ERE5.7

Natural gas hydrate (NGH) is the most promising clean alternative energy resource for world. Based on the analysis of the bottleneck problems in hydrate recovery method, the achievement of reservoir-scale production of NGH by depressurization depend on three key factors, namely heat supply, reservoir stability and reservoir permeability. Based on the three principles of depressurization, in-situ supplemental heat and backfilling and increased permeability, the novel method, depressurization and backfilling with in-situ supplemental heat method was proposed. In this method, calcium oxide (CaO) powder is injected into the hydrate reservoir, which will provide a large amount of heat for the decomposition of NGH. At the same time, the Ca(OH)₂ produced by the reaction will backfill the void volume left by hydrate decomposition and improve the permeability of the reservoir. The method is mainly implemented in three stages, i.e., horizontal well drilling and completion, powder injection and depressurization and backfilling. Currently, the two-dimension and three-dimension numerical simulations based on this novel method are completed. And the simulation results quantitatively verify the potential value of the depressurization and backfilling with in-situ supplemental heat method from the perspective of the theoretical calculation of numerical model. Based on the key procedures of this method, the related physical simulations for specific operating technique, such as CaO injection and corresponding production performance, are advancing. Combining above promising simulation results, this novel method is expected to be an effective hydrate recovery method.

How to cite: Li, S., Zhang, Z., Sun, Y., Xu, T., Li, X., and Wang, S.: A Novel Method for Natural Gas Hydrate Production: Depressurization and Backfilling with In Situ Supplemental Heat, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-9086, https://doi.org/10.5194/egusphere-egu22-9086, 2022.

Oil production in karst areas often leads to negative consequences for ecosystems, including aquatic ones, since karst creates favorable conditions for the migration of oil mining pollution.

The study area is located in the oil and gas bearing zone of the Western Urals, the territory is assigned to the area of gypsum and carbonate-gypsum karst. The site (river basin) of one of the old-developed fields of the Perm Region was studied, which is characterized by a large number of oil mining infrastructure facilities.

The purpose of this study is to identify the features of technogenic transformation of ecosystems in karst conditions. For this, a field survey of the territory, sampling of surface and underground waters, grounds, bottom sediments and soils, measurements of the concentrations of pollutants in the air, the presence of the main ecological and trophic groups of microorganisms in water samples were carried out.

The process of hydrocarbons input (bitumization) covered karst cavities, springs, streams of the study area. In time, the concentration of hydrocarbons increased during periods of high water. Spatially, the hydrocarbon content gradually decreased from the polluted springs in the direction of the river mouth.

The increased content of hydrocarbons in bottom sediments (up to 54,872 mg/kg) was observed at almost all sample plots.

Areas with a tendency to accumulation of hydrocarbons were identified within the boundaries of the study area (soil pollution near the well cluster in the upper part of the river basin exceeds 100,000 mg/kg). Bottom sediments and soils are a deposit medium for pollutants, they can become secondary sources of pollution.

Microorganisms are an integral part of ecosystems, which serve as indicators of pollution. Quantitative changes in the group of heterotrophic and oil-oxidizing microorganisms of the spring microbocenosis are multidirectional. An increase in the number of heterotrophs and a decrease in the number of oil-oxidizing microorganisms are observed.

Technogenic salinization during oil production is an accumulation of salts (chlorides, sulfates, carbonates), which are contained in large quantities in high-mineralized stratal waters extracted along the way. The maximum values of chloride concentrations were recorded in the upper part of the river basin.

The karst region is composed of sulfate rocks, which have greater solubility compared to carbonate rocks, we believe that this primarily explains the high content of sulfate ion in water samples.

The increased salinity of the aquatic environment can be judged by the presence of halophilic microorganisms. At the points where halophilic organisms were detected, chloride concentrations exceeding background values were recorded. It should be noted that the number of halophiles is low.

Excess concentrations of benzene, hexane, toluene, hydrogen sulfide, and methane were recorded in the atmospheric air at certain points.

The transformation of ecosystems in the study area has a pronounced degradation orientation. Hydrocarbons make the greatest contribution to environmental pollution, and the presence of karst forms only aggravates the situation.

Measures to localize pollution and organizational recommendations to improve the environmental situation were proposed for each problem area.

The reported study was funded by Russian Foundation for Basic Research (RFBR) and Perm Territory, project number 20-45-596018.

How to cite: Khotyanovskaya, Y.: Technogenic transformation of ecosystems in the karst area during oil production, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-6883, https://doi.org/10.5194/egusphere-egu22-6883, 2022.

Taking into account the world-wide energy crisis, the search and rational use of cheap and

ecologically pollution-free renewable energy sources are extremely important. Among these sources the geothermal energy is of great potentialities. Tbilisi has a high potential of geothermal sources, which have been in use since ancient times. The major areas of utilization are balneology and local heating of community and residential buildings. It also should be noted that most of the geothermal wells are non-operational. Therefore, a re-assessment of the geothermal potential of the Tbilisi deposit is of major importance from the standpoint of economic development based upon renewable, ecological cleaner energy sources. Field hydrogeophysical investigations (tentative testing, regime hydrodynamic and hydrochemical observations) have been carried out to assess the main thermo-hydrodynamic parameters of water containing horizons. In the field and laboratory conditions thermal properties of aquifer matrix rocks as well as vertical and horizontal zonality of thermal flow have been investigated.

During testing the hydrodynamic influence of well Lisi 5 on wells Lisi 7 and 8, as well as on well Saburtalo 1 was established. It appears that wells Saburtalo 4 and 6 are out of influence area, they are not influenced by well Lisi 5, which points to their independent regime. For the proper characterization of this water regime and assessing its influence area additional testing should be carried out in the future.

Based on previous and newly obtained geologic, hydrogeological and geophysical data, 3D model of Tbilisi thermal region was created which takes into account complexity of area, its separation into domains by faults, and their different hydrodynamic zonality. For modeling computer softwares such as Feflow 5.3, AquiferTestPro, etc. have been applied, which enabled to define hydrothermal resources and assess hydraulic parameters of water containing layers.  As a result of modeling work, the 10-year perspective of thermal deposit of Tbilisi was assessed at the present conditions of exploitation.

In the whole region subsidence of water horizon is expected. For example, in the Lisi district, if mean yearly discharge (exploitation rate) is preserved, water table drops by 2-5 m and the released thermal energy decreases from 5.5*10²⁰  to 1.578*10¹⁷ J.  According to the simulated geothermal circulation system, when the used water of well 5 (1690 m³/day cooled down to 30 ⁰C) was reinjected to the well 1 with negative level, ‘cooling of horizon and subsidence’ tendency became slower. Therefore, in the future creation and implementation of geothermal circulation systems are recommended.  This will help to achieve economical and ecologically approved exploitation of geothermal resources.

How to cite: Kapanadze, N., Melikadze, G., Todadze, M., Tsutskiridze, E., and Fórizs, I.: Assessment of Geothermal Potential in the Tbilisi Geothermal Reservoir, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-4374, https://doi.org/10.5194/egusphere-egu22-4374, 2022.

Hydraulic Fracturing (HF) aims at enhancing the permeability of oil and gas production reservoirs by injecting fluids at high pressures into the formation. However, this practice has been a concern to researchers; it causes perturbation to the underground system, alters the pressures and stresses along the nearby dormant faults, and may therefore, induce earthquakes under specific conditions. In this work, we study the efficacy of using a newly emerging technique, Cyclic Hydraulic Fracturing (CHF), to reduce the risk of induced seismicity while efficiently enhancing the reservoir permeability. Instead of injecting the fluid all at once at a high pressure during each stage, CHF increases the connectivity of the reservoir by injecting the same volume in a stage through different cycles. Each cycle represents a pressurization (injection) phase and a depressurization (zero-injection) phase. The effect of CHF on the stability of a fault at a close proximity to the HF operations is assessed using different injection strategies: conventional HF (constant injection per stage) and 2 CHF schemes (3 or 5 cycles per stage). For each strategy, we calculate the Coulomb Failure Stress (CFS) and the rate of seismicity along the fault using a 2D Finite Element poroelastic model. Our numerical simulations show that CHF delays the pore pressure diffusion along the fault due to the depressurization phases that allow the relaxation of the pore fluid pressure. It also reduces the seismicity rate on the fault when compared to conventional HF. Our results suggest that the mitigation of induced seismicity is possible by using a CHF procedure optimized to reduce the seismicity rate i.e., optimized number of cycles and pressurization/depressurization periods. This development paves a way to exploit sites that are abandoned due to seismic hazards.

How to cite: Yassine, D., Yehya, A., and Maalouf, E.: Mitigation of Seismic Hazards from Hydraulic Fracturing Using Cyclic Injection, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-7882, https://doi.org/10.5194/egusphere-egu22-7882, 2022.

For several decades, research on CCUS (carbon capture, storage, and utilization) have been extensively carried out to achieve substantial reduction of the amount of CO₂ emitted into the atmosphere and effective resource development. In recent years, high temperature reservoirs have recently been considered as a target for CO₂ injection. This aims at development of unconventional geothermal resources and CO₂ mineralization.

Since the value of CO₂-water interfacial tension is a fundamental property of fluid behavior in CO₂-water-rock systems, many studies have been reported on CO₂-water interfacial tension. However, the temperature of the geothermal reservoir in the above-mentioned technology may be up to 300 ℃, which is much higher than typical conditions for CCUS. It is not easy to perform measurements under such high temperature conditions, and no experimental data have been reported in existing studies.

Therefore, in this study, we performed molecular dynamics simulations to estimate the interfacial tension up to 300 ℃, and also studied the detailed properties such as density and dynamics.

How to cite: Shiga, M., Morishita, T., and Sorai, M.: Interfacial Tension of CO2-Water Under Conditions for High-Temperature Geothermal Systems: Prediction and Investigation by Molecular Dynamics Simulation, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-6837, https://doi.org/10.5194/egusphere-egu22-6837, 2022.

The interaction of CO₂ with the shale reservoir in the process of CO₂ fracturing can change the pore-throat structure characteristics of the rock. In order to determine the microscopic pore throat change characteristics in shale reservoir after CO₂ fracturing , typical shale core samples before and after fracturing were selected, combined with casting thin slice(CST), field emission scanning electron microscope(FESEM), CT scan, high pressure mercury injection(HPMI), and nuclear magnetic resonance(NMR) test results, and quantitatively evaluate the change characteristics of micro pore throats in shale  reservoir after CO₂ fracturing. The results show that various storage spaces such as intergranular pores, intragranular pores, organic pores, and microfractures can be observed in shale reservoirs before CO₂ fracturing, which are with poor pore throat connectivity, and most of them are distributed in a dispersed and isolated state. The discharge pressure is low, 0.89Mpa on average, the mercury removal efficiency is low, and the maximum mercury saturation difference is large. Movable fluid saturation ranges from 2.72% to 41.24%, with an average of 26.78%. After CO₂ fracturing the shale reservoir, FE-SEM photos often show dissolved pores. The proportion of micro-cracks increased, and the number of cracks observed for a single sample ranged from 1 to 11, with an average of 4. The average length, opening and spacing of micro-cracks are 27.75μm, 286.63μm, and 3.70μm. The average porosity and permeability of micro-cracks are 9.03% and 1.74×10^-3μm². The pore throat connectivity of the shale samples becomes better, the degree of development is higher, the displacement pressure is increased to 3.05MPa, and the mercury removal efficiency and the maximum mercury saturation are both increased. NMR results showed that the movable fluid saturation of shale core samples increased significantly after CO₂ fracturing, and the movable fluid saturation was between 1.57% and 50.25%, with an average of 38.14%. CO₂ fracturing shale reservoirs will not only produce secondary fractures, but also easily form complex fracture networks. In addition, it will also improve the dense micro-pore throat structure of the shale reservoir itself, increase fluid seepage capacity, and increase oil and gas recovery.

How to cite: He, M., Li, T., Huang, X., Li, X., and Wu, K.: Characteristics of microscopic pore throat changes in shale reservoir after CO2 fracturing, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-4295, https://doi.org/10.5194/egusphere-egu22-4295, 2022.

As shale gas exploitation proceeds, reservoir pressure progressively decreases. While using CO₂ or water to enhance shale gas recovery, it is important to investigate their effects on the mechanical properties of shale under dynamic pressure conditions. In this study, we have investigated the effects of supercritical CO₂ and water immersion on the mechanical properties of shale under different dynamic pressures (pressure change 1: decreasing from 20 MPa to 8 MPa; pressure change 2: decreasing from 42 MPa to 30 MPa). The testing results indicate that, after soaking in supercritical CO₂ and water, the uniaxial compressive strength (UCS) of shale is decreased by 51.05% and 58.36% (pressure change 1), and by 35.98% and 36.84% (pressure change 2), respectively. The strength and Young's modulus of shale are decreased more significantly after water immersion compared to supercritical CO₂ immersion. Due to the matrix compression effects, the mechanical properties of shale are changed more significantly under lower imbibition pressures. Supercritical CO₂ immersion leads to an increase in the Poisson's ratio along with more complex fracture patterns, whereas water immersion results in a slight decrease in the Poisson's ratio associated only with shear fracture formation. The acoustic emission (AE) signals display obvious stage characteristics during the compressional deformation of the samples, and the AE energy is mainly generated in during the unstable crack propagation stage. Supercritical CO₂ immersion plays an important role in crack generation, whereas water immersion is dominated by the alteration of the pore structure. Compared with the constant pressure imbibition, the dynamic pressure imbibition changes the microstructure of shale and weakens its mechanical properties more significantly. The results of this study provide a clearer understanding of the effects of CO₂ and water on the mechanical properties of shale during exploitation of shale gas.

How to cite: Lyu, Q., Wang, K., Tan, J., and Wood, D.: Experimental investigation on the mechanical properties of shale soaked in supercritical CO₂ / water at dynamic pressures, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-13139, https://doi.org/10.5194/egusphere-egu22-13139, 2022.

Impacts of saturation with CO₂ and CO₂-based liquids are vital for understanding shale's mechanical properties associated with supercritical-CO₂ optimized shale gas extraction and geological capture and storage of CO₂ in shale reservoirs. A sequence of triaxial compression tests is performed to examine the impact of subcritical CO₂, supercritical CO₂, subcritical CO₂-water, supercritical CO₂-water, subcritical CO₂-NaCl, and supercritical CO₂-NaCl saturation on shale strength. A statistical damage constitutive model of shale after CO₂, CO₂-water, and CO₂-NaCl saturation is established to describe shale's stress-strain relationships under various immersion conditions.

The laboratory findings indicate that the change of the axial stress, Young's modulus, and axial strain of shale after immersion verifies the physical and chemical reactions that occur between shale and the soaking fluids. Mechanical properties of shale show the greatest variations after CO₂-water saturation. The variation in mechanical properties of shale after CO₂-NaCl saturation is smaller than those of shale under CO₂-water saturation owing to the precipitation of NaCl crystals. Pure CO₂ saturation has the smallest influence on shale's mechanical properties among the three types of liquids assessed. CO₂ in a supercritical state shows a stronger impact on shale than the subcritical state for the same sort of fluids. Also, following saturation, all the shales display a mixed tensile-shear failure mode. The cohesion force of shale increments following pure CO₂ saturation, whereas it diminishes following CO₂-water and CO₂-NaCl saturation. Decreases in the internal friction angles are observed for all the soaked shales. The anisotropy of shale leads to a slight difference between the actual failure angle and the failure angle measured by the Mohr-Coulomb criterion.

The stress-strain relationship of shale under different confining pressures is effectively described by the Weibull probability distribution and the principle of strain equivalence. This establishes statistical damage constitutive equations of shale under different soaking conditions. The values of key modeling parameters, including F₀ and m, are highly dependent on the brittleness and strength of shale associated with various soaking conditions.

How to cite: Xie, B., Lyu, Q., Tan, J., and Wood, D.: Mechanical properties of shale following saturation with CO2 and CO2-based fluids: experimental and modeling study, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-13143, https://doi.org/10.5194/egusphere-egu22-13143, 2022.

Fluids-shale interactions during hydraulic fracturing alters the pore characteristics and hydraulic properties of shale, thus affecting the oil and gas recovery efficiency and the geological storage capacity of shale reservoirs.  Short-term (0-1 month) and long-term (1-12 months) experiments are conducted to investigate the fluids-shale interaction behaviour during fracturing fluid injection and retention periods. The effects of fluids-rock interaction on pore characteristics and hydraulic properties are determined by characterizing the shale's mineralogy, surface morphology, pore structure characteristics, and hydraulic properties before and after the experiments. The experimental results show variability during the fluid injection and retention periods. In the short-term experiments, pyrite dissolution caused a rapid decrease in fluid pH (decreased by 1.7-5.1). In long-term experiments, feldspar and clay mineral dissolution caused a slow increase in fluid pH (increased by 0.5). The dissolution of minerals enlarged the native pores of the shale, thereby increasing the porosity, raising the average pore diameter, and increasing the gas adsorption capacity of the shale (by 14.1%). Measurements of fractal dimension D1 indicate that the pore surfaces become rougher during the short-term experiments, whereas the pore surfaces become smoother during the long-term experiments. The change in pore structure affects the hydraulic properties of the shale. In particular, the absolute permeability of the shale increased (60.0-129.1%), while the pore tortuosity decreased (26.1%-57.8%). However, as the pH rises above 4, substantial gypsum and iron hydroxide precipitation occurs, blocking shale fractures and pores. Such precipitation reduces shale porosity, hydraulic properties, and sorption capacity. On the other hand, lower pH (below 3.5) can inhibit the formation of secondary precipitation. Monitoring pH changes is, therefore, the key to improving oil and gas recovery by enhancing reservoir geological storage capacity following hydraulic fracturing.

How to cite: Hu, C., Tan, J., Lyu, Q., Dick, J., and Wood, D.: Pore characteristics and hydraulic properties of shale samples under long-term exposure to hydraulic fracturing fluids, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-13144, https://doi.org/10.5194/egusphere-egu22-13144, 2022.

Hydraulic fracturing is a widely used technique for oil and gas extraction from the ultra-low porosity and permeability shale reservoirs. By injecting a large amount of fracturing fluids with specific chemical additives into shale reservoirs, porosity and permeability can be significantly improved, and thus enhances the recovery of oil and gas. However, hydraulic fracturing will not only bring economic benefits, but also cause a series of environmental issues, e.g., earth surface and water pollution. The Niutitang shale characterized by wide distribution, great thickness, high organic matter and brittle mineral contents is one of primary targets of shale gas development in South China. This research aims to simulate rock-fluid reaction and investigate the evolution of fluid composition and shale characteristics occurred during the hydraulic fracturing of the Niutitang shale. 

Two sets of shale samples from different depths of a well located in Central Hunan Province were exposed to fracturing fluids with different pH values. Afterwards, changes in the fluids and the shale matrix were investigated through a series of geochemical, mineralogical, and textural analysis. By comparing results of different experiments at different scales, key geochemical rock-fluid reactions occurred during this process were found, and their potential influences on shale gas production were discussed. 

Experimental results show obvious mineral dissolution, in particular the oxidation of pyrite.  Pyrite oxidation significantly alters fracturing fluids and subsequently impacts on the dissolution of other minerals. During the process of pyrite dissolution, hydrogen ions release into the fluids, leading to obvious acidification. The acidified solution dissolves carbonate and feldspar minerals. Meanwhile, in the process of mineral dissolution, heavy metals or radioactive elements release as well, e.g., Ba, U, and Sr, which are all primary toxic elements of flowback fracturing fluids. The interaction between shale and fracturing fluid also causes changes in the shale matrix. Comparisons between shale samples before and after experiments clearly show density decrease while porosity increase. In addition, pore types change from ink bottle-shaped thin neck hole dominance to long and narrow plate-shaped hole dominance. Through the theoretical calculation of saturation index and observation by scanning electron microscope, we found that mineral dissolution is accompanied by secondary mineral precipitation, e.g., Fe-(oxy) hydroxide and gypsum. These precipitates, nevertheless, could potentially restrict the migration of metal elements by adsorption or co-precipitation, occlude the pore systems, and finally decrease the recovery of shale oil and gas. Overall, we conclude that mineral compositions and physical properties of the shale are among primary factors controlling fluid-rock reactions. Therefore, mineral composition and textural analysis are critical to fracturing fluid design and important to lowering environmental risks caused by flowback fluids. 

How to cite: Tan, J. and Li, G.: On the shale-fluid reactions occurred in the hydraulic fracturing process of shale gas development: insights from lab simulation, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-13093, https://doi.org/10.5194/egusphere-egu22-13093, 2022.