Hydraulic fracturing (HF) is a well-known stimulation method used to increase production from conventional and unconventional hydrocarbon reservoirs. In recent years, HF has been widely used in Enhanced Geothermal Systems (EGS). HF in EGS is used to create a geothermal collector in impermeable or poor-permeable hot rocks (HDR) at a depth formation. Artificially created fracture network in the collector allows for force the flow of technological fluid in a loop between at least two wells (injector and producer). Fluid heats up in the collector, then is pumped to the surface. Thermal energy is used to drive turbines generating electricity. This paper is a compilation of selected data from 10 major world’s EGS projects and provides an overview of the basic elements needed to design HF. Authors were focused on two types of data: geological, i.e., stratigraphy, lithology, target zone deposition depth and temperature; geophysical, i.e., the tectonic regime at the site, magnitudes of the principal stresses, elastic parameters of rocks and the seismic velocities. For each of the EGS areas, the scope of work related to HF processes was briefly presented. The most important HF parameters are cited, i.e., fracturing pressure, pumping rate and used fracking fluids and proppants. In a few cases, the dimensions of the modeled or created hydraulic fractures are also provided. Additionally, the current state of the conceptual work of EGS projects in Poland is also briefly presented.

The beginning of 2022 was a time of major changes in the perception of energy availability and security in European countries. The aggression of Russia against Ukraine destabilizing the European energy economy, combined with the withdrawal from fossil fuels which has been going on for a dozen years, has strengthened activities to introduce new energy technologies based on renewable energy sources. One of the most promising and stable sources of renewable energy is geothermal energy, in particular enhanced geothermal systems (EGS) in hot dry rocks (HDR). These deposits occur at a great depth in almost every place on Earth, but due to their low permeability, they require hydraulic fracturing, which results in high investment costs. This technology has been developed for several decades. The current situation in Europe seems to confirm that its rapid development to a level that guarantees stable and profitable operation is crucial. This is of particular importance in the case of former member states of the economic zone of the Council for Mutual Economic Assistance, which until recently were heavily dependent on Russian energy. This review, based on the latest available data, covers potential HDR prospective areas in the countries of the south-eastern Baltic basin, including Lithuania, Latvia, Estonia and Poland. It is specific to this region that the original heat flux density is lower as a result of the paleoclimatic effect associated with the youngest ice age; however, thermal conditions do not deviate too much compared to western Europe, especially Rhine Graben, and significantly exceed the conditions of Finland, where an EGS project is currently being operated. In Lithuania, the most prospective area is the ZNI intrusion (south of Klaipeda), characterized by a geothermal gradient of up to 40 °C/1000 m. In addition, the Precambrian batholith south of Liepāja (Latvia) and the Rapakivi granites in the north and center of Estonia are promising EGS sites. Poland has relatively the most explored EGS potential, in both volcanic, crystalline and sedimentary rocks, especially in the area of the Szczecin Trough, Gorzów Block, Moglino-Łódź Trough and Karkonosze Mountains. Unfortunately, local tectonic conditions, in particular the development of faults and natural fracture zones that affect the directions of fracture propagation during hydraulic fracturing, have not been sufficiently recognized, which is one of the main barriers to the expansion of EGS pilot projects in these countries. These issues present challenges for the researchers, especially in terms of petrophysical analyses of rocks in target zones and local stress conditions, which have a key impact on fracturing operations and profitability of the systems. Despite high investment costs on the one hand and a significant slowdown in the global economy in 2022 on the other, it remains hopeful that the authorities of individual countries will decide to accelerate research work, leading to the implementation of pilot projects of EGS installations, and that this technology will be further improved to ensure a stable clean energy supply.

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.

The Young’s modulus and Poisson’s ratio, parameters reflecting the elastic response of a rock to stress, are the key parameters used in many engineering activities, such as hard coal mining and natural gas extraction. The objective of this paper was to present the results of complex laboratory measurements of the static and dynamic Young’s modulus and Poisson’s ratio for Upper Carboniferous hard coals from the Upper Silesian Coal Basin. The coals differed in geologic age (Mudstone Series—younger coals; Upper Silesian Sandstone Series—older coals) and petrographic structure (vitrain, clarain, and durain lithotype). Elastic parameters of the coals were determined following compression tests under a complex state of stress, as well as using the ultrasonic method in reservoir conditions. On this basis, linear functional dependences between parameters such as UCS, differential stress, confining pressure, strain rate, P- and S-wave velocities, and the static and dynamic Young’s modulus and Poisson’s ratio were determined. These dependences turned out to be linear, with strong and very strong correlation, as indicated by the high coefficients of determination, R². These new results significantly broaden the knowledge of elastic properties of Carboniferous hard coals, especially in the field of geoengineering, underground coal gasification, and reservoir stimulation for coal bed methane extraction.

Hydraulic fracturing is a well-known stimulation technique for creating fractures in a subsurface formation to achieve profitable production rates in low-permeability reservoirs. Slickwater has been widely used as a traditional fracturing fluid. However, it has multiple disadvantages, such as high consumption of water, clay swelling and low flowback recovery. Foam, as an alternative fracturing fluid, consumes less liquid and provides additional energy. However, foam bubbles are typically unstable due to the degradation of surfactants, particularly in high temperature reservoirs, which reduces their capabilities of carrying and placing proppants into fractures. The purpose of this study is to provide general guidelines for an optimised application of polymers to improve the foam stability in high temperature reservoirs while increasing the proppant placement and water usage efficiencies. In this paper, the effects of natural hydroxypropyl guar (HPG) and synthetic polyacrylamide (PAM) polymers on the rheological properties of nitrogen foam-based fluids were examined by laboratory experiments conducted using temperatures up to 110°C. Then, a 3D hydraulic fracture propagation model was developed to study the fracturing performance of HPG-foamed and PAM-foamed fluids in the Toolachee Formation, Cooper Basin. It was found that synthetic PAM polymers were more effective than natural HPG polymers in stabilising foam viscosity under high temperature conditions. The simulation results indicate that foam-based fluids totally outperform slickwater in the field case application. This paper emphasises the significance of crosslinkers, foam quality and thermal stability on the performance of foams in high temperature environments.

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.