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.

Relevance. This paper discusses the optimization of multi-reservoir field development at the Uzen oilfield using geochemistry and an innovative method for inflow distribution across productive layers. Aim. To minimize the negative impact of reservoir property heterogeneity in hydrocarbon fields, a comprehensive approach is proposed. It includes geochemical analysis of oil and the development of specialized downhole equipment for oil-water separation. This approach is aimed at reducing capital investments and operational costs, improving production control, and enhancing the economic efficiency of field development. Methods. The application of downhole injection and separation systems equipped with electrically driven centrifugal pumps opens new opportunities for the oil production sector. This technology significantly increases the efficiency and cost-effectiveness of oil extraction by boosting oil flow rates from existing production wells through the inclusion of new reservoir intervals and reducing lifting and pumping costs via in-well separation and simultaneous water reinjection into the formation. Even without a complete economic analysis, the advantages of implementing this new method in the Parsumurun Dome of the Uzen field are evident, promising significant benefits compared to traditional approaches. Reduced operating expenses and capital investments, combined with the potential for increased oil production revenues, ensure high economic efficiency for the proposed solutions. These factors make investment in this method particularly attractive, offering substantial improvements in the financial performance of field development. Results and conclusions. Pilot testing at the Parsumurun Dome, which contains only 2% of the Uzen field geological oil reserves, provides a unique opportunity to evaluate the effectiveness of the proposed method. Positive results from the pilot trials could justify full-scale implementation across the entire field, offering considerable technological and economic benefits.

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.

Thermal–gas–chemical treatment (TGCT) using activated aluminum alloys is a promising near-wellbore stimulation method for high-viscosity oil reservoirs, combining localized heat generation, hydrogen release, pressure increase, and chemical activation of the treated zone. This study evaluates the potential of TGCT for the Karazhanbas field using laboratory core flooding experiments and reservoir-scale scenario analysis. Experiments were conducted on unconsolidated core models saturated with high-viscosity oil. Treatment with activated aluminum alloy and formation water generated up to 2600 mL of gas but did not increase oil displacement efficiency. In contrast, the system containing activated aluminum alloy, 3 wt.% HCl, and 2 wt.% surfactant intensified the reaction, promoted gas–liquid foam formation, increased electrical resistivity to 5000 Ω·m, and improved oil displacement efficiency from 0.37 to 0.61. The additional oil recovery reached 16.8 mL, corresponding to a relative increase of approximately 65%. Reservoir-scale scenario calculations showed a heterogeneous production response, with maximum oil production rate increases ranging from 0.03 to 3.27 m³/day, depending on well conditions. The results indicate that TGCT efficiency is controlled by the combined thermal, gas, and chemical effects rather than gas generation alone. Field-scale implementation requires the calibration of the treatment radius, effect duration, temperature response, gas saturation, permeability alteration, and well-specific reservoir conditions.