Production from mature oil fields is gradually declining, and new discoveries are not sufficient to meet the growing demand for oil products. Hence, enhanced oil recovery is emerging as an essential link in the global oil industry. This paper aims to recognize the possibility of increasing oil recovery from Polish carbonate reservoirs by the water alternating gas injection process (WAG) using various types of gases, including CO2, acid gas (a mixture of CO2 and H2S of 70/30% vol/vol) and high-nitrogen natural gases occurring in the Polish Lowlands. A series of 17 core flooding experiments were performed under the temperature of 126 °C, and at pressures of 270 and 170 bar on composite carbonate cores consisting of four dolomite core plugs. Original reservoir rock and fluids were used. A set of slim tube tests was conducted to determine the miscibility conditions of the injected fluids with reservoir oil. The WAG process was compared to continuous gas injection (CGI) and continuous water injection (CWI) and was proven to be more effective. CO2 WAG injection resulted in a recovery factor (RF) of up to 82%, where the high nitrogen natural gas WAG injection was less effective with the highest recovery of 70%. Based on the core flooding results and through implementing a genetic programming algorithm, a mathematical model was developed to estimate recovery factors using variables specific to a given WAG scheme.

Geological sequestration of acid gases, including CO2, is now a growing solution to prevent progressive Earth climate change. Disposal of environmentally harmful greenhouse gases must be performed safely and securely to minimise leakage risk and possible uncontrolled emissions of injected gases outside the sequestration structure. The paper describes a series of research activities at the Borzęcin sequestration site located in western Poland, which were designed to study the migration paths of injected acid gases (mainly mixture of CO2 and H2S) into the water-bearing layers underlying natural gas reservoir. Along with understanding the nature and dynamics of acid gases migration within the sequestration structure, the research was also addressed to assess its leak-tightness and the long-term safety of the entire reinjection facility. As a part of the research works, two downhole sampling campaigns were completed in 2018–2019, where samples of water underlying the Borzęcin reservoir were taken and subsequently studied to determine their physicochemical parameters that were never before examined. Compositions of gas dissolved in downhole brine samples were compared with produced and injected gas. Relevant studies of reservoir water from selected wells were performed, including isotopic analyses. Finally, four series of soil gas analyses were performed on the area surrounding the selected well, which are important for the hazardous gas sequestration safety analysis in the Borzęcin facility. All the above mentioned research activities aimed to acquire additional knowledge, which is valuable for risk assessment of the acid gas sequestration process taking place on the specific example of the Borzęcin site operating continuously since 1996.

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This paper discusses the issues of the impact of pressure and temperature on the precipitation of paraffin deposits from reservoir fluids in the presence of previously prepared paraffin inhibitors. Using a properly modified PVT apparatus, the temperature of the beginning of paraffin precipitation (wax appearance temperature—WAT) has been determined, below which the solid paraffin phase was captured on a specialized filter in various temperatures. Based on the conducted experiments, a boundary has been established separating the paraffin area (the presence of paraffins as their solid phase) from an area without paraffin. Measurements of the amount of paraffin using the filter allowed the determination of the WPC (wax precipitation curve), due to which additional data is provided regarding the amount of precipitated paraffin deposit below the WAT. The developed methodology enables to conduct the measurements within a wide range of pressures using the sample saturated with reservoir gas, which can test the crude oil sample that corresponds to the actual production conditions. Most known research methods do not allow such preparation of a sample and conducting the measurements under pressurized conditions; therefore, the produced results are subject to errors. The paper describes also the studies of efficiency and differences in the action of various paraffin inhibitors. Based on the performed research, a comparison was made involving the action of agents under the pressureless conditions of dead oil and pressurized crude oil samples saturated with gas. The performed studies allowed the determination of equilibrium conditions (in a pressure–temperature system), under which deposition of the solid paraffin phase occurs during the use of three various inhibitors. Based on the performed experiments, an area with a paraffin hazard was determined, along with an area without paraffins. Due to the separation of the precipitated solid paraffin phase, an increase in the mass of the paraffin deposit associated with a temperature drop was determined (wax precipitation curve), as well as the impact of the applied inhibitors on its course.

Crucial oil reservoirs are located in naturally fractured carbonate formations and are currently reaching a mature phase of production. Hence, a cost-effective enhanced oil recovery (EOR) method is needed to achieve a satisfactory recovery factor. The paper focuses on an experimental investigation of the efficiency of water alternating sour and high-nitrogen (~85% N2) natural gas injection (WAG) in mixed-wetted carbonates that are crucial reservoir rocks for Polish oil fields. The foam-assisted water alternating gas method (FAWAG) was also tested. Both were compared with continuous water injection (CWI) and continuous gas injection (CGI). A series of coreflooding experiments were conducted within reservoir conditions (T = 126 ℃, P = 270 bar) on composite cores, and each consisted of four reservoir dolomite core plugs and was saturated with the original reservoir fluids. In turn, some of the experiments were conducted on artificially fractured cores to evaluate the impact of fractures on recovery efficiency. The performance evaluation of the tested methods was carried out by comparing oil recoveries from non-fractured composite cores, as well as fractured. In the case of non-fractured cores, the WAG injection outperformed continuous gas injection (CGI) and continuous water injection (CWI). As expected, the presence of fractures significantly reduced performance of WAG, CGI and CWI injection modes. In contrast, with regard to FAWAG, deployment of foam flow in the presence of fractures remarkably enhanced oil recovery, which confirms the possibility of using the FAWAG method in situations of premature gas breakthrough. The positive results encourage us to continue the research of the potential uses of this high-nitrogen natural gas in EOR, especially in the view of the utilization of gas reservoirs with advantageous location, high reserves and reservoir energy.