagenetic zonation of organic matter, and potential petroliferous objects in large structural zones are characterized. It is supposed that oil likely played a significant role in the phase composition of naphtides. Its formation in the land and coastal shelf zone was stipulated by the presence of high-quality oil source rocks in the Riphean–Phanerozoic cover of the Siberian Craton. In the remaining part of the shelf, where the Aptian–Cenozoic rift system is widespread, oil can also be present in pools, because the rocks likely accommodate not only gas source rocks, but also deltaic and prodeltaic oil-and-gas source rocks that are located in the main oil formation zone. The above properties are specific features of the study region, and its hydrocarbon potential will be increasing steadily with the shelf development.

Evidence of bottom-redox conditions during oceanic anoxic event 2 (OAE2) in Wadi Bazina, Northern Tunisia (Southern Tethyan margin)

Detailed chemostratigraphy across the Cenomanian-Turonian boundary in northern Tunisia points to several prevailing paleoceanographic conditions during the deposition of organic-rich beds of Bahloul Formation. The sedimentological study shows that there is no correlation between color and CaCO3 content because both dark and light-colored intervals of Bahloul Formation are carbonate-rich. Stable isotope analysis displays a positive carbon isotope excursion characterized by four significant peaks (I to IV) which are ranging from 3.2 to 3.5‰. These peaks represent episodes of elevated rates of organic carbon burial during the C/T oceanic anoxic event (C/T boundary OAE2). The Cenomanian-Turonian boundary could be situated between the third isotopic peak and the filament event. The total organic carbon (TOC) measurements show values ranging from 0.28 to 6.19% with average value of 3.5%. This indicates that the Bahloul Formation shale is a very good oil source rock. The Hydrogen Index (HI) values range from 359 to 698 mg HC/g TOC. The T max values range from 390 to 438 °C. Binary diagrams HI vs. T max indicate a type II with values falling within the immature organic-matter range. The concentrations major elements reveal low values of Ti and K. The correlation between Al and Ti and K shows a significant correlation pointing to homogeneous provenance. Primary productivity indicators (Cu, Ba, and Ni) record its association with organic matter. Redox-sensitive elements such as U, V, and Mo and the high values of V/(V + Ni) ratio indicate a strongly reducing environment which led to the better preservation of the organic matter.

Study of thermal maturation processes of sulfur-rich source rock using compound specific sulfur isotope analysis

Semi-open pyrolysis experiments were conducted on a thermally immature, organic and sulfur-rich source rock (Ghareb Formation, Israel). Structural and sulfur isotope ratio (34S/32S) changes in specific organic sulfur compounds were studied along with bulk sulfur phases (H2S, kerogen, oil) during thermal maturation and oil formation. Oil, gas and rock samples were collected sequentially at several points along the maturation path and were analyzed. In addition, four natural crude oils from Israel were analyzed and the results were compared to the pyrolytic oils.The results showed relatively large δ34S variability (∼10‰) of the organic sulfur compounds (OSCs) in the bitumen of the unheated rock and first pyrolytic oil. This variability was probably a remnant of the original sulfur isotopic signature acquired during the sulfurization of the organic matter in the early diagenetic process. At later stages of thermal maturation, the variability of the sulfur isotopic values in the kerogen gradually decreased to ∼2‰. Three mechanisms were suggested to explain the structural changes and isotopic fractionations of OSCs in the kerogen and generated oils: (A) Cleavage of weak SS and CS bonds leading to the release of large amounts of H2S and to cyclization of the precursors in the kerogen with small fractionations. Thus, the OSCs released by this mechanism preserved their distinct δ34S values. (B) Re-reaction of the released S species with hydrocarbons and generation of new OSCs within the kerogen (or bitumen) matrix. (C) Cleavage of stronger CC bonds and transformation of OSCs to create more stable compounds (e.g. dibenzothiophenes) from multiple sulfur sources. Mechanisms (B) and (C) homogenized the δ34S values of the different OSCs which reflected that of the bulk kerogen.The bulk organic sulfur phases (bitumen, oil, kerogen) were 34S enriched by<1‰ despite large amounts of 34S-depleted H2S (53% of total S) that was released continuously (“open system”). Therefore, the preferential loss of H2S during thermal maturation may not be responsible to the 34S enrichment of oils as reported in some petroleum basins. The overall outcome of the maturation process yields OSCs with δ34S values that closely reflect the kerogen and can be used as a fingerprint for oil-oil and oil-source rock correlation over wide ranges of thermal maturity. The applicability of such correlation is demonstrated by the very good correlation of δ34S values of specific OSCs between artificial and natural oil samples.

Geochemistry characteristics of high-mature source rock extracts and using various approaches to discriminate the indigenity

ABSTRACTA total of 11 core samples of Cambrian source rocks and 2 Cambrian-sourced crude oils (TD2, T904) were analyzed. High content of total organic matters indicates a good to excellent source rocks. However, high maturity was indicated by high Tmax values and very low content of HI index and S1+S2. The relative intact alkanes can be detected in most samples with no odd/even predominance. A series of relatively high abundance of terpanes and steranes can be detected on m/z 191 and m/z 217 chromatograms, respectively. Ratios of C21/C23 tricyclic terpanes are greater than 1.0. All samples of Yuli 1 and Tadong 2 show high abundance of C26∼C28 triaromatic steroids and triaromatic dinosteroids, with ratios of (C26+C27) TAS/C28TAS and TDSI greater than 1.0 and 0.62, respectively. Oil source rocks correlation between sampled rock extracts and typical Cambrian oils reveals that high-postmature Cambrian source rock extracts are well consistent with those two typical Cambrian oils that are usually used as end members oils represented by Cambrian-sourced oils. Three approaches were proposed to discriminate indigenity of high-postmature source rocks.

Lower limits and grading evaluation criteria of tight oil source rocks of southern Songliao Basin, NE China

Abstract Taking the southern Songliao Basin as the target area, the hydrocarbon expulsion volume from source rocks has been quantitatively evaluated in this paper, based on the material balance method. Employing the “Overpressure” module of PetroMod software, the overpressure history of the source rocks was evaluated. According to the relationships between hydrocarbon expulsion rate, residual organic carbon content and overpressure within the source rocks, the lower limits of expulsion from tight oil source rocks were determined: a hydrocarbon expulsion amount of 2 mg/g, residual hydrocarbon content of 0.8%, and overpressure of 1 MPa. The source rocks with hydrocarbon expulsion amounts > 8 mg/g, a residual organic carbon content > 2.0%, and overpressure > 7 MPa were defined as excellent source rocks. As a result, tight oil source rocks can be divided into three types, excellent source rocks (type I), inefficient source rocks (type II) and non-productive source rocks (type III). The actual application in the southern Songliao Basin shows that the excellent source rocks have an obvious control on the planar and vertical distribution of tight oil discoveries, areas with excellent source rocks and nearby formations are favorable for the accumulation of tight oil.

Seismic reservoir characterization of Duvernay shale with quantitative interpretation and induced seismicity considerations — A case study

The Devonian Duvernay Formation in northwest central Alberta, Canada, has become a hot play in the past few years due to its richness in liquid and gaseous hydrocarbon resources. The oil and gas generation in this shale formation made it the source rock for many oil and gas fields in its vicinity. We attempt to showcase the characterization of Duvernay Formation using 3D multicomponent seismic data and integrating it with the available well log and other relevant data. This has been done by deriving rock-physics parameters (Young’s modulus and Poisson’s ratio) through deterministic simultaneous and joint impedance inversion, with appropriate quantitative interpretation. In particular, we determine the brittleness of the Duvernay interval, which helps us determine the sweet spots therein. The scope of this characterization exercise was extended to explore the induced seismicity observed in the area (i.e., earthquakes of magnitude [Formula: see text]) that is perceived to be associated with hydraulic fracture stimulation of the Duvernay. This has been a cause of media coverage lately. We attempt to integrate our results with the induced seismicity data available in the public domain and elaborate on our learning experience gained so far.

Crude oil families in the Euphrates Graben (Syria)

The most petroliferous province in Syria is the Euphrates Graben system in the eastern part of the country. The source of the produced light and heavy oils has been a matter of debate from a petroleum geochemistry perspective as there are several possible source rock and just one proven source rock (R'mah formation). Based on gross composition and oil-oil correlation of biomarker and non-biomarker characteristics, three oil families have here been identified in the study area. Crude oils of Family 1 have been found to be generated from a marine and clay-rich source rock that is older than Jurassic in age based on age-related biomarker parameters (steranes and nordiacholestane ratios). Maturity-related parameters (aliphatic biomarkers and diamondoids) signal that the source of this oil family had a high maturation level. These features fit very well to the Tanf Formation (Abba Group) which is equivalent to Lower Silurian Hot Shales found elsewhere in the Middle East and North Africa. However, the Upper Cretaceous R'mah Formation and Shiranish Formation were found to be responsible for generating the majority of the crude oils studied (Family 2). Compositional and molecular differences between Families 2A and 2B were attributed to facies and subtle maturation variations. Geochemical oil-source rock correlations indicate that Family 2A was most likely sourced from the Shiranish Formation, while Family 2B was sourced from the R'mah Formation. Secondary alteration processes influenced bulk petroleum composition, most notably the depletion of light ends and the lowering of API gravity, particularly in the northwestern part of the graben.

Formation and distribution characteristics of Proterozoic\u2013Lower Paleozoic marine giant oil and gas fields worldwide

There are rich oil and gas resources in marine carbonate strata worldwide. Although most of the oil and gas reserves discovered so far are mainly distributed in Mesozoic, Cenozoic, and upper Paleozoic strata, oil and gas exploration in the Proterozoic–Lower Paleozoic (PLP) strata—the oldest marine strata—has been very limited. To more clearly understand the oil and gas formation conditions and distributions in the PLP marine carbonate strata, we analyzed and characterized the petroleum geological conditions, oil and gas reservoir types, and their distributions in thirteen giant oil and gas fields worldwide. This study reveals the main factors controlling their formation and distribution. Our analyses show that the source rocks for these giant oil and gas fields are mainly shale with a great abundance of type I–II organic matter and a high thermal evolution extent. The reservoirs are mainly gas reservoirs, and the reservoir rocks are dominated by dolomite. The reservoir types are mainly karst and reef–shoal bodies with well-developed dissolved pores and cavities, intercrystalline pores, and fractures. These reservoirs are highly heterogeneous. The burial depth of the reservoirs is highly variable and somewhat negatively correlated to the porosity. The cap rocks are mainly thick evaporites and shales, with the thickness of the cap rocks positively correlated to the oil and gas reserves. The development of high-quality evaporite cap rock is highly favorable for oil and gas preservation. We identified four hydrocarbon generation models, and that the major source rocks have undergone a long period of burial and thermal evolution and are characterized by early and long periods of hydrocarbon generation. These giant oil and gas fields have diverse types of reservoirs and are mainly distributed in paleo-uplifts, slope zones, and platform margin reef-shoal bodies. The main factors that control their formation and distribution were identified, enabling the prediction of new favorable areas for oil and gas exploration.

The petroleum system of the Tenere Basin: oil geochemistry from the SH-1 wildcat well in eastern Niger

The SH-1 wildcat well, firstly encountering oil, proved the existence of a working petroleum system in the Tenere Basin, but the origin of oil and its generation history is not fully understood. In this regard, one crude oil and nine Upper Cretaceous source rock samples from the SH-1 wildcat well in the Tenere Basin were characterized by a variety of biomarker parameters and stable carbon isotopic composition. The oil from the Tenere Basin displays a low pristine/phytane (Pr/Ph) ratio, low C 29 /C 30 and C 35 /C 34 hopane ratios, low C 22 /C 21 and high C 24 /C 23 tricyclic terpane ratios, and high gammacerane index (gammacerane/C 30 hopane), suggesting shale source rocks deposited under an anoxic and relatively high-salinity environment. Relatively high C 29 sterane concentrations, a low value of the regular steranes/17 α (H)-hopanes ratio and a canonical variable from stable carbon isotopic composition larger than 0.47 indicate that the oil is mainly derived from terrestrial higher plants. Both aromatic maturity parameters and sterane isomerization parameters suggest that the oil was generated from an early mature source rock. Correlation between oils from the Tenere Basin and those from the Termit Basin confirms that these oils belong to the same genetic family. The oil–source rock correlation suggests that the oil from the Tenere Basin originated from the Upper Cretaceous marine source rocks, and the Yogou Formation can be considered as effective source potential.

Basin modeling of the Late Miocene Zeit source rock in the Sudanese portion of Red Sea Basin: Implication for hydrocarbon generation and expulsion history

The Late Miocene Zeit Formation is exposed in the Red Sea Basin of Sudan and represents an important oil-source rock. In this study, five (5) exploratory wells along Red Sea Basin of Sudan are used to model the petroleum generation and expulsion history of the Zeit Formation. Burial/thermal models illustrate that the Red Sea is an extensional rift basin and initially developed during the Late Eocene to Oligocene. Heat flow models show that the present-day heat flow values in the area are between 60 and 109 mW/m2. The variation in values of the heat flow can be linked to the raise in the geothermal gradient from margins of the basin towards offshore basin. The offshore basin is an axial area with thick burial depth, which is the principal heat flow source.The paleo-heat flow values of the basin are approximately from 95 to 260 mW/m2, increased from Oligocene to Early Pliocene and then decreased exponentially prior to Late Pliocene. This high paleo-heat flow had a considerable effect on the source rock maturation and cooking of the organic matter. The maturity history models indicate that the Zeit Formation source rock passed the late oil-window and converted the oil generated to gas during the Late Miocene.The basin models also indicate that the petroleum was expelled from the Zeit source rock during the Late Miocene (>7 Ma) and it continues to present-day, with transformation ratio of more than 50%. Therefore, the Zeit Formation acts as an effective source rock where significant amounts of petroleum are expected to be generated in the Red Sea Basin.

Hydrocarbon composition and structural parameters of resins and asphaltenes of naphthenic oils of northern West Siberia

The composition of saturated and aromatic hydrocarbons and the structural-group characteristics of resins and asphaltenes in four oils of northern West Siberia have been studied. As follows from the distribution of hydrocarbons, the Cenomanian oils (pools in the beds PK and K2c) of the Russkoe, Barsukovskoe, and Pangodinskoe fields are naphthenic and the Pangodinskoe oil sample from the Lower Cretaceous pool (bed BN9) is methanoic. The hydrocarbon composition pattern of the saturated fraction and the characteristics of the heterocyclic components of these oils point to their formation from dispersed organic matter of mixed genesis in the oil window. Hence, the oil source rocks are localized at depths much greater than the present-day level of the oil pools. Secondary (cryptohypergene) alterations (oxidation and biodegradation) in the shallow-depth oils determined their current predominantly naphthenic composition and considerably hamper reconstruction of the types of initial dispersed organic matter. We assume that the mixed genetic type of the studied oils is not only due to their heterogeneous source but also due to the reorganization of primary oil pools at the Cenozoic stage of tectogenesis. The Cenomanian Russkoe and Pangodinskoe naphthenic oils are saturated with adamantoids, which can be selectively accumulated during biodegradation.

The role of Domanik deposits in the formation of oil pools in the central areas of the Volga-Ural petroleum province (Buzuluk depression)

The results of genetic typification of oils and bitumens from oil source rocks (OSR) of the Buzuluk depression are presented. Crude oils within the study area were divided into five genetic types, which differ both in organic-matter composition and in the conditions of its accumulation. Characteristic of the potential source rock was given for each oil type. Oil-to-source rock bitumen correlation studies were performed using biomarker distribution. The studies have shown that only oils from the Upper Devonian-Middle Carboniferous deposits (oils of Types I and II) were generated by Domanik rocks. Middle Devonian oils (Types III-V) are not related to the Domanik strata. The identified relationships between oils and organic matter of different facies-genetic types of Domanikoid-Domanikite OSR can be used to refine the stratigraphic volume and geographic distribution boundaries of Domanik deposits in the study area.

Geochemistry of Late Devonian oils of the Timan-Pechora basin

The composition of biomarkers and aromatic hydrocarbons of Late Devonian oils of the Timan-Pechora Basin has been studied. It shows that the organic matter of oil-generating deposits is at the close stages of thermal maturity, which are within the early and middle stages of the oil window. Five groups of oils have been recognized, three of which were generated by organic matter of Domanik deposits and the other two formed from organic matter of another source. Most of the studied oil samples contain derivates of isorenieratene indicating that the organic matter of oil source rocks formed in the photic-zone anoxia of the paleobasin.

New data on the petroleum potential of the Aldan-Maya depression

The Vendian-Riphean section of the Ust’-Maiskaya-366 parametric well was studied. The well is the first deep well drilled in the central part of the Aldan-Maya depression, in the southeast of the Siberian Platform. New probable oil source rocks within the Upper and Middle Riphean deposits have been identified based on core analysis supported by geological-survey data. We make a geochemical description of organic matter from these deposits and report the composition of abundant migrated bitumens discovered in the Ust’-Maiskaya-366 well section. The petroleum content in the Aldan-Maya depression has been predicted with regard to the new geological and geochemical data.

Geochemical characteristics and reservoir continuity of Silurian Acacus in Ghadames Basin, Southern Tunisia

The present work is dealing with the study of lateral and vertical continuity of the multi-layers Acacus reservoir (Ghadames Basin-Southern Tunisia) using the distribution of hydrocarbon fraction. For this purpose, oil–oil and source rock–oil correlations as well as the composition of the light fractions and a number of saturate and aromatic biomarkers parameters, including C35/C34 hopanes and DBT/P, have been investigated.Based on the ratios of light fraction and their fingerprints, the Acacus reservoir from Well1 and Well2 have found to be laterally non-connected although the hydrocarbons they contain have the same source rock. Moreover, the two oil samples from two different Acacus reservoir layers crossed by Well3-A3 and A9, display a similar hydrocarbons distribution, suggesting vertical reservoir continuity.On the other hand, the biomarker distributions of the oils samples and source rocks assess a Silurian “Hot shale” that is the source rock feeding the Acacus reservoir. The biomarker distribution is characterized by high tricyclic terpanes contents compared to hopanes for the Silurian source rock and the two crude oils. This result is also confirmed by the dendrogram that precludes the Devonian source rocks as a source rock in the study area.

The 35/9-7 Skarfjell discovery: a genuine stratigraphic trap, NE North Sea, Norway

Abstract The Skarfjell oil and gas discovery, situated 50 km north of the Troll Field in the NE North Sea, was discovered by well 35/9-7 and was appraised by three additional wells operated by Wintershall, in the period 2012–14. The Skarfjell discovery is an example of a combined structural/stratigraphic trap. The trap formed along the northern edge of a deep WNW–ESE-trending submarine canyon, which was created by Volgian erosion of intra-Heather, Oxfordian-aged sandstones and then infilled with Draupne Formation shales. This mud-filled canyon forms the top and side seal, with the bottom seal provided by Heather shales. The reservoir comprises mid-Oxfordian deep-water turbidites and sediment gravity flows, which formed in response to tectonic hinterland uplift and erosion of the basin margin, 10–20 km to the east. The Skarfjell discovery contains light oil and gas, and may be subdivided into Skarfjell West, in which the main oil reservoir and gas cap have known contacts, and Skarfjell Southeast, which comprises thinner oil and gas reservoirs with slightly lower pressure and unknown hydrocarbon contacts. The Upper Jurassic Draupne and Heather formations are excellent source rocks in the study area. They have generated large volumes of oil and gas reservoired in fields, and discoveries for which the dominant source rock and its maturity have been established by oil to source rock correlation and geochemical biomarker analysis. The Skarfjell fluids were expelled from mid-mature oil source rocks of mixed Heather and Draupne Formation origin. The recoverable resources are estimated at between 9 and 16 million standard cubic metres (Sm 3 ) of recoverable oil and condensate, and 4–6 billion Sm 3 of recoverable gas. The Skarfjell discovery is currently in the pre-development phase and is expected to come on stream in 2021.

The lower part of the first member of the Shahejie formation (Es1x) as a source rock for oil found in Lixian Slope, Raoyang Sag, Bohai Bay Basin, Northern China

The Es1x sub-member (lower part of the first member of Shahejie Formation), which consists mainly of dark oil shale and mudstone, is well developed in Lixian Slope, Raoyang Sag, Bohai Bay Basin, northern China. The samples from Es1x sub-member were subjected to kerogen petrographic microscope, Rock-Eval, extractable organic material (EOM), and vitrinite reflectance (R o) analyses, respectively. In addition, some samples respectively from the Es3x and Es1x source rocks as well as six crude oil samples from Shahejie Formation of Lixian Slope were subjected to gas chromatography–mass spectrometry (GC–MS) analyses. Based on these geochemical analyses and petrographic analyses, this study provides an overview on the type, richness, thermal maturity, and hydrocarbon generation potential of organic matter in Es1x sub-member, as well as a successful oil–source correlation in Lixian Slope. The total organic carbon (TOC) content of Es1x sub-member samples varies from 0.07 to 6.20%, suggesting that this interval is heterogeneous but contains excellent source rocks. This is further corroborated by hydrocarbon yields (S 2) and extractable organic matter (EOM). Both maceral composition and HI values indicate that organic matter is mostly derived from aquatic organisms. This is supported by n-alkane-isoprenoid ratios (pristane/n-C17 alkane (Pr/n-C17) versus phytane/n-C18 alkane (Ph/n-C18)). The microscope of kerogen in Es1x sub-member samples shows that the mixed-type I/III kerogen is dominant. This is supported by the hydrogen index (HI) values of Es1x sub-member samples. Vitrinite reflectance (R o) values of Es1x source rock samples are between 0.32 and 0.97%, with most of them being lower than 0.7% indicating immature to low maturity levels. T max and production index (PI) values are in line with R o value-based maturity assignments. The n-alkanes and biomarker distributions in crude oils and Es1x source rock samples indicate presence of low-maturity oils derived from organic matter most likely deposited under anoxic, strongly reducing conditions in a lacustrine, brackish to saline/hypersaline water environment. This similarity suggests that crude oils of the Lixian Slope were predominantly sourced from the Es1x sub-member. Es3x (lower part of the third member of Shahejie Formation) source rock samples exhibit different properties that are more in line with freshwater depositional environments.

Origin and history of the oils in the Lawton oil field, southwestern Oklahoma

The Lawton oil field is located on the Wichita Mountain uplift in southwestern Oklahoma. This study focused on addressing three problems related to the Lawton oil field: (a) what is (are) the source(s) of the oils; (b) have the oils been subjected to alteration since emplacement; and (c) what is the filling history of the field? Eighteen oils and one seep sample were collected and characterized by a variety of geochemical techniques including bulk composition, biomarkers, and stable carbon isotopes in order to address these questions. Source rocks in this region are absent following the Pennsylvanian-age Wichita orogeny but biomarkers and stable isotopic data suggest the source of these oils is probably the Woodford Shale. Despite the fact that all of these oils were recovered from reservoirs at depths between 125 and 1,000 ft (38 and 305 m), none of them appeared to be extensively biodegraded as manifested by the abundance of the complete range of n-alkanes. However the presence of 25-norhopanes in all eighteen samples suggests that these oils are mixtures of various proportions of degraded and non-degraded (or slightly degraded) oils. The seep sample, and some oils, have a relatively high abundance of the C32 ββ 22R hopanoic acid, relative to the C31 ββ 22R hopanoic acid, with the presence of these ββ 22R hopanoic acids suggesting the oils have been degraded aerobically at some point in their history. It was also noted that the concentration of the C31 ββ 22R hopanoic acid is higher in the shallower reservoirs than in the deeper reservoirs possibly indicating slightly higher levels of degradation in the shallower reservoirs compared to the deeper reservoirs. A hydrocarbon accumulation model has been proposed for this field based on two main reservoir charging periods. The initial charge of crude oil was biodegraded, probably under anaerobic conditions. The second charging period took place after (or together with) the uplift of the Wichita Mountains and subsidence of the southern part of the Anadarko Basin leading to deeper burial of the source rock and production of higher maturity oil, which subsequently filled the reservoirs containing the degraded oil and may still be recharging these shallow reservoirs today.

Geomechanical and petrophysical properties of mudrocks: introduction

Abstract Mudstones (shales) are of particular importance as the source rocks for oil and gas, and increasingly so as the reservoirs for unconventional hydrocarbons. They are also the most common sedimentary rocks on Earth, and, hence, are frequently encountered in excavations and foundations for buildings. These factors point to a pressing need to develop an increased fundamental understanding of their geomechanical and petrophysical properties. The mineral content of mudstones has a dominant effect on their mechanical properties. Presence of clay minerals within them results in plasticity and ductility that can pose particular engineering challenges, but swelling clays in particular can lead to serious problems of mechanical stability of boreholes and in construction. Good hydraulic fracture performance is linked to brittleness and high elastic moduli. This in turn is favoured by high silica or carbonate content and diagenetic cementation. Permeability to fluids depends on the interconnectivity of storage pores through orientated crack networks. New advances in imaging technologies are permitting very-high-resolution three-dimensional imaging down to the nanometre scale. Such studies will eventually lead to technological advances that exploit more effectively these enigmatic rocks.

Модель формирования нефтегазоносности в отложениях терригенного девона южных районов Пермского края

Нефтегазообразование – длительный сложный и многофакторный процесс, в котором выделяют такие основные стадии, как формирование глубинных нефтематеринских свит, генерация нефти глубинными нефтематеринскими свитами, формирование флюидоупоров, миграция и первичная аккумуляция нефти, деструкция нефти. С целью поисков и разведки нефтегазоносных месторождений необходимы проведение детального изучения каждой из перечисленных стадий и установление особенностей конкретной территории. Такой комплексный подход позволяет более эффективно проводить геолого-разведочные работы.