Underground Natural Gas Storage Research Articles

A Review of the Utilization of CO2 as a Cushion Gas in Underground Natural Gas Storage

A cushion gas is an indispensable and the most expensive part of underground natural gas storage. Using CO2 injection to provide a cushion gas, not only can the investment in natural gas storage construction be reduced but the greenhouse effect can also be reduced. Currently, the related research about the mechanism and laws of CO2 as a cushion gas in gas storage is not sufficient. Consequently, the difference in the physical properties of CO2 and CH4, and the mixing factors between CO2 and natural gas, including the geological conditions and injection–production parameters, are comprehensively discussed. Additionally, the impact of CO2 as a cushion gas on the reservoir stability and gas storage capacity is also analyzed by comparing the current research findings. The difference in the viscosity, density, and compressibility factor between CO2 and CH4 ensures a low degree of mixing between CO2 and natural gas underground, thereby improving the recovery of CH4 in the operation process of gas storage. In the pressure range of 5 MPa–13 MPa and temperature range of 303.15 K–323.15 K, the density of CO2 increases five to eight times, while the density of natural gas only increases two to three times, and the viscosity of CO2 is more than 10 times that of CH4. The operation temperature and pressure in gas storage should be higher than the temperature and pressure in the supercritical conditions of CO2 because the diffusion ability between the gas molecules is increased in these conditions. However, the temperature and pressure have little effect on the mixing degree of CO2 and CH4 when the pressure is over the limited pressure of supercritical CO2. The CO2, with higher compressibility, can quickly replenish the energy of the gas storage facility and provide sufficient elastic energy during the natural gas production process. In addition, the physical properties of the reservoir also have a significant impact on the mixing and production of gases in gas storage facilities. The higher porosity reduces the migration speed of CO2 and CH4. However, the higher permeability promotes diffusion between gases, resulting in a higher degree of gas mixing. For a large inclination angle or thick reservoir structure, the mixed zone width of CO2 and CH4 is small under the action of gravity. An increase in the injection–production rate intensifies the mixing of CO2 and CH4. The injection of CO2 into reservoirs also induces the CO2–water–rock reactions, which improves the porosity and is beneficial in increasing the storage capacity of natural gas.

Co-optimization method for injection strategy of underground natural gas storage integrating aboveground and underground parts

Underground natural gas storage (UNGS) is an important infrastructure to overcome the imbalance between supply and demand of natural gas. During the gas injection period, gas is compressed aboveground and then transported to injection wells for injection into the underground reservoir. Reasonably formulating the compressor operation scheme and injection scheduling scheme is a crucial step. However, “Compressor-pipeline-injection well-reservoir" constitutes a synergistic whole. More efficient and practical operation schemes can only be proposed through the establishment of an optimization method that coordinates the entire gas injection process. A novel two-layer multi-objective collaborative optimization method is proposed to optimize the monthly operation scheme during the injection period. The upper-layer model focuses on optimizing injection volume allocation to minimize reservoir pressure deviation and total compressor energy consumption. The under-layer model optimizes the compressor operation scheme by considering the multi-stage compression (MC) and clearance adjustment (CA) equipped in reciprocating compressors. The synergistic relationship during the injection process is integrated into the traditional model through the interlayer iteration method. Furthermore, a high accuracy and efficiency proxy model based on machine learning algorithms (ML) is developed to predict compressor performance. The results of the case study indicate that, compared with traditional optimization method and the two-stage co-optimization method, the proposed method achieves an average energy consumption reduction of 9.54 × 106 kWh (10.79%) and 2.12 × 106 kWh (2.4%) respectively. The effective utilization of CA and MC can significantly alleviate the deviations between displacement and processing requirements, eliminating 22,120.5 × 104 Nm3(85.62%). The two-layer co-optimization method effectively integrates the aboveground and underground parts of UNGS, providing a solution for safe and efficient operation during the injection period.

Analysis of Carbon Dioxide/Methane Mixing Process in Rock Cores for Underground Natural Gas Storage

Analysis of Carbon Dioxide/Methane Mixing Process in Rock Cores for Underground Natural Gas Storage

Evaluation of underground gas storage capacity in the depleted gas reservoir with water evaporation and salt precipitation

Water evaporation and salt precipitation will occur in gas reservoirs and underground gas storage (UGS) with high-salinity formation water during production and operation. This phenomenon seriously affects the efficient and safe operation and gas storage capacity. This work focuses on quantitatively evaluating the UGS capacity based on depleted gas reservoirs considering water evaporation and salt precipitation. The core flooding experiments are conducted to analyze the influence of water evaporation and salt precipitation on rock properties under different water salinity during multi-cycle injection-production. A numerical model considering water evaporation is established to determine the salt precipitation radius around the gas well. According to the experimental and simulation results, a new analytical model is developed to calculate the underground natural gas storage capacity based on material balance principles. The field case study is presented to show the practical potential of the established model. Both formation porosity and permeability in near-well region may be finally improved by water evaporation and salt precipitation under irreducible water condition. In the presence of movable-water, formation porosity and permeability of the near-well region may be firstly improved and finally reduced due to continuous salt precipitation in porous media. Salt-precipitation radius achieves 28.5 m after ten cycles. The UGS capacity is 101.11 × 108 m3 without considering salt precipitation, 1.11% higher than original geological reserves. The UGS capacity considering both irreducible-water evaporation and salt precipitation is 101.03 × 108 m3. However, when the moveable-water evaporation volume increases to 15Virr, the final UGS capacity is further decreased to 98.55 × 108 m3. The UGS capacity has decreased by 0.82%, 1.64%, and 2.45% compared with irreducible water. The continuous evaporation of movable water and salt deposition will reduce the gas storage capacity and cause damage to the UGS. This work provides an effective method to investigate the quantitative impact of water evaporation and salt precipitation on UGS capacity.

Underground natural gas storage facility operations and well leakage events in the United States

Federal minimum safety standards for underground natural gas storage (UNGS) operations in the United States (U.S.) were set by the Pipeline and Hazardous Materials Safety Administration (PHMSA) in the aftermath of the 2015 Aliso Canyon well leakage incident. Beginning in 2017, these standards required operators of U.S. UNGS facilities to publicly report: 1) leakage events that meet established criteria for incidents; 2) annual details of well construction, maintenance, and integrity testing activities; and 3) the occurrence of leading indicators of leakage (i.e., safety-related conditions). We reviewed both PHMSA reports and previously published studies to compile a dataset of 53 well leakage events at UNGS facilities in the U.S. that align with the PHMSA reporting requirements. Casings (55.0%) and wellheads (32.5%) were the most common failed well components identified. Human intervention through incorrect operation or outside force damage was the most common (39.3%) cause of well leakage events. Well leakage events caused by corrosion resulted in significantly greater emissions than those with other causes. UNGS annual reports detailed operations at 406 UNGS facilities with 17,993 wells—14,469 were injection and the remainder monitoring. Of these wells, 11,446 (63.6%) were reported to have a design that is potentially susceptible to a single point of failure, which is more than three times the previous estimate. Additional information about the status and construction of individual wells is needed to confirm the number of operational wells with a single-point-of-failure design. These data would help regulators identify single-point-of-failure wells and ensure the elevated risks associated with them are appropriately mitigated by proposed risk management plans. Statistically significant differences in the characteristics of UNGS facilities that have and have not experienced well leakage events were observed among those operating in depleted hydrocarbon reservoirs. Depleted hydrocarbon UNGS facilities that experienced well leakage events were generally larger, which suggests that focusing regulatory inspections and reviews on these facilities may be justified. The UNGS data reported were not sufficient to build a predictive model that forecasts well leakage events. Modeling efforts were limited by the data reporting format, which requires UNGS operators to aggregate data by facility in their annual reports. Gathering and evaluating information for individual wells at UNGS facilities would be valuable and may provide additional insights into well leakage risks to better inform risk management planning efforts.

Machine learning for underground gas storage with cushion CO2 using data from reservoir simulation

Underground natural gas storage (UNGS) is a means to store energy temporarily for later recovery and use. In such storage operations, carbon dioxide (CO2) can be injected as cushion gas to improve the operating efficiency of the working gas and then be permanently stored in the same reservoir. A potential obstacle for widespread use of this technology is that the mixing of the different gases can lead to undesired CO2 production. Herein, we use a two-component flow model to simulate injection and withdrawal periods of methane (CH4) in idealized reservoirs containing CO2. First, we simulate cases with a single well for both CH4 injection and production. From 1200 simulations with systematic variation of reservoir temperature, porosity, permeability, height, and injection time, we find that the reservoir height and permeability have the most significant impact on the production time until the well stream reaches 1% mole fraction of CO2. In another set of simulations, we investigate the impact of well spacing in seasonal gas storage scenarios with separate wells for CH4 injection and production, while CO2 injection occurs from a third well. Based on the simulated data we construct artificial neural networks (ANNs) that describe the relations between the varied input parameters and the production time of CH4, well-block mole fraction and pressure. We conclude that trained and validated ANN models are useful tools to optimize important parameters for UNGS operations, including well positioning, with the aim at maximizing the amounts of delivered gas.

Impact of well interference on transient pressure behavior during underground gas storage: A comparative study

Underground natural gas storage (UGS) serves as an environmentally sustainable remedy for mitigating regional and temporal disparities in energy supply and demand. The phenomenon of substantial well interference and non-uniform pressure distributions in UGS, resulting from high injection and withdrawal rates, requires a comprehensive examination. This study presents an analytical model aimed at investigating the ramifications of well interference on transient pressure dynamics during UGS. Employing the Laplace transform method, an analytical framework for diverse wells within UGS is derived, with well interference effects being effectively incorporated through the application of the superposition principle. To validate the proposed analytical solutions under various scenarios, a commercial numerical simulator is employed. The analysis reveals that when an adjacent well is engaged in gas withdrawal, interference induces an initial rise in pressure derivative followed by a subsequent plateau. Conversely, during gas injection into an adjacent well, the pressure derivative curve exhibits a continuous decline, akin to situations characterized by constant pressure boundaries. Notably, the likelihood of interference with a target well is more pronounced when gas injection or production occurs in a vertical well as opposed to a horizontal one. Preliminary data from the Hutubi UGS in China, one of the largest projects of its kind, indicate cumulative gas injection and withdrawal volumes of 155.43 × 108 m3 and 130.81 × 108 m3, respectively, with a maximum storage capacity of 107 × 108 m3. Ultimately, the gas storage volume reaches 93.50% of the UGS's designated capacity. This substantial quantity of stored natural gas equates to the calorific value of 9.88 × 109 kg of crude oil or 1.29 × 1010 kg of coal. In comparison to conventional fossil fuels such as oil and coal, the utilization of natural gas in the Hutubi UGS results in a significant reduction of carbon dioxide emissions, amounting to 1.04 × 1010 kg and 1.38 × 1010 kg, respectively. This contribution advances the field by proposing an analytical model for the systematic analysis of well interference on pressure dynamics within the Hutubi UGS, thereby facilitating the transition from oil and coal to natural gas, a crucial step in the pursuit of cleaner and more sustainable energy production practises.

Identificating vegetation stress under natural gas micro-leakage based on leaf scale temporal hyperspectrum

ABSTRACT Timely detection of underground natural gas leakage is significant for the safe production of gas storage and the protection of ecological environment. Direct detection makes it difficult to identify natural gas micro-leakage accurately, while hyperspectral remote sensing can identify micro-leakage based on spectral changes of vegetation near the leakage area. However, the spectral morphological characteristics of vegetation leaves under natural gas micro-leakage will undergo complex changes over time, making it difficult to identify vegetation stress. Temporal spectral characteristics improve the capability of capturing spectral differences of stressed vegetation at different times, allowing for indirect evaluation of leaked information. This study simulates the stress of underground natural gas storage micro leaks on bean growth through field experiments. Based on the changes in spectral reflectance and chlorophyll content of leaves, temporal features were constructed based on multi-temporal reflectance data, and feature selection methods were used to obtain bands sensitive to natural gas stress. This paper proposed a leaf scale natural gas micro-leakage identification index based on temporal spectral features (TNII) to identify bean stress under natural gas leakage. The results are summarized as follows: (1) With the leakage of underground natural gas, the spectral reflectance of leaves increased in the visible and near-infrared range, and the chlorophyll content decreased. (2) The TNII ( R 676 − R 526 ) Tn − ( R 676 − R 526 ) T 1 ( R 676 − R 526 ) Tn + ( R 676 − R 526 ) T 1 constructed based on sensitive wavebands (676 and 526 nm) can be employed to identify bean stress under natural gas after 17 days of leakage. The JM (Jefferies Matusita) distance test indicates that TNII could timely and stably identify bean stress under natural gas micro-leakage (JM > 1.8). This study provides the theoretical basis and technology support for micro-leakage detection of underground gas storage or pipelines.

Dynamic evaluation of technological innovation system; the case of underground natural gas storage technology in Iran

The technology development is often a process that requires government guidance and support. The government prepare and implement policies for the development of priority technologies. Prior to formulating the policies for technology development, the innovation system should be evaluated and analyzed to identify problems and shortcomings in the system. In the next step, appropriate policies should be implemented to address them. The present study seeks to understand the current situation of the natural gas underground storage technology innovation system in Iran. This innovation system provides a model for evaluating it in Iran by utilizing the framework of the technological innovation system and the method of dynamic evaluation (motors of innovation). Based on that, the system failures in the country have been identified. According to the findings, most important causes of system failure in the development of this technology include insufficiency and low share of private companies in this field, relatively low and average quality of entrepreneurs, and the limited number of storage tanks.

Biodiversity and Potential Activity of Microorganisms in Underground Gas Storage Horizons

The share of molecular hydrogen as a source of “green energy” is currently significantly increasing. It is proposed to use existing underground natural gas storage facilities to store large volumes of hydrogen. In Russia, depleted oil and gas fields (DOGFs) and deep aquifers are used for natural gas storage. The purpose of this work was to determine microbial diversity in DOGF and deep aquifers by cultural and 16S rRNA gene-based approaches and the effect of H2 on the growth of microorganisms from the underground gas storage (UGS) horizons. The composition of the microbial community inhabiting the formation water of the Peschano–Umetskoe depleted oil and gas reservoir was typical for microbial communities of oil reservoirs and included bacteria of the phyla Bacillota (Dethiosulfatibacter, Defluviitalea, Acetobacterium, Syntrophobotulus), Actinobacteriota (Dietzia, Rhodococcus), Spirochaetota (Sphaerochaeta), Pseudomonadota (Shewanella), and Bacteroidota (Petrimonas), together with methanogenic archaea of the phylum Euryarchaeota (Methanobacterium). In some formation water samples, the share of methanogens of the genus Methanobacterium reached 61.6% of the total community; these hydrogen-utilizing organisms may contribute to the formation of methane in the reservoirs used for the storage of molecular hydrogen. Microbial communities of UGSs located in aquifers were less diverse and abundant. Cultivable hydrogenotrophic sulfate-reducing, homoacetogenic, and methanogenic prokaryotes were retrieved from the studied aquifers and from the DOGF used for gas storage. Microorganisms present in the condensation and reservoir waters of the UGS facilities can influence the composition of the water and gas phase, and affect the host rocks and borehole equipment.

Linking geological and infrastructural requirements for large-scale underground hydrogen storage in Germany

Hydrogen storage might be key to the success of the hydrogen economy, and hence the energy transition in Germany. One option for cost-effective storage of large quantities of hydrogen is the geological subsurface. However, previous experience with underground hydrogen storage is restricted to salt caverns, which are limited in size and space. In contrast, pore storage facilities in aquifers -and/or depleted hydrocarbon reservoirs- could play a vital role in meeting base load needs due to their wide availability and large storage capacity, but experiences are limited to past operations with hydrogen-bearing town gas. To overcome this barrier, here we investigate hydrogen storage in porous storage systems in a two-step process: 1) First, we investigate positive and cautionary indicators for safe operations of hydrogen storage in pore storage systems. 2) Second, we estimate hydrogen storage capacities of pore storage systems in (current and decommissioned) underground natural gas storage systems and saline aquifers. Our systematic review highlights that optimal storage conditions in terms of energy content and hydrogen quality are found in sandstone reservoirs in absence of carbonate and iron bearing accessory minerals at a depth of approx. 1,100 m and a temperature of at least 40°C. Porosity and permeability of the reservoir formation should be at least 20% and 5 × 10−13 m2 (∼500 mD), respectively. In addition, the pH of the brine should fall below 6 and the salinity should exceed 100 mg/L. Based on these estimates, the total hydrogen storage capacity in underground natural gas storages is estimated to be up to 8 billion cubic meters or (0.72 Mt at STP) corresponding to 29 TWh of energy equivalent of hydrogen. Saline aquifers may offer additional storage capacities of 81.6–691.8 Mt of hydrogen, which amounts to 3.2 to 27.3 PWh of energy equivalent of hydrogen, the majority of which is located in the North German basin. Pore storage systems could therefore become a crucial element of the future German hydrogen infrastructure, especially in regions with large industrial hydrogen (storage) demand and likely hydrogen imports via pipelines and ships.

Gas Injection Capacity of Slotted Liner and Perforation Completion in Underground Natural Gas Storage Reservoirs

The use of Horizontal wells is a common method of underground natural gas storage (UGS), but there is still a need to discuss whether they are more suitable for slotted liner or perforation completions. To address this issue, a numerical model is developed to predict the gas injection rate of horizontal wells while considering the skin factor. Here, a novel uncoupled iteration method is employed to determine the skin factor deriving from turbulence in each time step when the bottom hole pressure is fixed. The uncoupled method begins with an estimate of the initial gas injection rate, which is then used to calculate a turbulent skin factor. This turbulent skin factor is then used to update the gas injection rate, iterating continuously until convergence is achieved. The effects of slotted liner and perforation design parameters, formation damage, and injection pressure on the skin factor are analyzed. The main findings suggest that the error in the gas injection rate calculated by the non-coupled model compared with the coupled model is only 0.6%, yet it can reduce the number of sub-iterations to 1/10 of that required by the coupled model. Moreover, the uncoupled model can provide results within four steps, even when the convergence condition is 10−14. The open area and perforation density play a significant role in determining the connection degree between the horizontal well and the reservoir, with a larger perforation density resulting in a negative skin factor. Perforations are more suitable than slotted liners for reservoirs with severe formation damage, and the difference in skin factor between the two can reach a value of 40.87 when the ratio of the damage zone’s permeability to that of the normal reservoir zone is 0.05. It is easier to reduce turbulence damage in slotted liner completions than perforation completions, with the turbulence damage of the slotted liner being only 15.9% of that of the perforation. However, to avoid damage it is crucial to prevent the screen tube from being plugged in, as it might otherwise rise to three to ten times the original level. This study provides a theoretical basis and practical reference for the application of slotted liner and perforation method in UGS horizontal wells.

A detailed comparative performance study of underground storage of natural gas and hydrogen in the Netherlands

With the expected increase in the use of hydrogen as an energy carrier, large-scale underground storage sites will be needed. Unlike underground natural gas storage (UGS), many aspects on the performance of underground hydrogen storage (UHS) are not well understood, as there is currently no UHS in use for energy supply. Here we present the results of a detailed comparative performance study of UGS and UHS, based on an inflow/outflow nodal analysis. Three UGS sites in depleted gas fields and one in a salt cavern cluster in the Netherlands are used as case studies. The results show that although hydrogen can be withdrawn/injected at higher rates than natural gas, this can be limited by technical constraints. It also indicates that wider ranges of working pressures are required to increase the storage capacity and flow performance of an UHS site to compensate for the lower energy density of hydrogen.

Guest Editorial: How To Leverage E&P Expertise for the New Energy Economy

_ The term “new energy economy” broadly refers to the transition to a low-carbon future for sustaining human development while reducing CO2 emissions. Such a shift is considered to be the third energy transition of the modern era, after the shift from biomass to coal as the primary source of energy in the early 1900s, followed by oil overtaking coal’s dominant position in the 1960s–1970s. This trend towards decarbonization (i.e., diversification from carbon-intensive fossil fuels to sustainable greener energy feedstocks and carriers) is motivated by the understanding that emissions need to be reduced to moderate the potential impacts of global temperature rise on future climatic changes. Strategies common to proposed decarbonization pathways include - Improving energy efficiency (i.e., slower increase in energy demand compared to GDP/population increase). - Increasing energy supply from renewable sources (i.e., wind, solar, geothermal, nuclear) coupled with hydrogen underground storage (HUS) as a way of storing surplus electrical energy. - Switching to low-carbon energy carriers (i.e., hydrogen) for end-use applications in transportation, buildings, and industry. - Removing carbon emissions, via carbon capture, utilization, and storage (CCUS), from fossil-fuel-fired power plants and hard-to-abate industrial sources. The key takeaway for readers is how the two subsurface-oriented decarbonization strategies—CCUS and HUS—are relevant for application/adaptation of expertise from the exploration and production (E&P) sector of the oil and gas industry. Their rise will be built upon decades of experience with CO2-EOR, gas injection, produced-water disposal, and underground natural gas storage (NGS). Carbon Capture, Utilization and Storage (CCUS) As shown in Fig. 1, CCUS involves capturing CO2 from a fossil-fuel-fired power plant or industrial facility and processing it to a practically pure form, transporting it to a nearby geologic storage site using pipelines, and injecting it into saline aquifers for long-term sequestration or depleted oil/gas fields for enhanced oil recovery (EOR) and associated storage. Research and field demonstration projects over the past few decades have demonstrated that CCUS is a viable technology for curtailing atmospheric CO2 emissions buildup. Some of the key elements of CCUS projects and their overlap with corresponding E&P expertise are summarized below.

Technology Focus: Natural Gas Processing and Handling (April 2023)

_ Regardless of which side of the aisle you are on, the critical role that natural gas will play in the energy evolution (or energy transition, as some would say) is undeniable. Natural gas as a fuel is an important bridge toward this evolution and doubles as a reliable partner for renewable energy sources in providing support for wind, solar, and hydroelectric generation by helping to match supply and demand. Renewed interest in, and high-level discussions regarding, the expansion in necessary natural gas infrastructure, the growth in energy consumption, and the expansion of liquefied natural gas business are all strong indicators for technical improvements in the handling and processing of natural gas in this new phase of the energy economy. The first of the case-study-oriented papers in this section highlights a coupled geomechanical and dynamic flow simulation work flow that forms an effective decision-making tool for the process optimization of underground natural gas storage operations in southwest China. Such a multidisciplinary approach allows for the optimization of several key variables to develop strategies for increasing withdrawal rates, meeting the needs of future peak gas demands, and supporting clean-energy initiatives. Indeed, the larger context of underground gas storage plays a key role in addressing supply and demand dynamics as natural gas consumption grows in the future in response to the energy evolution and cleaner-energy initiatives. Another key focus of the energy-evolution discussion is the reduction of carbon emissions through the framework of the circular carbon economy. A case study is presented on the mitigation of routine gas flaring as part of strategic initiatives of the Saudi oil and gas industry. The lessons learned from this case study can be scaled up to the broader industry. In the third highlighted paper, the focus is on the management of methane emissions across the natural gas value chain and a case study on the deployment of methane detection and quantification technologies of the national operator of the Malaysian oil and gas industry. Methane-emissions reduction directly affects advocacy for natural gas as a low-carbon fuel for energy-evolution stakeholders. In the paper, specific methods are developed to quantify methane from fugitive leaks, loss of primary containment, venting and flaring of hydrocarbons, stationary combustion, compressor seals, pneumatic control devices, and pumps. Other than the specific papers highlighted, it is quite encouraging to see cost-effective carbon-emission reduction initiatives at the local operator scale in the sphere of natural gas handling and processing. One such standout that rightfully serves as an example for the entire industry is the 100% elimination of natural-gas-powered pneumatic devices of the largest natural gas producer in the United States, EQT. This meaningful milestone sharply reduced this operator’s annual carbon footprint and, in the wider sense, provided a practical example of aggressively addressing methane emissions through exceptional teamwork and strategy implementation. Recommended additional reading SPE 210890 Strategies for Reducing and Monetizing Fugitive Methane Emissions From Natural Gas Infrastructure by Stefan Diezinger, Siemens Energy SPE 210446 What’s the Best Way To Stabilize Oil in the Permian? An Examination of Different Facilities Layouts by Isabel Chan, TechnipFMC, et al. OTC 31891 A New Approach to Future Floating Liquefied Natural Gas for Offshore Gas Monetization by Xiaogang Liu, Wison Offshore and Marine, et al.

A Novel Performance Evaluation Method for Gas Reservoir-Type Underground Natural Gas Storage

The regulation of the seasonal energy supply for natural gas and the storage of fossil energy are important to society. To achieve it, storing a large amount of natural gas in porous underground media is one of the government’s choices. Due to the successful lesson learned from the oil and gas industry, natural gas storage in underground porous media has been regarded as the most potential long−term energy storage method. In this paper, we developed a new workflow to evaluate the performance of gas reservoir−type underground natural gas storage (UGS). The theoretical background of this workflow includes the correction of the average formation pressure (AFP) and gas deviation factor by error theory and the analytical mathematical model of UGS wells. The Laplace transform, line source function, and Stehfest numerical inversion methods were used to obtain pressure solutions for typical vertical and horizontal wells in UGS. The pressure superposition principle and weighting method of the gas injection−withdrawal rate were used to obtain the AFP. Through the correction of the AFP and gas deviation factor in the material balance equation, the parameters for inventory, effective inventory (the movable gas volume at standard condition), working gas volume (the movable gas volume is operated from the upper limit pressure to the lower limit pressure), and effective gas storage volume (the available gas storage volume at reservoir condition) were determined. Numerical data from the numerical simulator was used to verify the proposed model pressure solution. Actual data from China’s largest Hutubi UGS was used to illustrate the reliability of the proposed workflow in UGS performance evaluation. The results show that large−scale gas injection and withdrawal rates lead to composite heterogeneity in gas storage wells. The nine injection and production cycles’ pressure and effective inventory changes from Hutubi UGS can be divided into a period of rapid pressure rise and a period of slow pressure increase. The final AFP is 32.8 MPa. The final inventory of the Hutubi UGS is 100.1 × 108 m3, with a capacity filling rate (the ratio of effective inventory to designed gas storage capacity) of 93.6%. The effective inventory is 95.3 × 108 m3, and the inventory utilization ratio (the ratio of effective inventory to inventory) is 95.2%. The working gas volume is 40.3 × 108 m3. This study provides a new method for inventory evaluation of the gas reservoir−type UGS.

Underground energy-related product storage and sequestration: site characterization, risk analysis and monitoring

Abstract This paper presents a high-level overview of site characterization, risk analysis and monitoring priorities for underground energy-related product storage or sequestration facilities. The siting of an underground storage or sequestration facility depends on several important factors beginning with the area of review. Collection of all existing and available records and data from within the rock volume, including potential vulnerabilities such as prior containment issues, proximity to infrastructure and/or population centres, must be evaluated. Baselining of natural processes before storage or sequestration operations begin provides the basis for assessing the effects of storage or sequestration on the surroundings. These initial investigations include geological, geophysical and geochemical analyses of the suitability of the geological host rock and environs for storage or sequestration. A risk analysis identifies and evaluates threats and hazards, the potential impact should they develop into unwanted circumstances or events and the consequences to the facility should any of them occur. This forms the basis for framing effective mitigation measures. A comprehensive monitoring programme that may include downhole well surveillance, observation wells, geochemical sampling and well testing ensures that the facility operates as designed and that unforeseen issues, such as product migration or loss of integrity, can be identified and mitigated. In addition to these technical issues, human factors and public perception of a project are a critical part of the site characterization, construction and operational phases of a project. Despite differences between underground storage and sequestration, the characterization, risk analysis and monitoring approaches that were developed for underground natural gas storage or for carbon dioxide sequestration could be used for underground storage or sequestration of any type of energy-related product. Recommendations from this work include: (1) develop an industry-standard evaluation protocol (workflow) for the evaluation of salt beds, saline aquifers, depleted hydrocarbon reservoirs, underground mines and cased wellbores for potential underground storage or sequestration development beyond those in use today; and (2) develop an industry-wide collaborative process whereby incident and near-miss data related to underground storage or sequestration operations can be reported, documented and shared for use in refining risk analysis modelling.

Policy and legal frameworks for underground natural gas storage in Iran

Policy and legal frameworks for underground natural gas storage in Iran

Optimal Operation of Integrated Energy Systems Based on Multi-Energy Coupling With Power-to-Gas Technology

Abstract Natural gas and renewable energy sources make up an increasingly large proportion of power generation due to their being environmentally friendly. Because of the intermittent and fluctuating output of renewable energy sources, the emerging technology of power-to-gas (P2G) units is of great significance to alleviate. This paper focuses on the coordinated optimization of the combined gas and electricity network (CGEN) system with bidirectional energy conversion. Gas-fired power generation (GPG) plants and P2G are considered as linkages between the two networks. A unified CGEN mathematical model is established with the minimum operation cost as the objective function. The injection and production process of underground natural gas storage (UNGS) is also taken into consideration that is not available in other literature. Variables such as the output of P2G and gas-fired power generation plants, the supply of UNGS, and the wind curtailment are optimized correspondingly. The improved 24-node power grid (PG) and Belgium 20-node natural gas pipeline network (NGPN) are adopted to test the validity and capability of the proposed model, and then we compare the results CGEN model with the single Belgium NGPN to analyze the impact on the NGPN. Moreover, we adopt a coupled operation system of a 6-node power system and a 7-node NGPN to further analyze the influence of P2G on the CGEN. The results show that compared with the system without P2G, the total operating cost of the system is reduced by 9.39%, the natural gas load shedding is reduced by 26.1%, and the wind curtailment is reduced from 326 MWh to zero.

Considerations regarding the opportunity to continue using the sarmatian VII objective within the ZD structure an underground natural gas storage deposit

Considerations regarding the opportunity to continue using the sarmatian VII objective within the ZD structure an underground natural gas storage deposit