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The sedimentary column at the Rechitsa oilfield in the Pripyat rift basin, Belarus, is dominated by an Upper Devonian synrift succession. The succession includes uppermost Frasnian and mid‐Famennian salt units which are about 1000 m and 2000 m thick respectively. Reservoir rocks consist of sandstones and carbonates in the intra‐, inter‐ and sub‐salt successions. In this paper, the geochemical analysis of 15 oil samples from different stratigraphic intervals at the Rechitsa field is used as a basis for reservoir characterisation. Geochemical studies included biomarker and stable C, N and S isotope analyses. Four genetic oil groups were identified and are referred to as Groups A to D. Oils in Group A came from upper intra‐ and inter‐salt reservoir rocks; the oils are early mature, enriched in heavy (C36+) hydrocarbons, heteroatoms, aryl‐isoprenoids and gammacerane, with low Pr/Ph = 0.6 and a sulphur isotope composition averaging 22.7‰ CDT. Oils in Group B were from sub‐salt reservoirs and are at peak maturity with Pr/Ph = 1, an increased proportion of C27 regular steranes, and a sulphur isotope composition of 8.1‰ CDT. The single oil sample in Group C was from a Proterozoic reservoir. The oil was overmature with a low content of heavy fractions, heteroatoms and steranes; its hopanes composition indicated that it was generated by the same source rock as the oils in Group B. Oils in Group D came from inter‐salt reservoir rocks and were composed of a mixture of Groups A and B oils in roughly equal proportions, as indicated by their average isotope, molecular and biomarker compositions. Observed differences in oil composition were explained in terms of contributions from at least two different source rocks together with variations in source rock maturity. Group A oils were interpreted to have been generated by Famennian carbonate‐rich source rocks containing dominantly marine and bacterial organic matter deposited in an anoxic evaporitic setting. Source rocks for Groups B and C oils were suggested to be composed of OM‐rich marine shales of Frasnian age or older. The geochemical characteristics of the Devonian oils from Rechitsa field, and the oil‐oil and oil‐ source rock correlations reported, will contribute to a better understanding of the petroleum system in the Pripyat Basin although direct oil‐ source rock correlations are not yet available. The presence of at least two source rocks for the Rechitsa oils has been suggested, respectively comprising carbonates in the inter‐salt succession and marine shales and/or carbonates in the sub‐salt succession. The main controls on oil composition in the Devonian reservoir units were the varying contributions from the different source rocks and differences in source rock thermal maturity associated with variations in burial depth and tectonics, together with the stratigraphic distribution of reservoir units which was in turn controlled by the presence of the thick Frasnian and Famennian salt units. [ABSTRACT FROM AUTHOR]

In this study, a set of laboratory experiments was carried out to study the parameters of hydraulic fractures induced in the dry and mineral-oil-saturated rocks and compare them with the geomechanical characteristics of tested samples. We chose sandstone and thermally treated granite as the materials for research. There are very few known studies related to the mechanical and acoustic properties of oil-saturated rocks, and even fewer studies describing, in detail, the parameters of hydraulic fractures generated in oil-saturated rocks. The hydraulic fracture parameters were determined using a set of independent sensors installed to measure the axial deformation of the sample (which is directly related to the aperture of created hydraulic fracture), fluid pressure, fluid volume injected into hydraulic fracture, and localization of acoustic emission (AE) events, generated during the propagation of hydraulic fractures. Our study focuses on the investigation of the influence of rock properties, altered by mineral oil saturation and thermal treatment, on such parameters of hydraulic fracturing as breakdown pressure (BP), fracture aperture, and the resulting roughness of the hydraulic fracture surface. In addition, we studied the influence of injected fluid viscosity on the parameters of created hydraulic fractures. It was revealed that the saturation state caused a reduction in the values of mechanical parameters such as Young's modulus, compressive strength, and cohesion, and had a similar reducing influence on the breakdown pressure. The values of HF parameters, such as fracture width and the volume of fracturing agent injected into the HF, are higher in the tests for both saturated sandstone and saturated TT granite. However, we found out that thermal treatment of granite samples led to a much more significant reduction in the values of mechanical and acoustic parameters than the mineral-oil saturation procedure because it created a dense network of thermally induced cracks. The results obtained in our laboratory studies can be taken into account in the modeling of hydraulic fracturing in the field. [ABSTRACT FROM AUTHOR]

Basin and petroleum systems are routinely modelled to provide qualitative and quantitative assessments of a hydrocarbon play. The importance of the rock thermal properties and heat flow density in thermal modelling the history of a basin are well‐known, but little attention is paid to assumptions of the thermal conductivity, present‐day heat flow density and thermal history of basins. Assumed values are often far from measured values when data are available to check parameters, and effective thermal conductivity models prescribed in many basin simulators require improvement. The reconstructed thermal history is often justified by a successful calibration to present‐day temperature and vitrinite reflectance data. However, a successful calibration does not guarantee that the reconstruction history is correct. In this paper, we describe the pitfalls in setting the thermal conductivity and heat flow density in basin models and the typical uncertainties in these parameters, and we estimate the consequences by means of a one‐dimensional model of the super‐deep Tyumen SG‐6 well area that benefits from large amounts of reliable input and calibration data. The results show that the entire approach to present‐day heat flow evaluations needs to be reassessed. Unreliable heat flow density data along with a lack of measurements of rock thermal properties of cores can undermine the quality of basin and petroleum system modelling. [ABSTRACT FROM AUTHOR]

This study is focused on the mineralogical, chemical, and isotopic characterization of pyrites from the rocks of the Bazhenov Formation (Upper Jurassic–Lower Cretaceous organic-rich shales, Western Siberia, Russia). Scanning electron microscopy (SEM) revealed pyrites of different morphologies: small and large framboids, small crystals, and large euhedral crystals; all morphotypes were usually combined into aggregates. Isotope ratio mass spectrometry (IRMS) and secondary ion mass spectrometry (SIMS) showed that small framboids and microcrystalline pyrite are isotopically light, with δ34SCDT varying from −55 to −20‰. Large framboids and euhedral crystals of pyrite are isotopically heavy with δ34SCDT up to +26‰. Both morphology and δ34S were suggested to be controlled by the redox conditions and sedimentation regime. The abundance of small framboids suggests that pyrite sedimentation occurred under anoxic conditions; the presence of the large framboids and euhedral crystals of pyrite suggest the accumulation of sediments occurred at suboxic conditions, possibly in the presence of oxygen. [ABSTRACT FROM AUTHOR]

This paper addresses potential application of data on stable carbon and oxygen isotope composition of carbonates for study of organic rich source rocks on the example of the Late Jurassic–Early Cretaceous Bazhenov Formation (West Siberian petroleum basin, Russia). Geochemical studies were conducted for sections located in central (most productive) and peripheral (northern and southern) regions of the Bazhenov Formation distribution area, containing deposits formed under different conditions. We identified key factors impacting stable isotope composition of carbonate minerals and established relation of their isotope composition to the formation conditions. Using a thermodynamic model of carbon and oxygen isotope exchange in the carbonate–water–carbon dioxide system, it is shown that variations in the isotope composition of secondary carbonates are affected by isotopic composition of primary carbonates in sediments and by the isotope exchange reactions with water and carbon dioxide, generated during the source rocks transformation. Our results demonstrate that stable isotope data for carbonates in the Bazhenov Formation together with standard geochemical methods can be efficiently applied to determine sedimentation conditions and secondary alteration processes of oil source rocks. [ABSTRACT FROM AUTHOR]