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At present, the study of the oil and gas potential of poorly explored areas of oil and gas basins in the Russian Federation is of great importance due to the possibility of discovering large hydrocarbon accumulations in them. The Vychegda Trough in the north of the Volga–Ural basin is considered to be one of such areas. The research is devoted to the assessment of the oil and gas potential of the Vychegda Trough based on the concept of "petroleum systems", which is widely used in oil and gas geology. A comprehensive analysis of geological and geophysical, petrophysical and geochemical data was carried out, and modern technologies for studying the oil and gas potential of sedimentary basins were applied: paleotectonic, paleogeographic reconstructions and basin modeling. The results of the research allowed us to determine a sufficiently high potential for the discovery of hydrocarbon accumulations and to identify three potential petroleum systems in the basin section: Riphean, Vendian and Devonian–Permian. [ABSTRACT FROM AUTHOR]

The deeplying Mesozoic and Paleogene deposits of the Middle Kura depression have significant resource potential. They are the main complexes in terms of prospectivity for oil and gas exploration. The lithological-facies characteristics of the host rocks, accumulation of which is tectonically conditioned, are among major indicators responsible for their oil and gas content. Based on actual core material from parametric, prospecting and exploratory wells, along with downhole logging data the marker horizons have been established for individual exploration areas within the depression. An overview of the lithostratigraphic features and thickness distribution of the Upper Cretaceous and Eocene deposits is given. Distribution of the fluid conducting strata, regional variation of their reservoir properties in buried structures of the Middle Kura depression is addressed as well. Within the study area a typical Upper Cretaceous section is comprised of three genetic rock types: sedimentary, igneous-sedimentary and igneous. The Eocene sediments are represented by shaly (Lower Eocene), terrigenous-carbonate (Middle Eocene) and terrigenous (Uppere Eocene) lithofacies. The regularities that have been revealed in lithofacies and thickness variation enabled highlighting the areas of highest subsidence and sedimentation, tracing basinal limits in Late Cretaceous and Eocene ages and depicting them on the maps presented. The compiled schematic maps clearly demonstrate the paleorelief in the study area at the close of Late Cretaceous and Paleogene times. Sections of the indicated sedimentary complexes contain effusive, carbonate, sandstone and siltstone reservoirs, exhibiting substantial occurrence and thickness, the latter having a marked trend to increasing toward the centerline of the Lower Kura depression. Thus, it is likely that the alteration in facies within the Upper Cretaceous and Eocene sections is closely interrelated with the breaks in sedimentation and erosions, favouring for formation of traps controlled by diverse screening features. At basin scale the major regionally persistent seal horizons are the Maykop shales of Oligocene-Lower Miocene age, which in a number of cases unconformably cover petroleum containing horizons.

The deep-lying Mesozoic and Paleogene deposits of the Middle Kura depression have significant resource potential. They are the main complexes in terms of prospectivity for oil and gas exploration. The lithological-facies characteristics of the host rocks, accumulation of which is tectonically conditioned, are among major indicators responsible for their oil and gas content. Based on actual core material from parametric, prospecting and exploratory wells, along with downhole logging data the marker horizons have been established for individual exploration areas within the depression. An overview of the lithostratigraphic features and thickness distribution of the Upper Cretaceous and Eocene deposits is given. Distribution of the fluid conducting strata, regional variation of their reservoir properties in buried structures of the Middle Kura depression is addressed as well. Within the study area a typical Upper Cretaceous section is comprised of three genetic rock types: sedimentary, igneous-sedimentary and igneous. The Eocene sediments are represented by shaly (Lower Eocene), terrigenous-carbonate (Middle Eocene) and terrigenous (Uppere Eocene) lithofacies. The regularities that have been revealed in lithofacies and thickness variation enabled highlighting the areas of highest subsidence and sedimentation, tracing basinal limits in Late Cretaceous and Eocene ages and depicting them on the maps presented. The compiled schematic maps clearly demonstrate the paleorelief in the study area at the close of Late Cretaceous and Paleogene times. Sections of the indicated sedimentary complexes contain effusive, carbonate, sandstone and siltstone reservoirs, exhibiting substantial occurrence and thickness, the latter having a marked trend to increasing toward the centerline of the Lower Kura depression. Thus, it is likely that the alteration in facies within the Upper Cretaceous and Eocene sections is closely interrelated with the breaks in sedimentation and erosions, favouring for formation of traps controlled by diverse screening features. At basin scale the major regionally persistent seal horizons are the Maykop shales of Oligocene-Lower Miocene age, which in a number of cases unconformably cover petroleum containing horizons. [ABSTRACT FROM AUTHOR]

Separation of well section into permeable and impermeable parts is one of the main problems for further construction of a geological model, reserves estimation and field development planning. Quality of separation depends on amount of knowledge about geological section, level of theoretical development of well logging methods and general geophysical characteristics of the area. The fullest differentiation is obtained by using a complex of geological and geophysical methods. The paper is focused on Visean deposits of well of Sofyinskoe field drilled in 2014. A complex of activities was performed along with well logging. Porosity was calculated by acoustic and neutron logging. Core analysis was performed. Using well logging and results of core analysis selection was made, used for construction of statistical models. Based on statistical models all parameters were made-up to a single measurement system. The analysis of degree of influence of geological and geophysical parameters was made. The geological analysis shows that the greatest influence belongs to porosity and residual water. The geophysical analysis shows that the greatest influence belongs to hydrogen content and own radioactivity of rocks. A complex probabilistic parameter that includes all measurements according to core and geophysical parameters is calculated. Results of core analysis are considered fully in order to obtain a highest degree of difference. Almost all the parameters of geophysical data increase the degree of difference, except for lateral logging, microgradient and micropotential tools and transit time of P-wave for short tool, which reduces the degree of difference. Based on values of a complex parameter that have maximum differences in geological and geophysical parameters, relationships of geological and geophysical parameters were built. Scatter charts show that fields of measured points are not intersected, which confirms a correct separation of a section. Using a statistical method allows to consider fully available geological and geophysical data to separate a section into permeable and impermeable parts.

Caprock has the most important role in the long term safety of formation gas storage. The caprocks trap fluid accumulated beneath, contribute to lateral migration of this fluid and impede its upward migration. The rapid upward passage of invasive plumes due to buoyancy pressure is prevented by capillary pressure within these seal rocks. In the present study, two main seal rocks, from the Zagros basin in the southwest of Iran, a shale core sample of Asmari formation and an anhydrite core sample of Gachsaran formation, were provided. Absolute permeabilities of shale and anhydrite cores, considering the Klinkenberg effect, were measured as 6.09 × 10 −18 and 0.89 × 10 −18 m 2 , respectively. Capillary sealing efficiency of the cores was investigated using gas breakthrough experiments. To do so, two distinct techniques including step by step and residual capillary pressure approaches were performed, using carbon dioxide, nitrogen and methane gases at temperatures of 70 and 90 °C, under confining pressures in the range 24.13–37.92 MPa. In the first technique, it was found that capillary breakthrough pressure of the cores varies in the range from 2.76 to 34.34 MPa. Moreover, the measurements indicated that after capillary breakthrough, gas effective permeabilities lie in range 1.85 × 10 −21 – 1.66 × 10 −19 m 2 . In the second technique, the minimum capillary displacement pressure of shale varied from 0.66 to 1.45 MPa with the maximum effective permeability around 7.76 × 10 −21 – 6.69 × 10 −20 m 2 . The results indicate that anhydrite caprock of the Gachsaran formation provides proper capillary sealing efficacy, suitable for long term storage of the injected CO 2 plumes, due to its higher capillary breakthrough pressure and lower gas effective permeability. [ABSTRACT FROM AUTHOR]

This paper reports a laboratory study of the gas breakthrough pressure for different gas/liquid systems in the Mississippian-age Midale Evaporite. This low-permeability rock formation is the seal rock for the Weyburn Field in southeastern Saskatchewan, Canada, where CO2 is being injected into an oil reservoir for enhanced recovery and CO2 storage. A technique for experimentally determining CO2 breakthrough pressure at reservoir conditions is presented. Breakthrough pressures for N2, CO2 and CH4 were measured with the selected seal-rock samples. The maximum breakthrough pressure is over 30 MPa for N2 and approximately 21 MPa for CO2. The experimental results demonstrate that the Weyburn Midale Evaporite seal rock is of high sealing quality. Therefore, the Weyburn reservoir and Midale Beds can be used as a CO2 storage site after abandonment. The measured results also show that the breakthrough pressure of a seal rock for a gas is nearly proportional to the interfacial tension of the gas/brine system. The breakthrough pressure of a CO2/brine system is significantly reduced compared with that of a CH4/brine system because of the much lower interfacial tension of the former. This implies that a seal rock that seals the original gas in a gas reservoir or an oil reservoir with a gas cap may not be tight enough to seal the injected CO2 if the pressure during or after CO2 injection is the same or higher than the original reservoir pressure. Therefore, reevaluation of the breakthrough pressure of seal rocks for a given reservoir is necessary and of highest priority once it is chosen as a CO2 storage site. [ABSTRACT FROM AUTHOR]

Non-isothermal injection of fluids deep into geological strata results in coupled alterations in in-situ temperatures and pore pressures, inducing deformations within the target rock and surrounding media. This paper presents new closed-form thermo-poroelastic solutions for spatiotemporal pore pressure, temperature, and displacements induced in a porous continuum confined with flexible sealing rocks, during early stages of injection when the rock temperature adjacent to the wellbore is within a transient state. Reservoir response in the direction perpendicular to flow is incorporated using the Winkler model. A comprehensive analysis reveals the duration of the transient state for various rocks to be rather substantial. While temperature profiles obtained from the proposed solutions are fairly similar to those of conventional solutions, thermal-induced pore pressures are demonstrated to be very different, resulting in a distinct geomechanical response of the confined layer specifically near the wellbore region. Vertical confinement is found to be notably influential on thermal-induced geomechanical response of a confined porous layer. [ABSTRACT FROM AUTHOR]