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.

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Dobór dodatków do energetyzowanych płynów szczelinującychSzczelinowanie hydrauliczne jest obecnie najpopularniejszą metodą stymulacji złóż gazu i ropy w formacjach niekonwencjonalnych. Jest ono niezbędne do umożliwienia eksploatacji złóż węglowodorów z formacji o bardzo małej przepuszczalności, tj. tight gas. Pokłady węgla oraz łupki gazonośne nie mogą być eksploatowane bez wykonania tego typu zabiegów [10]. W przypadku, gdy użyte ciecze szczelinujące wykonane są na bazie wody, może wystąpić tzw. uszkodzenie przepuszczalności, spowodowane m.in. pęcznieniem minerałów ilastych lub działaniem innych mechanizmów fizycznych i chemicznych zachodzących w szczelinowanej formacji [5]. Rolą cieczy szczelinującej jest wygenerowanie i propagacja szczelin. Zastosowana ciecz powinna również posiadać odpowiednie właściwości, które pozwolą na utrzymanie wtłaczanych materiałów podsadzkowych w formie zawiesiny, a następ-nie umożliwią cieczy pozostawienie podsadzki w szczelinie wytworzonej w złożu. W poszukiwaniu innych metod szczelinowania zwrócono uwagę na zastosowanie cieczy energetyzowanych jako mniej inwazyjnej metody szczelinowania formacji wrażliwych na obecność wody. W artykule zaprezentowano badania laboratoryjne, które miały na celu dobór odpowiednich środków do energetyzowanych płynów szczelinujących, w tym: biocydów, środków powierzchniowo czynnych, polimerów i środków spieniających oraz ich stężeń. Głównym celem było opracowanie skutecznej metody oceny zależnych od czasu właściwości płynów szczelinujących w warunkach złożowych.Słowa kluczowe: płyny energetyzowane, płyny szczelinujące, dodatki do płynów spienionych. Selection of additives for energized fracturing fluidsHydraulic fracturing is now the most popular method of stimulating gas and oil reservoirs in non-conventional formations. Fracturing is necessary to enable the production of hydrocarbon from formations of very low permeability, i.e. tight gas, coal and gas-bearing shales deposits, that cannot be exploited without fracking [10]. When fracking fluids used are based on water, so-called permeability damage caused by, among others, swelling of clay minerals, or by other physical and chemical mechanisms taking place in a formation being fractured [5] is likely to occur. The role of fracking fluid is to generate and propagate fractures. Any applied fracking fluid, should also have appropriate properties to make forced proppant materials keep the form of a suspension, and then to make fluid leave proppant in a fracture generated in a reservoir. In the search for alternative methods of fracturing, we drew our attention to, the use of energized fluids as a promising method of fracturing water sensitive formations. The article presents laboratory tests that focused on the selection of appropriate fracturing fluids additives; including biocides, surfactants, polymers and foaming agents and their concentrations. The main aim was to develop effective methods for evaluation of time-dependent properties of the fracturing fluids, at reservoir conditions. Key words: energ...

The first objective of this experiment was to improve the stabilization of N2 based foam with nanoparticles as an alternative to typical fracturing fluid, which consists of a gelling agent (HPG—hydroxypropyl guar). The second objective of the project was to investigate the damage caused by nanoparticle–based nitrogen foamed fracturing fluids (F.F) on a reference sandstone, using permeability and porosity tests, optical microscope with a Profilometer, and a scanning electron microscope (SEM). The properties of F.F with two types of SiO2 nanoparticles (hydrophilic fumed silica Areosil 300 and silica sol U-2 obtained by the sol-gel method), such as rheology and core damage, were investigated. The discussion of this research results is based on the stability tests carried out with the use of rheology and the foam half-life, formation damage ratio, and observation of exposed samples using SEM and the Profilometer. The permeability and porosity damage ratios of the damaged core samples were found to decrease when nitrogen foamed fluids were used. These results were confirmed with the Profilometer and SEM images. The experimental data showed that the foam stability increased when silica (SiO2) nanoparticles were added. SiO2 nanoparticle-surfactant-stabilized foam for fracturing is superior to traditional water-based fracturing fluids and causes lower core permeability damage than a traditional F.F.

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The use of water-based fracturing fluids during fracturing treatment can be a problem in water-sensitive formations due to the permeability damage hazard caused by clay minerals swelling. The article includes laboratory tests, analyses and simulations for nitrogen foamed fracturing fluids. The rheology and filtration coefficients of foamed fracturing fluids were examined and compared to the properties of conventional water-based fracturing fluid. Laboratory results provided the input for numerical simulation of the fractures geometry for water-based fracturing fluids and 50% N2 foamed fluids, with addition of natural, fast hydrating guar gum. The results show that the foamed fluids were able to create shorter and thinner fractures compared to the fractures induced by the non-foamed fluid. The simulation proved that the concentration of proppant in the fracture and its conductivity are similar or slightly higher when using the foamed fluid. The foamed fluids, when injected to the reservoir, provide additional energy that allows for more effective flowback, and maintain the proper fracture geometry and proppant placing. The results of laboratory work in combination with the 3D simulation showed that the foamed fluids have suitable viscosity which allows opening the fracture, and transport the proppant into the fracture, providing successful fracturing operation. The analysis of laboratory data and the performed computer simulations indicated that fracturing fluids foamed by nitrogen are a good alternative to non-foamed fluids. The N2-foamed fluids exhibit good rheological parameters and proppant-carrying capacity. Simulated fracture of water-based fracturing fluid is slightly longer and higher compared to foamed fluid. At the same time, when using a fluid with a gas additive, the water content in fracturing fluid is reduced which means the minimization of the negative results of the clay minerals swelling.

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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.