The object of the study reported in this paper is the parameters of a device for implosion impact on aquifers during well development. The problem of increasing the productivity of aquifers was solved by removing colmatation products formed during the drilling process and restoring the natural permeability of the formations. This could ensure high production of wells and their long-term trouble-free operation. One of the most effective ways to develop wells is implosion impact. However, its use is hampered by the complexity of the structure of existing devices, the high cost of use, and the insufficient reliability of their operation. To overcome this, an original device for implosion impact on aquifers was designed and its operating parameters were determined. A procedure has been devised for determining the maximum permissible sizes of intervals not filled with liquid under the conditions of preventing casing string collapse. The effect of these intervals on reducing the total weight of the casing string was investigated. An optimal well structure was proposed for the conditions of the Tonirekshin field. The critical dimensions of empty intervals were calculated for all wall thicknesses of casing pipes included in the well design. It has been established that the amount of weight reduction of the casing string in the well due to the Archimedean force for field conditions is 43–47 %. Archimedean force increases with increasing pipe wall thickness. Reducing the weight of the casing string reduces the required winch power, allowing the use of lighter drilling rigs. The procedure for preparing for repeated implosion impacts has been studied. The studies performed and the recommendations presented will be effective when drilling and developing wells under the conditions of the Mangistau Peninsula, at the Tonirekshin field.

This paper presents the results of the experimental research on diamond-reinforced composites with WC–Co matrices enhanced with a ZrO₂ additive. The samples were prepared using a modified spark plasma sintering method with a directly applied alternating current. The structure and performance of the basic composite 94 wt.%WC–6 wt.%Co was compared with the ones with ZrO₂ added in proportions up to 10 wt.%. It was demonstrated that an increase in zirconia content contributed to the intense refinement of the phase components. The composite 25 wt.%C_diamond–70.5 wt.%WC–4.5 wt.%Co consisted of a hexagonal WC phase with lattice parameters a = 0.2906 nm and c = 0.2837 nm, a cubic phase (a = 1.1112 nm), hexagonal graphite phase (a = 0.2464 nm, c = 0.6711 nm), as well as diamond grits. After the addition of zirconia nanopowder, the sintered composite contained structural WC and Co₃W₃C phases, amorphous carbon, tetragonal phase t-ZrO₂ (a = 0.36019 nm, c = 0.5174 nm), and diamond grits—these structural changes, after an addition of 6 wt.% ZrO₂ contributed to an increase in the fracture toughness by more than 20%, up to K_Ic = 16.9 ± 0.76 MPa·m^0.5, with a negligible decrease in the hardness. Moreover, the composite exhibited an alteration of the destruction mechanism after the addition of zirconia, as well as enhanced forces holding the diamond grits in the matrix.

The study aims to improve the efficiency of oil field development at the Kalamkas field through the implementation of new methods for analyzing hydrodynamic survey data and monitoring well conditions. It is hypothesized that the use of integrated geophysical and hydrodynamic methods will enhance forecasting accuracy, optimize field operations, and increase the hydrocarbon recovery factor. An integrated approach combining pulsed neutron logging (PNL), acoustic cementometry (AC), inflow and injectivity profile evaluation methods, and specialized software for advanced data interpretation was applied, significantly improving the accuracy of well condition analysis. The analysis enabled the identification of oil and gas saturation intervals, zones of increased water cut, and cementing defects in casing, and allowed for a quantitative assessment of reservoir permeability dynamics. Hydraulic fracturing application resulted in a 10–15% increase in permeability in certain zones, with an average oil recovery factor increase of 5%. Analysis of PNL data demonstrated the transition of oil-saturated reservoirs to water saturation during development, confirmed by geophysical and pressure build-up survey results. The study identified the primary causes of increased water cut and key factors leading to production rate decline. Proposed measures for optimizing operating modes and well grid efficiency contribute to improving existing field management practices.

This study presents an assessment of the hydrodynamic connectivity and compartmentalization of petroleum reservoirs in the Caspian Basin using integrated oil fingerprinting and biomarker geochemistry approaches. The aim of the study was to identify inter-reservoir fluid communication, reconstruct hydrocarbon migration pathways, and determine the factors controlling the geochemical heterogeneity of reservoir systems. The investigation was based on the analysis of 43 oil samples collected from 15 fields within the Caspian Basin using gas chromatography, gas chromatography–mass spectrometry, carbon isotope analysis, and multivariate statistical methods, including principal component analysis (PCA) and hierarchical cluster analysis. The results revealed the presence of both hydrodynamically connected reservoirs characterized by similar molecular and biomarker compositions and compartmentalized reservoir blocks showing significant geochemical differences and variations in thermal maturity. It was established that the internal heterogeneity of the reservoirs is controlled by tectonic segmentation, multi-stage hydrocarbon migration, and differences in source rock characteristics. The obtained results confirm the effectiveness of oil fingerprinting methods for diagnosing hydrodynamic connectivity and reservoir compartmentalization in complex petroleum systems.

This study presents an integrated geochemical approach to distinguish between genetic and reservoir-related factors controlling oil compositional variability, evaluate reservoir compartmentalization, and reconstruct hydrocarbon migration pathways within the Nuraly field and the Akshabulak group of fields in the South Turgay Basin, Kazakhstan. The study aims to develop and validate an integrated approach combining biomarker analysis and oil fingerprinting to improve the reliability of oil genetic interpretation, assess reservoir fluid communication, and reconstruct secondary hydrocarbon migration pathways. This study analyzed 164 unique crude oil samples from the Akshabulak and Nuraly fields. Oil fingerprinting was performed on all 164 samples, including 128 samples from the Akshabulak group and 36 samples from the Nuraly field. A representative subset of 75 samples, comprising 39 Akshabulak oils and 36 Nuraly oils, was additionally analyzed for biomarkers. Oil fingerprinting was conducted using low thermal mass multidimensional gas chromatography (LTM-MD-GC), whereas biomarker analysis was performed using gas chromatography–mass spectrometry (GC–MS). Principal component analysis (PCA) and hierarchical cluster analysis were applied separately to the oil-fingerprinting and biomarker datasets. The resulting classifications were subsequently compared and integrated to distinguish source-related genetic variability from reservoir-related compositional effects, including hydrocarbon migration, oil mixing, and reservoir compartmentalization. The proposed approach is based on the complementary diagnostic capabilities of the applied geochemical methods. Biomarkers provide information on the origin of organic matter, depositional environment, and thermal maturity of the source rocks, whereas oil fingerprinting is sensitive to hydrocarbon migration processes and the degree of hydrodynamic connectivity between reservoirs. The results indicate that the investigated oils are predominantly derived from terrigenous organic matter of lacustrine origin. The Akshabulak group is characterized by genetic homogeneity of oils despite pronounced reservoir compartmentalization, whereas the Nuraly field contains at least two genetically distinct oil populations and hydrocarbon mixing zones. Regional hydrocarbon migration was reconstructed from southeast to northwest. Paleochannel sandstones were identified as high-permeability migration conduits, while tectonic faults and facies heterogeneity were recognized as the principal controls on reservoir hydrodynamic isolation. The results demonstrate that integrating biomarker analysis with oil fingerprinting provides an effective tool for distinguishing between genetic and reservoir-related controls on oil compositional variability, evaluating reservoir compartmentalization, and improving the reliability of geological and reservoir models in structurally complex petroleum systems.

Petroleum reservoir systems of the South Mangyshlak Basin are characterized by a complex geological framework, pronounced geochemical heterogeneity, and evidence of inter-reservoir fluid interactions, which complicate the interpretation of oil origin and the assessment of geochemically inferred reservoir connectivity between productive horizons. In this study, a comprehensive geochemical characterization of crude oils from the basin was performed using high-resolution gas chromatography (HRGC), gas chromatography–mass spectrometry (GC–MS), oil fingerprinting, and Rock-Eval pyrolysis. The distributions of n-alkanes, isoprenoids, terpane, sterane, and aromatic biomarker compounds were analyzed to evaluate the genetic type of the source organic matter, thermal maturity, and hydrocarbon migration processes. The results revealed the presence of marine, lacustrine, and mixed genetic oil families, together with a general tendency toward increasing thermal maturity with reservoir depth. The most pronounced evidence of vertical hydrocarbon migration and oil mixing was identified in the Uzen oil field, where the multilayer reservoir system exhibits geochemical evidence consistent with possible inter-reservoir fluid communication and geochemically inferred reservoir connectivity. The obtained results suggest that the geochemical heterogeneity of oils in the South Mangyshlak Basin reflects the combined effects of variations in source-rock organic matter, vertical hydrocarbon migration, and oil mixing within stacked petroleum reservoir systems.