At present, when estimating the state of the resource base and the general forecast for the development of oil production, ones often operate with the reservesto-production ratio, which reflects, as it is believed, a guaranteed time for involving current recoverable reserves in active development. However, the terms (numbers) differ significantly. In this regard, it seems appropriate to once again discuss the content of the commonly used ratio, the differences in approaches to its estimation and use in our country and abroad, as well as the possibility of using it when forecasting production and the need for an increase in reserves.

The following problem is solved by the present research: the probable sources of Paleozoic hydrocarbon deposits are determined on the basis of modeling the hydrocarbon foci of generation Paleozoic-Mesozoic oil source formations (for example, the southeast of Western Siberia, Tomsk Region). The research area is the lands Ostanino field group: the Selveikin area of deep drilling, the Ostaninskoye and Gerasimovskoye oil and gas condensate fields. Pre-Jurassic strata with oil source potential, including the Paleozoic Larinskaya (S₁ lr), Mirnaya (D₁ ³ mr), Chuzikskaya (D₂ cz), Chaginskaya (D₃ cg) and Kehoregskaya (C₁ kh) formations, as well as Jurassic Bazhenovskaya (J₃ bg) and Tyumenskaya (J₁-2tm ) formations, and, accordingly, the reservoirs of the weathering crust and bed-rock Paleozoic reservoirs are the objects of study. The subject of analysis was selected in accordance with the concept of the geothermal regime of the subsoil, as a leading factor in the implementation of the generation potential of the parent sediments. The research methods are digital paleotemperature modeling and historical-geological analysis.
The results and conclusions concerning the fundamental problems of “Paleozoic oil” are obtained. 1. Source of the Paleozoic oil deposits can be both the Domanic type rocks of the Paleozoic formations and the Jurassic oil source formations. Thus, both upward vertical interstratal HC migration and downward HC migration can take place. Therefore, the two concepts of “main source” are compatible and should not be considered, as often, orthodoxly alternative. 2. The domanicoid rocks of the Paleozoic formations are most likely the source for Paleozoic gas and gas condensate deposits. 3. Paleozoic formations the roof of the bed-rock Paleozoic (on the Ostankinskaya group of fields – C₁ kh and D₃ cg) can be only the source of the «Paleozoic oil» and gas deposits in the PreJurassic oil and gas complex. 4. Bazhenov formation – J₃ bg may be the “Jurassic” source of oil deposits in the Pre-Jurassic oil and gas complex. The results were obtained and conclusions were drawn concerning the applied (search) aspects of the problem: 1. Results additionally substantiate the author’s search criterion for the oil and gas content of the Paleozoic – these are anomalous geophysical and petrophysical characteristics of the Jurassic section. 2. The absence of hydrocarbon deposits in the Jurassic section is most likely a negative sign of the Paleozoic oil and gas content. 4. The low density of the modern heat flow (less than 40 mW/m² ) is most likely a negative sign of oil deposits in the Paleozoic. 3. High paleotemperatures in terms of VR (more than 175^o C) are most likely a negative sign of oil and gas deposits in the Paleozoic. 4. Reasons have been obtained to state that oil deposits in the Paleozoic cannot be richer than oil deposits in the Jurassic.

This work is a continuation of a cycle of studies on the generalization of geochemical information on the content of elements in the composition of rocks and oils in the area of the Ukhta anticline of Southern Timan region. Based on the values of yttrium (Y/Ho) and cerium anomalies (Ce sample/Ce*PAAS) established in modern sedimentary basins, the studied rocks of the Upper Devonian are divided according to the conditions of formation and transformation into predominantly hydrothermal and hydrogenous. It is shown that, depending on these conditions; zones of hydrothermal and hydrogenous mineralization with an increased content of Zn, Cu, Co, V, Mn, and Mo are formed. As a result of a comparative analysis of the content of elements in oils and the values of geochemical ratios U/Th, V/Ba, Th/Ba, As/Ba, three types of oils were identified: Yaregsky, Nizhnechutinsky high-temperature, and Nizhnechutinsky low-temperature. The values of these indicators are considered as search criteria for a certain type of oil.

Paper shows the information about the geological and geophysical exploration of Tambeyskoye natural gas field located in the north of the Yamal Peninsula. The problems with mapping of natural gas deposits in Cretaceous and Jurassic formations are described. The results of formation thickness analysis are presented in order to explain the reasons for the unprecedented concentration of separate natural gas accumulations and the heterogeneous saturation of massive reservoirs in Cretaceous formations. The method of paleotectonic analysis is briefly described, the initial data are reported. Structural and isopach maps are presented. Structural elements and their evolution in Jurassic and Cretaceous time are presented. It was concluded that different structural elements of the work area transformed quite independently until the end of Cenomanian. The modern shape of North Tambey uplift was forming during the Neogene to Quarter age. Natural gas bearing reservoirs in Jurassic formation with the overpressure were reported. The young age of the North Tambey uplift, the unprecedented concentration of separate natural gas accumulations, the and the heterogeneous saturation of massive reservoirs in Cretaceous formations, overpressure in Jurassic formation – all these facts show that the Tambeyskoye natural gas field is under active gas accumulation. Hydrocarbon gases coming from deep Jurassic formations and it was not enough time for gas accumulations to be distributed over the reservoirs of Cretaceous.

The geological study of reservoirs of heavy oil confined to the deposits of the Sheshma horizon, for further involvement of deposits in pilot production, is an expensive project in itself due to the high viscosity of oil from 200 to 200,000 MPa∙s and changes in the depth of the productive formation from 100 up to 500 m. It’s advisable to exclude all kinds of factors, including geological ones, leading to additional costs in the development of heavy oil deposits in an unstable economic situation.
The purpose is determining of impact palaeovalley on the efficiency of wells using the example of heavy oil deposits. For the analysis authors have applied, materials the estimation of reserves, laboratory researches and macro descriptions of the core, the results of structural and geomorphological studies, and development parameters.
It is viewed heavy oil deposits of the Sheshma horizon, complicated by palevalley, and geological structure. The porosity-permeability properties and characteristics of the bedding are given. The authors’re determined areas of palaeovalley the drilled wells, a macro description of the core and cuttings in the palaeovalley part are given. Zones of deconsolidation of the Upper Permian terrigenous deposits are identified by results of structural and geomorphological studies. A comparison of the map of predictive fracturing with the map of Pliocene formations characterizing the genesis of the palevalley is made. The authors’re comparisoned the operational capabilities of wells with the location of the wellhead in the palaeovalley zone and outside the palaeovalley. Recommendations for the design of horizontal wells complicated by palaeovalleys are determined.

The results of laboratory studies of nearly 1,300 samples from 50 wells of reservoirs of three productive terrigenous horizons represented by sandstones and siltstones are considered. Intergranular and fractured components mainly make up the porosity structure of reservoirs and their values influence the main parameters of rocks, including filtration-capacitive properties of reservoirs, and determine the processes of hydrocarbon field development. The spatial distribution of the intergranular and fractured components of reservoir porosity affects the development and exploitation of oil and gas reservoirs and determines the relevance of this study. The values of the fracture and intergranular component of porosity were determined by the author’s method using data on open porosity and the rate of elastic wave propagation in rock samples and the mineral skeleton of these samples during the simulation of reservoir conditions. A mosaic area distribution of fractured porosity values, caused by a long geological and tectonic history of the area development, was revealed. We identified zones of increased fractured porosity up to 0.7–0.8 % (percent absolute porosity) in the north and center of the western part of the field, and zones with minimum fractured porosity values of less than 0.2–0.3 % in the eastern part of the field. Results of laboratory core studies showed the presence of fractured porosity in reservoirs up to 1.26 %. The data on the size and distribution of fractured reservoirs across the Chayanda field area may be used to refine the field development project.

The use of the electron paramagnetic resonance (EPR) method for studying carbonate rocks is widespread. EPR makes it possible to reconstruct lithological and geochemical environments of ancient sedimentation, including redox conditions and paleo-radioactivity of sedimentation basins. The paper considers the heterogeneous structure of carbonate reservoir rocks of the Kazanian Stage of the Gorsky ultraviscous oil field by paramagnetic marks: manganese ions Mn²⁺, radical ions SO₃ ^– , SO₂ ^– , РO₂ ^2-(РO₂ ⁰ ) in carbonate minerals and radical С₆₀₀ in the remains of organic matter in the rock. The carbonate reservoirs of the Gorsky structure, tectonically confined to the eastern side of the Melekess Depression, are represented by two main lithotypes: dolomitic boundstones and dolomitic oolitic packstones, which have various post-sedimentary alterations. EPR data were obtained for 28 samples with a step of 0.5- 1.5 m along the section. The EPR spectra are characterized by narrow lines that indicate the marine origin of carbonates. Based on the EPR spectra of the ions Mn²⁺ and its content in carbonate minerals, the lagoonal-marine genesis of the Gorsky structure rocks was revealed. The dominant dolomite mineralization of the section was established. The absence of dolomite radicals and low values of the degree of population of the magnesium and calcium positions of dolomites are due to the secondary nature of carbonates. The distribution of manganese ions, organic and inorganic radicals in the rock along the section is shown simultaneously with its reservoir properties and the conditions for the formation of two dolomite lithotypes.

The distribution of thermal conductivity, radiogenic heat generation and heat flow in the Barents Sea southern part, including the Fedynsky Arch, is analyzed. Models of deep temperatures controlling the catagenesis of organic matter thermal conditions are calculated. A 3D temperature model was built up to a 30 km depth, which allowed us to demonstrate cross-sectional temperature maps at various depths in the Earth’s crust. A comparison of the Barents Sea thermal field and seismotomographic model was carried out, which showed that the seismotomographic anomalies are caused by thermal inhomogeneities.

At present, a large number of scientific works devoted to the study of the features of the geological structure and the development of oil deposits in complex carbonate reservoirs are based on the use of any one research method. This article shows the advantages of the integrated use of modern methods of core research, including X-ray microtomography and electron microscopy, as well as data from hydrodynamic and field studies of wells. The advantage of the approach used is the ability to study the deposit at three levels: core-well-development object, it is reasonable to transfer micro-survey data to the regularities of the implementation of technological processes of oil production. The objects of research in this article are the Famennian oil deposits of two neighboring fields, which, at first glance, are analogues in terms of the similarity of the enlarged geological and physical characteristics. Comprehensive studies of core samples from these deposits made it possible to establish differences both in the mineral composition of rocks and in the structure of their void space, especially in the size and distribution of pore channels. So, with approximately equal porosity for one of the deposits, the presence of two types of voids and a twofold prevalence of the size of the largest of them were established. According to the complex of laboratory methods for studying the core, the reservoir is classified as a porous type (no cracks were found). The performed interpretation of the hydrodynamic studies confirmed this fact, made it possible to establish the presence of a dependence of the reservoir permeability on the formation pressure (deformation of the void space of the reservoir), and also to build the corresponding individual dependence for each well. Comparison of the equations approximating the dependence data showed a more pronounced deformation of the reservoir, which is characterized by the presence of large pores and caverns. That is, a complex of laboratory and hydrodynamic studies made it possible to establish the probability of deformation of the void space of a carbonate reservoir even in the absence of cracks in it. In turn, the reservoir deformation is singled out as the most probable cause explaining the different rates of decline in well flow rates of the fields under consideration.

Long-term phased development of a multi-layer field, including tens and hundreds of oil-bearing horizons and local deposits, combined with their vertical and horizontal separation, creates conditions for the formation of residual oil reserves. For the purpose of identifying and spatial localization of residual reserves, an algorithm for retrospective analysis was developed and applied on the example of the Upper and Lower Devonian terrigenous deposits of the Romashkinskoe oil field, which have been developed since 1952. The long history of geological study and development of oil-bearing formations of the Pashiysky D1 (layers g and e), Mullinsky D2, Ardatovsky D3, Vorobyevsky D4 and Biysky D5 horizons is analyzed according to the data of 2605 wells. It is proposed to single out 6 categories of formations and the reserves contained in them. Previously undeveloped formations composed of conditioned reservoirs are classified as category 1. Formations composed of more clayey and less permeable reservoirs are awarded with category 2. Category 3 includes previously developed formations, but left before reaching the limit of water cut, and category 4 – currently being developed intervals. The least promising are those that are stopped after reaching the maximum water cut (category 5), as well as wedged out, replaced by non-reservoirs or considered waterbearing (category 6) formations. Categories were mapped to identify, visualize and describe the main patterns in the distribution of residual reserves, which are established both in single wells and in bypassed oil that include a group of wells. The algorithm was tested on the corporate information base of historical data on geological exploration, research and development of the Abdrakhmanovskaya area of the Romashkinskoe oil field. Examples of experimental workover operations to include the identified residual reserves in the development are given.

The paper discusses methodological approaches to the use of deterministic factor analysis for identifying the sources of changes in gas wells’ parameters under steadystate gas inflow obeying linear and non-linear filtration laws. Factor analysis methods make it possible to quantify the degree of influence of individual factors on the deviation of the indicator under study. In accordance with the methodology of factor analysis, mathematical models of the factor system were substantiated for linear and non-linear gas filtration, a set of factors of influence was determined, and ready-made solutions for factor analysis of gas wells’ operating parameters were obtained. In the paper, the method of weighted finite differences was substantiated and investigated with the aim of factor analyzing gas wells’ mode of operation and obtaining formulas to calculate the increment in gas production caused by changes in factors. Approbation of working formulas for assessing the degree of influence of factors on either positive or negative deviations in the gas flow rate was carried out with respect to the parameters of the wells of underground gas storages in the cycles of withdrawal and injection. The obtained formulas for factor analysis of gas wells make it possible to quantify the influence of such factors as reservoir and bottomhole pressures, filtration resistance coefficients, on the deviation of gas flow rate. Further ranking of wells by factors constitutes the basis for managing gas withdrawal (injection) processes and for well interventions planning.

Decreasing negative impact of industrial emissions to the atmosphere and prolonging fossil fuel usage period are urgent issues of fuel and energy sector. In view of this problem, injection of flue gases into oil fields to increase oil recovery may be considered as environmentally safe and economically rational way for beneficial use of greenhouse gas emissions. To effectively displace oil with flue gases it is important to consider many factors: influence of composition of the flue gases and oil, miscibility conditions, injection regimes, etc. Flue gases, a product of fuel combustion in air, can be produced as a result of oil self-ignition when air is injected into a reservoir with light oil (thermal gas method). Flue gases from natural gas, fuel oil or coal combustion in power plants or other processes that burn fossil fuels can also be used for injection into the reservoir. This paper presents an analysis of the world laboratory and industrial experience in studying efficiency of oil displacement using flue gases. Conclusions are presented about optimal criteria for implementation of this process and directions for further research.

The article is considering a new effective step-by-step approach to creating and tuning PVT-models of reservoir oil and reservoir gas condensate mixtures. The method is based on the reproducing of the results of field measurements and basic laboratory studies of representative samples in thermodynamic modeling using cubic three parameters equation of state. Tuning PVT-model is used for reliable modeling of PVT properties of reservoir fluids (reservoir oil and reservoir gas) in the design and monitoring of field development, calculation of multiphase flow in wells and field pipelines, as well as in basin modeling.
Proposed approach makes possible to tune the PVT model with high accuracy of both reservoir oil and reservoir gas condensate system to experimental data using a step-bystep procedure, where at each step, by changing one of the parameters of the equation of state, one of the PVT properties of the hydrocarbon system is tuned. Algorithmization and automated application of this approach in specialized software products is possible.
Proposed approach allows tune reservoir oil PVT-models on the main PVT-properties such as saturation pressure, FVF, STO density, gas-oil ratio of reservoir oil and dependencies of dynamic viscosity and compressibility on pressure at reservoir temperature as well as STO density. The tuned gas-condensate PVT-model precisely reproduces the key properties such as dew point pressure, initial condensate content in the reservoir gas, z-factor of the reservoir gas, gas-oil ratio, stable condensate density, drop down curve by the result of CVD-test.
PVT-models created on the base of the proposed method, provide reliable information on the properties of a reservoir fluid in development of flow simulation both using a reservoir simulation compositional models and using pseudo models “black oil”. The method is illustrated by the example of creation of the adequate PVT-models of various regions of Russia reservoir oil and reservoir gas condensate mixtures.

Experience shows that in the process of creating and long-term cyclic operation of underground gas storage facilities (UGS) in reservoirs of aquifers, reservoir gas losses can occur. Losses can reach tens of percent of the injected volumes of gas into the reservoir and have a significant impact on the reliability and safety and efficiency of operation of UGS. In this regard, the issues of the organization of field control and methodology for assessing reservoir gas losses at UGS are relevant.
The article proposes the structuring of the gas injected into the reservoir into possible reservoir components, taking into account the state of the gas phase and participation in filtration mass transfer processes. The main factors determining the formation of different reservoir components are given.
The basic concepts are considered and the definition of reservoir gas losses at UGS in aquifers is given. The main features of one or another type of reservoir gas losses are shown.
Reservoir losses from free gas currents from an artificial gas deposit, which can occur as a result of vertical leaks from the storage facility and lateral gas escapes through the reservoir beyond the trap, are briefly described. Formation losses associated with gas adsorption by rocks, gas phase transitions and gas saturation of low-permeable sections of reservoirs; gas dissolution in invading reservoir water and its convective-diffusion entrainment by displaced water into the aquifer region of the reservoir are also considered.
Using the example of a UGS created in an aquifer, the system of geological and commercial monitoring of a subsurface area within a mining branch in conditions of vertical interplastic flows of free gas is considered. It is shown that the implemented system of observation and control wells allows for adequate monitoring of the gas storage facility and control of the tightness of UGS throughout the section above the storage facility.
The following components of reservoir gas losses at the storage facility are considered: dissolved gas in residual water within the gas reservoir; gas adsorbed by rocks within the gas reservoir; dissolved gas diffused from the gas reservoir into the contact aquifer region of the reservoir; dissolved and free gas in the control horizons. Using a geological model of the formation, as well as the results of modeling the convectivediffusion transfer of dissolved gas into the aquifer region of the formation, the assessment of the components of reservoir gas losses in a direct way by their locations is given.

The petrological and geochemical characteristics of intrusive rocks, sources of magmatic melts, as well as the composition of minerals of near-ore metasomatites and ores of the Karagaikul gold-porphyry ore occurrence located in the Main Ural fault zone in the South Urals have been studied. The content of petrogenic oxides was determined by the silicate method, rare elements – using ICP-MS analysis on a quadrupole mass spectrometer ELAH 9000. The composition of minerals was studied using electron microscopic analysis on a scanning electron microscope REMMA-202M. It was found that gabbro, gabbro-diorite and diorite of the ore-bearing dyke series of the Karagaikul ore occurrence are suprasubduction magmatites of normal alkalinity belonging to the transitional and calc-alkaline petrogenetic series. They were formed from fluid-saturated melts. The main source of melts for intrusive rocks was most likely spinel peridotites of the suprasubduction lithospheric mantle, previously metasomatized by aquatic fluids that arose during the dehydration of rocks of the subducting oceanic plate. The dykes underwent propylitization of the biotite-actinolite facies in a near-ore halo (paragenesis: biotite + actinolite + epidote + orthoclase + albite + quartz + chlorite + pumpelliite), and the host serpentinized ultrabasites – carbonatization (chromogenesis: dolomite + magnesite). According to the chlorite geothermometer, the temperature of propylite formation is 287–317 °С. Sulfide minerals in goldbearing stockworks are represented by pyrite, chalcopyrite, galena, pentlandite, pyrrhotine, and violarite.

Data on the morphology, composition, textural and structural features of chromite deposits of the Ufaley ultramafic massif are presented. The mineralogical and compositional features of the host ultramafic rocks allow us to interpret them as depleted restite from partial melting of mantle peridotites. Relatively wide variations in the composition of ore-forming chromian spinel grains (#Cr 0.6–0.8) and noticeable metamorphism of disseminated ores with replacement of chromite by Cr-magnetite are noted. It is assumed that chromitite bodies were initially formed under the conditions of the upper mantle by a rheomorphic mechanism, and then their structural and geochemical transformation took place in the collisional setting of the upper part of the crust. Flattened bodies of disseminated chromitites have been preserved near competent gabbroid blocks, while other deposits have been transformed into lenses and podiform bodies of densely disseminated and massive ores of smaller size. The “cold tectonics” of the crustal stage led to the disintegration of deposits and the simultaneous local enrichment of deformed chromitite bodies.

In a laboratory experiment, the ability of the soil to self-cleaning under heavy petroleum pollution and the effect of biochars and shungites on the cleaning process were studied. Incubation of contaminated soils for 28 days at a constant humidity and temperature without addition of sorbents led to a decrease in the residual content of petroleum products by only 8%. The addition of biochar and shungite at a dose of 2.5% made it possible to reduce the content of petroleum under constant incubation conditions to 48.8% and 38%, respectively. It was shown that the incubation of oil-contaminated soils in the regime of variable humidity and temperature without the addition of sorbents makes it possible to reduce the content of petroleum by 32% over 28 days of the experiment. In the course of the study, methods were developed for determining substrate-induced respiration (SIR) in various incubation modes. Soil contamination with petroleum led to a significant decrease of SIR in the initial period of incubation from 12.8 C-CO₂ µg/g h to 8.6 C-CO₂ µg/g h, which returned to normal on the 14th day of the experiment. It has been shown that the introduction of biochars (to a lesser extent schungites) into oil-contaminated soils ensures the maintenance of SIR at the required level and increases the potential capacity of soils for self-purification. The paper discusses the possibilities of increasing the potential capacity of soils for self-cleaning under heavy oil pollution.