Stored Gas Research Articles

Mechanism of the Production Impact in Shale Gas Wells Caused by Water Invasion during Interwell Interference.

Interwell interference is a universal problem in shale gas development and can cause severe reductions in the productivity of producing wells. Studies have attempted to identify the root cause of interference in producing wells, but the mechanisms of production reduction and recovery in impacted wells are still not clear. Thus, an effective preventive strategy is needed for producing wells when fracturing is performed in adjacent wells. According to the mechanism of spontaneous imbibition and water drainage in shale mico- and nanoscale pores, this paper introduces the water–gas distribution during fracturing and production and reveals that water drainage in micro- and nanoscale pores is mainly controlled by the amount of stored gas and follows the order of pore size. Based on this analysis, the mechanism by which interwell interference impacts the production of producing wells is explained for the first time. It is concluded that the secondary water invasion caused by interwell interference completely blocks the pores associated with long-term gas production but has little influence on the pores that have not yet drained or have produced only a small amount of gas, and smaller pores face a greater risk of water blockage. The proportion of drained pores formed during long-term gas production determines the effect of interwell interference on production; when more pores are drained by long-term gas production, greater damage occurs to the productivity of the producing well. The suggestion for preventing interwell interference is to reduce the time interval between fracturing operations at two adjacent wells, thereby diminishing the reduction in production.

A Review on Well Integrity Issues for Underground Hydrogen Storage

Abstract Renewable energy production is limited by the fluctuations limiting their application. Underground hydrogen storage (UHS) is one possible alternative to reduce the gap between supply and demand by storing the energy converted to hydrogen as a carrier and store it during surplus to produce it during high demand periods. The hydrogen is stored in the subsurface in geological formations containing the gas and is injected/produced via wells. There is a lack of experience associated with this technology and only a small number of projects worldwide. There are several mechanisms that can compromise the integrity of the well and generate leakage of the stored gas. This paper aims to introduce the challenges associated with well integrity of UHS. Mechanisms that can compromise well integrity and generate leaks include microbial corrosion, hydrogen blistering hydrogen-induced cracking and hydrogen embrittlement, cement degradation, elastomer failure, and caprock sealing failure. Propose well completion criteria, recommendation, and materials selection for newly constructed wells or existing wells. A comparison with more developed storage technologies aims to provide a better understanding of the limitations of hydrogen storage by comparing it to carbon dioxide (carbon capture and storage) and methane (underground gas storage). Finally, evaluation and monitoring techniques are required to see the influence of hydrogen on well integrity. Future research and development will reduce the uncertainties and limitations associated with UHS increasing its feasibility and implementation.

Surface grafting of silica nanoparticles using 3‐aminopropyl (triethoxysilane) to improve the CO2 absorption and enhance the gas consumption during the CO2 hydrate formation

AbstractIn this study, the surface of silica nanoparticles is modified using an organosilane (APTES: 3‐aminopropyl (Triethoxysilane)). The surface‐grafted nanosilica is employed as an additive to increase the CO2 storage capacity of gas hydrate. The hydrate formation experiments are performed to measure the amounts of stored gas in the hydrate phase in the presence of various aqueous mixtures, that is, APTES, silica, and the surface‐grafted nanosilica. The experiments are implemented for APTES with volume concentrations of 0.3 and 0.5%, grafted nanosilica with mass concentrations of 0.05, 0.1, 0.15, 0.2, and 0.25%, and the nanosilica with mass fraction of 0.2%. The amounts of CO2 consumption, water to hydrate conversions, storage capacities, and apparent rate constants are obtained for all of the experiments. The results are compared with the formation of gas hydrate in the presence of pure water. The results indicate that the two concentrations of APTES have a slight positive effect (around 10% improvement) on the amount of CO2 consumption during the hydrate formation compared to the pure water. The surface‐grafted nanosilica leads to more CO2 consumption compared to the APTES and nanosilica for all concentrations. The maximum amount of stored CO2 and CO2 storage capacity are achieved by using surface‐grafted nanosilica with a mass fraction of 0.2%. The surface‐grafted nanosilica improves the CO2 storage about 42.6% in comparison with the pure water and 35% compared to the silica nanoparticles. Improvement of heat transfer, mass transfer, and CO2 absorption into the modified silica nanofluid results in an enhancement in the CO2 storage compared to the other mixtures. © 2021 Society of Chemical Industry and John Wiley & Sons, Ltd.

Techno-economic system analysis of an offshore energy hub with an outlook on electrofuel applications

The integration of cross-sectoral energy hubs into large-scale wind farms opens up existing structures to new applications and contributes to achieving renewable energy systems and climate protection targets. The offshore energy hub concept consists in establishing an artificially constructed energy conversion and distribution hub that addresses two energy-related markets by power supply to public grids and by potentially enabling the conversion of renewable electricity into hydrogen or ammonia and supplying it ashore. Hence, the energy hub concept enables smart integration of offshore wind power into gas grids. Power generation on demand from stored green gas is able to cover residual power loads at low carbon intensity. Electrofuel production provides also the opportunity to export renewable fuels for sectors with traditionally high greenhouse gas emissions, e.g., agriculture or transportation. In this contribution an energy hub system in the North Sea is modeled and simulated to determine production quantities and efficiencies of electricity, hydrogen and ammonia. When comparing the efficiencies of production, storage, and transport values of 45.1–65% for hydrogen and values of 52–52.3% for ammonia were determined. Re-conversion to electricity with fuel cells of both hydrogen and ammonia is less efficient and cost worthly than their use in electrofuel applications. Because of emerging and potential cost reductions a sensitivity analysis is performed where lower capital costs (50%) lead to cost reductions in hydrogen (42–45%) and ammonia production (40–42%). Results show that energy hubs can become sustainable pillars in future energy systems through improving cost-competitiveness of wind power.

Lightweight hydrogen storage cylinder for fuel cell propulsion systems to be applied in drones

A lightweight type-4 cylinder is developed using a polyethylene terephthalate (PET) liner for application in drones. We conducted a parametric study on the internal phenomena of the developed cylinder during the filling process to examine the applicability of the cylinder to drones. First, we fabricated a type-4 cylinder with a volume of 6.8 L. Then, variations in pressure and temperature inside the cylinder were examined during the filling test. At the end of the filling test, the internal pressure reached 450 bar, and the temperature reached 58 °C. The expansion of the cylinder at the center of the cylinder body was larger than that at the dome knuckle. Subsequently, the effect of the inlet gas temperature on the internal phenomena of the developed cylinder was examined. As the inlet gas temperature decreased, both the temperature of the stored gas and the expansion rate decreased. Finally, the storage density of the developed cylinder was compared with that of other types of vessels. The storage density of the developed cylinder was equal to 4.8 %, which higher than that of other types of cylinders. Through this study, the applicability of PET as a liner for a lightweight hydrogen storage cylinder was examined.

Optimized dispatching of city-scale integrated energy system considering the flexibilities of city gas gate station and line packing

Integrated Energy System (IES) has been proved to be able to effectively improve energy utilization and economic benefits. In the day-ahead dispatch of city-scale IES, electricity-gas interconnection is widely used to realize energy complementarity among regions, where the pressure regulation and electricity-heat-gas coupling in the gas gate station powered by Combined Heating and Power (CHP) device are usually excluded. Therefore, with the gas gate station centered, CHP fired energy hub linearization model, the optimized dispatching model of city-scale IES considering the flexibilities of city gas gate station and line packing is established in this paper where an Integrated Electricity and Gas System (IEGS) is running among regional Combined Cooling, Heating and Power (CCHP) systems, applying power and natural gas coupled energy flow algorithm. Results of case studies verify the potential of pipeline storage compared with gas storage tanks up to an 8.391% reduction on overall operation cost, a 14.366% improvement on renewable energy utilization and charging/discharging cycles reaching only 0.197 times of those of tanks, especially in areas with rich renewable energy. Besides, regulated by CHP fired energy hub which is worth constructing for its economic benefits and alleviation of peak power supply pressure, the average pipeline pressure proportional to stored gas volume increases by 5.885%, enhancing the flexibility of line packing. Moreover, this paper demonstrates that heating economy of gas boilers and electric boilers in comparison to gas turbines rises in turn with the increase of Gas-Electricity Price Ratio (GEPR). Lastly, Quasi Elastic Coefficient (QEC) is defined to describe multi-energy consumption sensitivity to Time-Of-Use (TOU) energy tariff, which is helpful in energy pricing and equipment scheduling.

High-Throughput Screening of Metal-Organic Frameworks for the Impure Hydrogen Storage Supplying to a Fuel Cell Vehicle

Metal-organic frameworks (MOFs), as typical porous materials, have been widely used for gas storage. However, impurities usually coexist in the stored gas, which will affect the deliverable capacity of the target gas. In this work, H2 gas (the target gas) adsorption process in 504 MOFs accompanied by impurities is screened by using a grand canonical Monte Carlo simulation method. The effects of the impurities, namely, CH4, O2, CO2, He, N2, Ar, and H2O, on the H2 deliverable capacity and regenerability are examined in the pressure between 35,000 kPa and 160 kPa at 298 K. The relationships between deliverable capacities of 504 MOFs and their material properties such as porosities, pore size, pore volumes, and surface areas are identified. Results show that the gravimetric deliverable capacity of 504 MOFs increases with porosity and surface area. XAWVUN is the best for the gravimetric deliverable capacity, and meanwhile, it has a fairly high volumetric deliverable capacity of H2 among 504 MOFs. The distributions of the adsorbed H2 molecules in XAWVUN display randomly. The impurities have no effect on the H2 adsorption in XAWVUN. The above results can guide to screen the best adsorbent for H2 storage supplying to a fuel cell vehicle.

Measurements and predictive models of high-pressure H2 solubility in brine (H2O+NaCl) for underground hydrogen storage application

In the context of Underground Hydrogen Storage (UHS), the stored gas is in direct contact with brine (residual brine from the cavern or formation water of deep aquifers). Therefore, knowledge of the phase equilibria (solubility of hydrogen in brine and water content in the hydrogen-rich phase) in the geological reservoir is necessary for the study of hydrogen mobility and reactivity, as well as the control, monitoring and optimization of the storage. The absence of measured data of high-pressure H2 solubility in brine has recently led scientists to develop predictive models or to generate pseudo-data using molecular simulation. However, experimental measurements are needed for model evaluation and validation. In this work, an experimental apparatus based on the “static-analytic” method developed and used in our previous work for the measurement of gas solubility in brine was used. New solubility data of H2 in H2O+NaCl were measured more or less under the geological conditions of the storage, at temperatures between 323 and 373 K, NaCl molalities between 0 and 5m, and pressures up to 230 bar. These data were used to parameterize and evaluate three models (Geochemical, SW, and e-PR-CPA models) tested in this work. Solubility and water content tables were generated by the e-PR-CPA model, as well as a simple formulation (Setschenow-type relationship) for quick and accurate calculations (in the fitting range) of H2 solubility in water and brine was proposed. Finally, the developed models estimate very well the water content in hydrogen-rich phase and capture and calculate precisely the salting-out effect on H2 solubility.

Tenure, Title and Property in Geological Storage of Greenhouse Gas in Australia

The disposal of greenhouse gas by underground storage in geological formations provokes several questions of legal entitlement: to the land in which the formations occur; to the formations which accommodate the stored gas; to the stored gas; to locate these formations; to store gas therein; to deal with these exploration and storage rights, and to protect them. This chapter examines how those questions arise and are resolved, onshore and offshore, in Australia.

Sensitivity analysis of gas leakage through a fault zone during subsurface gas storage in porous formations

Abstract. Subsurface gas storage in porous media is a viable option to mitigate shortages in energy supply in systems largely based on renewable sources. Fault systems adjacent to or intersecting with gas storage could potentially result in a leakage of stored gas. Variations in formation pressure during a storage operation can affect the gas leakage rates, requiring a site and scenario specific assessment. In this study, a geological model of an existing structure in the North German Basin (NGB) is developed, parameterised and a methane gas storage operation is simulated. Based on the observed storage pressure, a sensitivity study aimed at determining gas leakage rates for different parametrisations of the fault damage zone is performed using a simplified 2-D model. The leakage scenario simulations show a strong parameter dependence with the fault acting as either a barrier or a conduit for gas flow. Furthermore, the storage operation greatly affects the gas leakage rates for a given parametrisation with significant leakage only during the injection periods and thus during increased overpressures in the storage formation. During injection, the peak leakage rates can be as high as 2308 Sm3 d−1 for damage zone permeabilities of 10 mD and a capillary entry pressure of 4 bar. Increasing capillary entry pressure results in a sealing effect. If the capillary entry pressure is scaled according to the damage zone permeability, peak leakage rates can be higher, i.e. 3240 Sm3 d−1 for 10 mD and 0.13 bar. During withdrawal periods, the pressure gradient between a storage formation and a fault zone is reduced or even reversed, resulting in greatly reduced leakage rates or even a temporary stop of the leakage. Total leakage volume from storage formation was assessed based on the 2-D study by considering the exposure of the gas-filled part of the storage formation to the fault zone and subsequently compared with gas in place volume.

An automatic smart measurement system with signal decomposition to partition dual-source CO2 flux from maize silage

Carbon dioxide (CO2) is a principal byproduct of various chemical, biological and biochemical processes. CO2 has been measured using various advanced sensors, but a limiting technical challenge has been resolving independent streams of CO2 produced by processes occurring simultaneously. The magnitude and kinetics of each stream may be chemically, biologically or/and physically informative, but such partitioning has received little attention and successful case studies remain rare. In silage production, CO2 flux, an important indicator of aerobic deterioration, microbial activity or oxidative rate of silage, derives from two different pools: gas accumulated in the pores during the early anaerobic phase, and current real-time production of CO2 as oxygenated air enters the silage across the exposed face after opening for feed-out. The former is regarded as a noise confounding the signal and the latter reflects current degradation of the silage. Using a self-developed automatic sensor system with novel signal decomposition, we successfully partitioned CO2 flux into two independent streams derived from the two distinct pools in maize silage, following two independent processes: a physical venting of stored gas through a tortuous diffusive pathway, and a biochemical process generating gas in real time. Three silage samples, treated with a chemical or a biological additive, or left untreated, were tested. The signal decomposition found two best-fit functions (0.8034 ≤ R2 ≤ 0.9036), a quadratic CO2 discharge function and an exponential CO2 production function, for characterizing these distinct processes. These results demonstrate chemical sensor with powerful data-processing capability to resolve the complexity of dual-pool CO2 emission.

Operation of natural gas and electricity networks with line pack

This paper addresses the coordinated operation of the electricity and natural gas networks considering the line pack flexibility in the natural gas pipelines. The problem is formulated as a mixed integer linear programming problem. The objective is to minimize the operation cost of the electricity and natural gas networks considering the price of the natural gas supply. Benders decomposition is used to solve the formulated problem. The master problem minimizes the startup and shutdown costs as well as the operation cost of the thermal units other than the gas-fired generation units in the electricity network. The first subproblem validates the feasibility of the decisions made in the master problem in the electricity network. And if there is any violation, feasibility Benders cut is generated and added to the master problem. The second subproblem ensures the feasibility of the decisions of the master problem in the natural gas transportation network considering the line pack constraints. The last subproblem ensures the optimality of the natural gas network operation problem considering the demand of the gas-fired generation units and line pack. The nonlinear line pack and flow constraints in the feasibility and optimality subproblems of natural gas transportation network are linearized using Newton-Raphson technique. The presented case study shows the effectiveness of the proposed approach. It is shown that leveraging the stored gas in the natural gas pipelines would further reduce the total operation cost.

A Numerical Investigation into the Effect of Controllable Parameters on the Natural Gas Storage in a Weak Reservoir-type Aquifer

Natural gas storage process in aquifer, due to fluid flow behavior of gas and water in the porous medium and because of their contact with each other under reservoir conditions, faces several challenges. Therefore, there should be a clear understanding of the injected gas behavior before and after the injection into the reservoir. This research simulates the natural gas storage in aquifer by using Eclipse 300 software. For this purpose, a core sample was considered as the porous medium for gas injection, and a composition of natural gas was injected into the core in different conditions. Moreover, by using Plackett-Burman method, all of the factors affected in this process were screened, and finally four main significant parameters, including the flow rate of injected gas, permeability, pressure, and irreducible water saturation were selected for designing a design of experiments (DOE) plan. Response surface method (RSM) is one of the best methods of experimental design used for optimizing the process and finding the best combination of parameters to have a high stored gas volume and a high recovered gas volume. The simulation includes 28 runs with four considered parameters, and the output is the recovered gas, which in turn is vital for the process accomplishment. Sensitivity analysis and grid independency test were checked. To this end, three grids with different number of cells in x-direction were generated, and by analyzing the results of gas saturation in the porous medium for each model, a grid with 11250 cells (50 elements in x-direction and 15 elements in y- and z-directions) was then chosen as the main grid. Uncertainty analysis and the validation of numerical simulations were carried out, and good agreement was observed between the numerical results and experimental data. In addition, the numerical results showed that the flow rate of the injected gas had a significant impact on the process in comparison with other parameters. Furthermore, increasing permeability and decreasing pressure and irreducible water saturation raise the amount of trapped gas in aquifers. Therefore, for having the maximum stored gas volume and a high recovered gas volume, the best combination of parameters is a high gas injection flow rate (0.9 cc/min), high permeability (1.54 md), a low pressure (2254 psi), and irreducible water saturation. (0.46). Finally, in a natural gas storage operation in an aquifer, both rock properties and operational parameters play important roles, and they should be optimized in order to have the highest amount of stored gas.

Gas-water-rock interactions and factors affecting gas storage capacity during natural gas storage in a low permeability aquifer

Abstract Gas-water-rock interactions during natural gas storage in a low permeability aquifer and main factors affecting the storage capacity were investigated in laboratory with core experiments. The results showed that gas injection flow rate had a major impact on stored gas volume and stored gas volume is higher at high flow rate. Gas storage volume ranged between 6%–20% of the pore space at experimental condition. Enhancing injection pressure can enhance gas storage volume. Statistics showed that injection flow rate had a greater influence on the gas storage volume than pressure. The retention time also had an impact on the gas storage process. Most of the natural gas was trapped in the reservoir and could not be produced after long time of retention. Atomic absorption spectroscopy indicated that ions concentrations of the brine and water evaporation increased when gas was injected into brine saturated core, and precipitation might occur, reducing porosity and permeability of core. Gas chromatography analysis showed that the concentration of carbon dioxide in the natural gas decreased and the concentration of methane increased after storage in the core.

Acoustic monitoring of a thermo-mechanical test simulating withdrawal in a gas storage salt cavern

Natural gas storage in salt caverns requires fast injection / withdrawal cycles due to the increasing dynamics of the energy market. High rates induce rapid changes in the internal pressure of the stored gas causing important temperature changes susceptible to damage the rock salt mass. To experimentally observe this, the Starfish project aimed to characterize the damage caused by purely thermal stresses at the surface of a large bloc of rock in the salt mine of Varangéville (France). The objective was to determine the type of failure mechanism involved with repeated cooling stages. Since the salt is favourable to the generation of Acoustic Emissions (AE) and the propagation of stress waves, acoustic monitoring was chosen as one of the methods to follow the impact of the salt cooling. In addition to thermal and mechanical sensors, an acoustic monitoring device consisting of 16 ultrasonic sensors was installed on the free surface and in boreholes. It enabled to record and locate a large number of AE (58,426) located with good accuracy (2.5 cm). Those AE can be correlated to the evolution of salt fracturing. Acoustic activity is very intense at the start of each cooling cycle, then decreases with time to reach a very low level (background) after about 15 days. The average localisation depth reached by the AE is about 90 cm during the first cooling period. For subsequent cooling cycles, this depth is limited to 74 cm. These results show that the first cooling period is decisive, as it contains the strongest and deepest acoustic emissions.

Application of petrophysical shale gas model for CO2 storage capacity assessment of coals

Carbon dioxide storage in unmineable coal seams is a potential solution for the reduction of GHG emissions. For the purpose of storage capacity estimations various static and dynamic models are applied and in this study a simple petrophysical model, originally designed for shale gas reservoirs, has been used. This model comprises of volumetric (free gas) and surface (adsorbed gas) component. Important input data for the model are Langmuir constants and other reservoirs parameters such as water saturation, porosity and rock density. Sorption isotherms on two distinct coals from the Upper Silesia Coal Basin were measured and calculated Langmuir constants with typical reservoir parameters were implemented into the model. It occurred that coal with higher ash content and higher sorption capacity for methane had a lower carbon dioxide sorption capacity. This was reflected in the overall carbon storage capacity which for the two coals varied from 31 m3/t to approximately 42 m3/t of coal at the storage pressure of 5.5-6 MPa where the majority of stored gas is the surface component (sorbed gas).

Analysis of convection enhancing complex shaped adsorption vessels

This work focuses on studying the adsorbent vessel external shape influences on the air surrounding the tank and, consequently, affecting the heat exchange by convection, hence passively increasing the system efficiency. Many studies in the literature focus on improving the adsorbent vessels interior and aspect ratio. However, a new approach is explored herein, the improvement on the external vessel geometry aiming to enhance the heat exchange by convection due the flow caused by its own generated heat. Then, by managing the heat generated by adsorption chemical reaction and converting it to air mass displacement, the vessel is improved without external energy sources. This study scientific contribution is to present an approach for an adsorbent tank model. The approach consists in coupling the dynamics of external air fluid and adsorption in the vessel interior, which is capable of generating a heat transfer coefficient that depends on geometry. The problem is divided into two domains and solved via the Finite Element Method. For the adsorbent domain, the equations are presented. Both domains are tied via the conduction heat transfer in the vessels wall. Several different designs are presented and exposed to an adsorption charging cycle. Methane is stored in an activated carbon bed. Results are presented, by comparing the temperature fields between the designs and the velocity fields as well as the amount of exchanged heat between the vessel wall and the external media. The value of the heat transfer coefficient is plotted on the designs walls for comparison. Additionally, the conventional approach (fixed h) and the variable h approach are compared. Results suggest an optimisation regarding the vessel external geometry is promising. This method allows measuring the improvement of adsorption systems by improving the natural convection due the external geometry, hence passively improving its efficiency (adsorption rate) and reducing its operational cost (when compared to active methods, such as heat exchangers) or its capacity (total amount of stored gas).

Insight into Heterogeneity Effects in Methane Hydrate Dissociation via Pore-Scale Modeling

The production of natural gas from the gas hydrates has attracted significant attention over the last few decades. A continued challenge in gas hydrates is the estimation of the stored gas capacity. To alleviate this problem, this study uses the numerical modeling to provide insight into the distribution of hydrate in porous media and to obtain information about the application of high pressure for gas recovery. Hydrate dissociation process in porous media is modeled at the pore scale using pore network modeling by considering the uniform and non-uniform hydrate distribution. We explored the effect of gas clustering, saturation, and recovery, and their dependency on the underlying parameters including the pore size distribution, the applied pressure drops across the pore structures, and the initial hydrate saturation. We found that non-uniform hydrate distribution, larger pore sizes along with high-pressure drop, and higher initial hydrate saturations enhanced gas release. Additionally, our results confirmed the findings of the previous studies using 2D networks which studied pressure drop during hydrate dissociation in reservoirs.

Depth-dependent greenhouse gas production and consumption in an upland cropping system in northern China

Vertical profiles of greenhouse gas (GHG) production and consumption within soils have not been carefully quantified. The objective of this study was to quantify the depth-dependent contributions of CO2, CH4 and N2O fluxes in the soil profile to soil surface gas exchange. We simultaneously measured the soil surface GHG emissions and the subsurface fluxes (0–115cm) in situ by using a static chamber-based method (CM) and a concentration gradient-based method (GM) respectively, over two-year period in a maize-based upland cropping system in northern China.We found that unfertilized maize-based farmland acted as CO2 sources and CH4 and N2O sinks. Soil surface respiration was mostly contributed by the 0–15cm horizon; while CH4 and N2O consumption originated from the 0–40 and 0–15cm soil horizons, respectively. Specifically, we revealed that the soil surface respiration was contributed by the 0–5 and 5–15cm horizons, accounting for 70.9 and 27.3% of the surface exchange, respectively. The CH4 consumption at 0–5, 5–15 and 15–40cm depths accounted for 54.1, 32.3 and 12.1% of the surface exchange, respectively. And the N2O consumption at 0–5 and 5–15cm depths accounted for 80.4 and 6.6% of the surface exchange, respectively. The subsoil below 15cm acted largely as a CO2 buffer; the production/consumption potentials of CH4 and N2O were very weak below 40 and 15cm depths, respectively. In conclusion, our results highlight that the topsoil (0–40cm) plays a critical role in CO2 production and CH4 and N2O consumption in an unfertilized maize-based farmland in Taihang mountain areas of northern China. However, the mechanisms responsible for changes in stored greenhouse gas within soil pore space are not clear, and further observational and experimental research is required to understand those processes.

Potential risk of H2S generation and release in salt cavern gas storage

The storage of natural gas in salt caverns can entail the risk of H2S generation, which in turn leads to gas pollution. H2S is generated by bacterial sulfate reduction. The bacteria use aqueous sulfate(aq) as an electron acceptor to oxidize the dissolved hydrocarbons and generate sulfide. Anhydrite is available in the rock salt surrounding the cavern and acts as a sulfate(aq) source. The stored natural gas, with its main component, methane, is in solubility equilibrium with the brine and is additionally delivered by diffusion into the brine. The generated H2S reaches the stored gas by outgassing from the brine. In this study, these processes are simulated by one- and three-dimensional hydrogeochemical diffusive mass transport models, which are based on equilibrium reactions for gas-water-rock interactions and kinetic reactions for sulfate reduction. Modelling results show that the greatest amount of H2S is generated in the brine. The amount of generated H2S(g) is mainly controlled by the amount of available sulfate(aq) as well as the rate of diffusion, which is coupled with the maximum operating live time of salt caverns. Additionally, the amount of generated and released H2S(g) is sensitive to the chosen kinetic rate constant.To ensure constant gas quality over time, the gas and the brine must be analyzed continuously and technical methods must be applied when the H2S(g) concentration increases. According to the modelling results, H2S(g) generation is inhibited by addition of dissolved ferrous iron to the brine. Dissolved ferrous iron reacts with sulfide-sulfur to form mackinawite (FeS(s)) so that aqueous sulfide is no longer available for H2S(g) generation. Another method is the addition of NaOH to increase the pH of the brine. Then, higher fractions of generated sulfide-sulfur are transformed to free S2−(aq) instead of H2S(g) and H2S(aq).