This paper presents laboratory studies based on which a stimulation technology for an oil field located in the Zechstein Main Dolomite was investigated. A large number of oil wells in the Main Dolomite produce significant amounts of reservoir water. Matrix acidizing using conventional acid solutions in such wells has caused a significant increase in water cut, because of their affinity for water. The purpose of this cooperation between the Oil and Gas Institute–NRI and the Brenntag Polska was to develop an acid treatment technology that would not increase the water cut after acidizing treatment in wells where oil production is accompanied by the production of reservoir water. Therefore, a series of tests were performed, including the selection of a suitable viscoelastic surfactant that was sensitive to crude oil. The contact of the gel of the viscoelastic surfactant fluid with crude oil resulted in the reduction of its viscosity The tests described herein include dissolution/dispersion tests, rheological tests, acid sludge tests, compatibility tests, core flow experiments, and corrosion tests, which allowed recipes to be developed for the preflush, diverter, and acidizing liquid. Then, recommendations were established for using these liquids in matrix acid treatment. A series of treatments performed according to this technology allowed the removal of near-wellbore damage without increasing the water cut.

After laboratory research the pilot treatment has been done. After obtaining positive results from this treatment, BMB oil field operator begun to use emulsified acid for small scale acidizing treatment on production wells. Six acidizing tr

This paper concerns the effect of proppant embedment related to hydraulic fracturing treatment. This phenomenon occurs if the strength of a dry reservoir rock is lower than that of proppant grains. The aim of this research was the laboratory determination of the loss of width of the proppant pack built of light ceramic grains. A laboratory simulation of the embedment phenomenon was carried out for a shale rock on a hydraulic press in a heated embedment chamber specially prepared for this purpose. Tests were conducted at high temperature and axial compressive stress conditions. The surfaces of cylindrical core plugs (fracture faces) were imaged under an optical microscope equipped with 3D software. The fracture faces were examined and compared before and after the embedment phenomenon. Analysis of the obtained images of the fracture face was done, based on a research method of the embedment phenomenon developed at the Oil and Gas Institute—National Research Institute. On the basis of the laboratory tests, the parameters characterizing the embedment phenomenon were defined and discussed. In addition, the percentage reduction in the width of the proppant pack was determined.

Nanoemulsions and polymers are widely used for increasing the efficiency of enhanced oil recovery (EOR) processes. The application of both these additives enables the synergistic use of several physical phenomena that are crucial to the process. One of the methods used for assessing these processes is laboratory core flooding tests using natural cores. In various experiments, carbonate rocks are subjected to oil displacement under high pressure and temperature. Polymer solutions and a newly developed polyfraction nanoemulsion are tested. The test results confirm the usefulness of these products for EOR processes and demonstrate their stability under high pressure, high temperature, and in the presence of H₂S. Under these conditions the polymers maintain high efficiency in displacing crude oil from carbonate rocks, while the tested nanoemulsion improves the wettability of carbonate rocks and reduces interfacial tension, factors which increase the efficiency of oil displacement.The best result in the laboratory EOR simulation was obtained for polymer and nanoemulsion concentrations in dilute reservoir water of 0.05% and 1%, respectively. In this case, the measured oil recovery was 37.5% higher than that obtained when using water without additives.

This study evaluates the corrosion behavior of N80 production tubing steel under high-temperature, high-pressure (HTHP) conditions representative of CO₂-based geothermal exploitation in depleted hydrocarbon reservoirs. We developed a staged laboratory protocol that simulates (i) an early multiphase production window (oil + formation brine + supercritical CO₂), (ii) the same environment with the originally developed non-commercial inhibitor (INH), and (iii) a later stabilized stage dominated by near-anhydrous supercritical CO₂ (scCO₂) with trace brine and oil. Corrosion was quantified by gravimetric mass-loss, complemented by multi-scale surface characterization (2D/3D optical profilometry) and microscopic cross-section analysis. In the early multiphase scenario unprotected N80 experienced severe attack (mass-loss rate ≈ 0.67 mm·year⁻¹) with both uniform corrosion and incipient pitting beneath ferrous-carbonate deposits. Addition of an inhibitor at 5000 ppmv reduced mass loss by more than an order of magnitude (to ≈0.09 mm·year⁻¹, ≈97% inhibition) and substantially limited pitting. Under stabilized, near-dry scCO₂ conditions, corrosion was negligible (≈0.0016 mm·year⁻¹). Multi-scale imaging linked observed morphologies (porous FeCO₃ scales, under-deposit pits) to measured rates and supported stage-specific mitigation recommendations. The novelty of this work lies in the integrated, staged HTHP experimental approach and in providing quantitative, actionable inputs for material selection, inhibitor deployment, and monitoring strategies for CCS–EGS projects that reuse depleted hydrocarbon reservoirs.