Gas Storage Wells Research Articles

Study on Quantitative Assessment of CO2 Leakage Risk Along the Wellbore Under the Geological Storage of the Salt Water Layer

In the process of CO2 geological storage in the salt water layer, CO2 leakage along the wellbore will seriously affect the effective storage of CO2 in the target geological area. To solve this problem, based on the investigation of a large number of failure cases of CO2 storage along the wellbore and failure cases of gas storage wells in the injection stage of the wellbore, the influencing factors of CO2 leakage risk along the wellbore were investigated in detail. Based on the analytic hierarchy process (AHP) and extension theory, 17 basic evaluation indexes were selected from 6 perspectives to establish the evaluation index system of CO2 leakage risk along the wellbore. The established evaluation system was used to evaluate the leakage risk of a CO2 storage well in the X gas field of BZ Block. The results showed that the influencing factors of tubing had the smallest weight, followed by cement sheath, and the influencing factors of casing–cement sheath interface and cement sheath–formation interface had the largest weight, accounting for 23.73% and 34.32%, respectively. The CO2 storage well leakage risk evaluation grade was Ι, with minimal leakage risk. The CO2 storage effect was excellent. The evaluation system comprehensively considers the tubing string, cement sheath, and micro-annulus interface, which can provide a scientific basis for the risk assessment of CO2 leakage along the wellbore under the CO2 geological storage of the salt water layer.

Research on Temperature–Pressure Coupling Model of Gas Storage Well during Injection Production

Periodic changes in wellbore temperature and pressure caused by the cyclic injecting and producing of gas storage wells affect wellbore integrity. To explore the distribution and influencing factors of wellbore temperature and pressure during gas storage well injection-production processes, based on energy conservation, momentum theorem, and the transient heat transfer mechanism of the wellbore, a temperature and pressure coupling model for gas storage injection-production wellbores was established, and a piecewise iterative method was used to solve the model equations. Compared with the field data, the predicted relative errors of the wellhead temperature and pressure were 2.30% and 2.07%, respectively, indicating that the coupling model has a high predictive accuracy. The influences of the injection-production conditions, tubing diameter, and overall heat transfer coefficient on the wellbore temperature and pressure distributions were analyzed through an example. When the gas injection flow rate increased by 1.5 times, the bottomhole temperature decreased by 37%. Doubling the overall heat transfer coefficient resulted in a 10% rise in the bottomhole temperature. An increase of 0.3 times in the gas injection pressure led to a 31% increase in bottomhole pressure. With a 1.5-fold increase in the gas production flow rate, the wellhead temperature rose by 28%, and the wellhead pressure dropped by 20%. The research in this paper can serve as a guide for the optimization design and safe operation of gas storage wells.

Development of software for automated digitisation of geophysical survey results of underground gas storage wells

The purpose of the work is to store, process and analyse the materials of geophysical surveys of wells (GSW) of underground gas storage (UGS) facilities. In order to reduce the time needed to analyse paper-based GSW data accumulated during the operation of gas storage facilities, it is important to transfer them to electronic form for storage. A set of application software solutions has been developed to achieve the goal.The paper presents approaches to the operational analysis of geophysical information, including its verification, correction and accumulation in digital format. A software package (SP), “Karotazh”, was developed for automated recognition of the results of geophysical surveys of wells, which are important for solving various geological and technological problems by means of prompt processing, systematisation, accumulation of initial information, graphical and documented display of this information. The software for preparation of well logs is designed to enter them into the archive for storage, viewing and further automated recognition (digitisation).In order to solve the tasks set out in the study, it has been used such general scientific methods as systematisation (when selecting the necessary sources of information), generalisation (in the process of defining general terms that highlight the main features), formal logical method, method of systematic analysis of information, descriptive method and modelling method.Implementing the developed software for automated recognition of logging results can increase the efficiency of processing geological and geophysical information on wells and productive horizons to analyse their condition and eliminate complications promptly. Forusers’' convenience, an interface for Ukrainian UGS conditions has been developed, allowing specialists to increase their work’s efficiency. The proposed software solution can be used by oil and gas companies in Ukraine to digitise and provide information support for the analytical processing of geophysical survey results.The approach enables to quickly digitise and analyse well logs and then store them in an electronic archive of geophysical surveys.In order to solve problematic issues in gas storage wells on time, it is necessary to promptly analyse the results of geophysical surveys using modern software tools to predict possible complications and take appropriate measures in a timely manner.Implementation and use of the developed software solution for automated recognition of GSW results at UGS facilities enables to reduce the time for analysis of information in paper form and increase the efficiency of obtaining the necessary information for timely action in case of complications.The authors propose relevant and up-to-date software solutions for the automated processing of GSW results and their storage and use in an electronic archive. Implementing the approach in production enables specialists to quickly analyse information and solve problematic issues.

Steckman Ridge: A naturally fractured underground gas storage field

This paper presents a field development case study of a gas storage field in Pennsylvania within a fractured reservoir. Integration of multiple data sets was required for the project's success. During the study, the interpretation of 3D isofrequency seismic volumes, generated through spectral decomposition, was shown to be the key step in this data integration. The interpretation of these isofrequency volumes successfully identified previously unresolved subtle structural features, which controlled the natural fracture system. The existence of these subtle structural features was subsequently confirmed with eight horizontal gas storage wells. Accurate characterization of a fracture trend requires the integration of seismic data, available well data, surface geology, drilling, and production data. This study was performed to develop the Oriskany reservoir in the Steckman Ridge underground gas storage field located in Bedford County, Pennsylvania. This field had undergone rapid depletion during its primary production phase. During the early portion of the study, the reservoir was determined to be a type 1 fractured reservoir with little to no gas storage available in the sandstone matrix. Multiple data types were acquired and integrated to detect and characterize the structural features that compose the reservoir. Isofrequency volumes, developed through spectral decomposition of 3D seismic data over the field, helped identify and map subtle shear faults that proved to be controlling the location and orientation of the dominant fracture trend in the field. Horizontal boreholes, needed to convert the field from gas production to gas storage, were planned and drilled based on this seismic interpretation. The existence of these shear faults, their location, and their orientation were confirmed by image logs acquired along the length of six horizontal gas storage boreholes. Additionally, flow tests performed to determine gas deliverability supported this interpretation.

Research and Application of Temporary Plugging Agent Technology for High-Pressure Wells in Gas Storage Facilities

Before various construction of gas storage well, in order to ensure safety, the reservoir must be temporarily blocked, degassed by circulation and no gas in the well can be operated. There are many temporary plugging methods for oil and gas wells. This paper studies the more advanced micro mesh gel temporary plugging technology in the industry and its application in gas storage wells, which mainly solves the problems of poor degradation backflow effect and difficult permeability recovery caused by weak formation stability after temporary plugging of gas storage wells. Research points: (1) On the basis of ordinary gel, through the fusion with cross-linking agent with special structure, a micron network polymer with significant steric hindrance effect on water molecules is finally formed, which improves the strength and stability of the gel system. (2) Add hexamethylene tetramine, bisphenol propane, delayed cross-linking agent and stabilizer into the polymer aqueous solution. It is verified by laboratory tests that the micron mesh gel can be formed after constant temperature coagulation for 3h~70h at ambient temperature of 90°C~170°C. (3) The temperature resistance, permeability and gel breaking of micron mesh gel are tested in the laboratory, and the results can meet the construction requirements. (4) After the temporary plugging operation of Well Su 49K-2X in the gas storage reservoir of Huabei Oilfield is completed, the degradation products of gel breaking will flow back smoothly to ensure that the well can be put into normal injection and production quickly. The test results show that: (1) Micron mesh gel has the advantages of long plugging validity, high temperature resistance, low viscosity after gel breaking, no residue, thorough gel breaking, no formation plugging pollution, and no impact on the original reservoir permeability. It is a new green plugging technology suitable for deep buried high-temperature depleted oil and gas reservoirs. (2) Before construction, the well temperature shall be measured to conduct test injection, so as to prevent gas invasion from affecting the construction effect. The pump injection displacement is designed to be redundant, so as to prevent the low molecular solution from not reaching the design position in the well on time, and the formation of solid rubber plugs at other positions in the well from affecting the construction.

Mathematical Modeling of Gas Filtration in the Bottomhole Zone of Underground Gas Storage Wells Using Fractional Derivatives

Mathematical Modeling of Gas Filtration in the Bottomhole Zone of Underground Gas Storage Wells Using Fractional Derivatives

Developing an electronic archive of geophysical survey results from underground gas storage wells

The study aims to analyse and systematise the data from geophysical surveys of wells (GSW) of underground gas storage (UGS) facilities. In order to minimise the time required for a detailed analysis of the paper-based GSW data for the entire period of gas storage facility operation, it is advisable to transfer it to electronic form as much as possible.

Risk analysis and Assessment of Wellbore Integrity Failure in Underground Gas Storage Based on Bayesian Network

Well integrity assessment plays vital role in the risk management of gas storage wells, which has emerged as a key topic of political and scientific discussion in the gas industry. However, the current research did not provide quantized assessment of failure probability of well integrity. To quantitatively evaluate the failure risk of gas storage well integrity, the probability model based on Bayesian network is established and calculated incorporating the relevant historical statistical data of gas storage well integrity failure and Leaky Noise or Gate extended model. Besides, the risk priority evaluation criteria of well integrity are set up, combining with the analytic hierarchy process. And the risk judgment matrix is constructed to quantitatively evaluate the risk of wellbore integrity failure in gas storage. Practical guidelines and solutions derived from the results of the current study can be used for the design of the gas storage wellbores.

The Flow Law of Brine and Sediment Particles in Gas-Driven Brine Drainage in the Sediments of Salt Cavern Gas Storage

The geological resources of salt cavern gas storage in China are mostly complex layered salt beds with many thin inter-layers and high insoluble matter content. In the process of cavity-building by water-solution method, the insoluble matters in salt layers and inter-layers are peeled off and deposited at the bottom of salt cavern, occupying more than one-third of the whole cavity volume. These sediments have a large pore volume and strong compressibility, and they are filled with brine; as a result, they have great potential for gas storage. The research on the flow law of brine and sediment particles in gas-driven brine drainage in the sediments of salt caverns is the basis of utilizing the void space of sediments for gas storage. In this paper, salt cores of salt cavern gas storage wells in the Jintan District were selected, and the physical characteristics of insoluble sediments of the salt cores were analyzed. Then, a laboratory simulation device and experimental method of the gas-driven brine drainage were presented. Using artificial composite sediments in the experimental device, the following was tested: (i) the flow rates of brine and particles in the vicinity of the brine drain pipe in the sediments under different nitrogen displacement pressures, (ii) the relationship between the sand extraction amount and nitrogen displacement pressure of different brine drain pipes, (iii) the sand extraction amount of different sizes of particles with brine drain time, (iv) the cumulative sand extraction amount of different brine drain pipes, and (v) the effect of brine flow rate on the sand extraction amount. The results show that quartz, plagioclase, and ankerite account for 45–94% and clay accounts for 3.3–14.4% of the insoluble minerals of the salt cores from the Jintan District. The particle size distribution of the sediments ranges from 0.04 mm to 6 mm and can be divided into four ranges: <0.5 mm, 0.5 mm~2 mm, 2 mm~4 mm, and >4 mm. The mass percentage of each range is 37.9%, 36.5%, 17%, and 8.6%, respectively. There is a threshold pressure of the gas-driven brine drainage, where the larger the diameter of the sieve hole, the lower the threshold pressure, and the easier the pipe is to sand out. The diameter of the sieve hole has a great influence on the flow rate of the sediment particles near the brine drain pipe. The increase in nitrogen displacement pressure has a positive correlation with the flow rate of sediments near the pipe with 5 mm diameter sieve holes, but has little effect on the flow rate of sediments near pipes with 1.5 mm or 0.5 mm diameter sieve holes. The sand extraction amount is affected by factors such as the nitrogen displacement pressure, diameter of sieve hole, brine drain time, and brine flow rate in the process of gas-driven brine drainage. A higher nitrogen displacement pressure and brine flow rate lead to more sand extraction. A screen pipe with 1 mm diameter sieve holes is suggested to be used for sand control, the sieve holes are recommended to be machined in the shape of a trumpet with a small inlet section (i.e., 1 mm) and a large outlet end (i.e., 1.5 mm), and the brine flow rate is suggested to be about 30 m3/h when the brine removal is carried out in the sediments of salt cavern, which depends on the actual operation on site.

The failure law of the cement plug-casing interface for direct plugging in the casing of old wells for salt cavern gas storage

The old salt hole wells cannot be directly converted into gas storage, injection and production wells, so the old wells must be plugged to ensure the effectiveness of plugging. Aiming at the plugging problem of old wells in salt cavern gas storage, a finite element model of the formation-cement sheath-casing-cement plug assembly suitable for direct plugging in the casing of salt cavern gas storage is established to simulate the fracture stripping process of the cement plug-casing interface. The results show that under the pressure of the gas storage, the cement plug casing bonding interface will undergo shear deformation, and after stacking to a certain extent, peeling phenomenon will occur. As the simulation time increases, the peel failure length gradually increases and tends to stabilize, reaching the limit of peel failure length. In the process of research, the factors and laws affecting the peeling failure length are also analyzed. It is found that the peeling failure length of the cement-casing interface is related to the maximum operating pressure of the gas storage, the length of the cement plug, the diameter of the cement plug, the elastic modulus, Poisson’s ratio. The research results are helpful to judge whether the plugging length in the casing is sufficient, and provide theoretical guidance to ensure the long-term safe operation of the gas storage.

Case Study of the Use of a Digital Twin for Leak Detection and Quantification in Underground Gas Storage Wells

Summary Underground gas storage (UGS) wells are essential components in energy security. However, UGS wells present a complicated and delicate combination of elements where ensuring safe and secure functionality over long periods is paramount. This paper showcases how a digital twin is used to evaluate and forecast the link between leaks and temperature and pressure trends in a UGS well, allowing the identification and quantification of defects and, subsequently, well barrier integrity. The digital twin used for this application presents advantages compared with other solutions present on the market with regard to the simplified configuration; that is, with minimal input data, the system can produce an accurate and useful output, which is then used in the well integrity decision-making process. UGS wells present additional criticalities with respect to normal production wells due to their longer life span and the repetitive production and injection cycles. This makes early and accurate leak detection essential for the safe management of the well barriers. The proposed digital twin simulates the trends of pressure and temperature within each annulus and compares results with data from the field, allowing the identification of the position and size of leaks. A genetic algorithm is applied to optimize the placement of leaks on their specific barriers. Once a leak is identified, a risk assessment is conducted to evaluate the overall integrity of the well. If the status of the well is found to be critical enough, an intervention may be planned. The studies presented show how the digital twin has been used on two wells with similar problems. At first, it has confirmed the necessity to put the well out of service as opposed to planning maintenance, thereby saving both time and cost. In the second case, it allowed the validation of a solution that led to a 60% reduction in failure consequence, allowing the well to continue operating without major costs or risks. The errors of the resulting simulations were always confined within the 0.5 bar limit highlighting its accuracy. The system has been in use for over a year and has shown great potential in accurate and efficient identification of leaks. This has accelerated the process of well integrity evaluation and allowed timely interventions on wells that required it. On the other hand, the process has highlighted cases where previous assumptions about leak location and size were corrected using the digital twin, therefore reducing the costs of interventions. Finally, the model showcases a clear readiness for predictive capabilities aimed to select, plan, and design fit for purpose mitigating actions.

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.

Study on simulation of cement plug—formation interface stripping failure and main influencing factors

Among the existing gas storage facilities, salt cavern gas storage has the advantages of high injection production efficiency, low gas cushion volume, safety, flexibility, etc. It is of great significance to speed up the construction of underground gas storage by transforming abandoned salt caverns of salt industry into underground gas storage. However, old salt cavern wells cannot be directly converted into gas storage injection and production wells, so the old wellbore must be plugged to ensure the effectiveness of plugging. Therefore, a set of plugging optimization technology for salt cavern gas storage wells is urgently needed. In this paper, a 3D finite element model of the cement plug-formation system based on cohesive element method is established for the milling and plugging of the old well in the salt cavern gas storage section. The results show that under the condition of constant gas storage pressure, a certain degree of small deformation will occur at the bottom of the cement plug after compression, resulting in the shear direction deformation of the cement plug formation cementation interface, and peeling will occur after accumulation to a certain extent. With the increase of simulation time, the length of stripping section gradually increases and tends to be stable, and reaches the limit of stripping failure length. In the process of research, the factors and laws affecting the stripping failure length were also analyzed. It was found that the stripping failure length of cement plug formation cementation interface was related to the maximum operating pressure of gas storage, cement plug length, cement plug diameter, elastic modulus, Poisson’s ratio and other factors. The research results are helpful to judge whether the milling and plugging length of the old well section is sufficient, and provide theoretical guidance for ensuring the long-term safe operation of the gas storage.

Analysis of Multiple Annular Pressure in Gas Storage Well and High-Pressure Gas Well

In gas storage or high-pressure gas wells, annular pressure is an unavoidable threat to safe, long-term resource production. The more complex situation, however, is multiple annular pressure, which means annular pressure happens in not only one annulus but two or more. Such a situation brings serious challenges to the identification of well integrity. However, few researches analyze the phenomenon of multiple annular pressure. Therefore, this paper studies the mechanism of multi-annular pressure to provide a foundation for its prevention and diagnosis. Firstly, the multi-annular pressure is classified according to the mechanism and field data. Then the failure mechanism and function of the wellbore safety barriers in the process of passage formation are analyzed. Finally, some suggestions are put forward for identifying and controlling multi-annular pressure. The results show that gas storage wells and high-pressure gas wells have the conditions to generate pressure channels, which leads to the expansion of annular pressure from a single annulus to multiple annuli. The pressure channel is composed of the tubing string, casing string, and a cement mantle, and the failures among the three have causal and hierarchical relationships. According to the channel direction, it can be divided into two types: tubing-casing annulus to casing annulus and casing annulus to the tubing-casing annulus, of which the former is more harmful. Some measures can be considered to prevent pressure channeling, including improvement of cementing quality, revision of maximum allowable annular pressure, and suitable frequency of pressure relief.

Numerical Simulation of Critical Production Pressure Drop of Injection and Production Wells in Gas Storage Based on Gas-Solid Coupling

The periodic injection-production process of natural gas in underground gas storage make the rock bear alternating load under the gas-solid coupling. The alternating load changes the physical properties of rock, and then influence the critical production pressure drop of injection-production wells in gas storage. In the case of gas-solid coupling, the decisive factors affecting the alternating load are the number of injection-production cycles and the injection-production differential pressure. Therefore, a discrete element numerical simulation model is established to simulate the gas-solid coupling process of gas storage wells under different injection-production cycle and differential pressure. The influence mechanism of injection-production cycle and differential pressure on particle cementation and primary crack is analyzed microscopically and also the influence law of injection-production cycle and differential pressure on rock mechanical properties is analyzed from the macroscopic. Finally, the influence law of injection-production cycle and differential pressure on the critical production pressure drop of injection-production wells due to gas-solid coupling can be obtained. The results show that under the influence of gas-solid coupling, the number of bonded contact cracks and micro cracks in the model increase gradually, both the elastic modulus ratio and the cohesion ratio decrease gradually with the increase of injection-production cycle and the higher the injection-production differential pressure, the greater the decline range. Then, with the injection-production cycle increasing the Poisson’s ratio increases gradually and the higher the injection-production differential pressure, the greater the increase range. Finally, the internal friction angle ratio increases greatly in the initial stage, after that decreases and then shows a linear increase. According to the influence law, the relationship model between the critical production pressure drop of injection-production wells in gas storage and the injection-production cycle and differential pressure under the gas-solid coupling will be established, which is used for the dynamic prediction of the critical production pressure drop of injection-production wells in the whole life cycle of gas storage.

Experimental Study on Sealing Failure Mechanism of Injection-Production String in Underground Gas Storage under Cyclic Loading

In order to clarify the impact of cyclic loading on the mechanical properties and sealing performance of threaded connections on pipe string under the injection-production conditions of gas storage and the airtight threaded connections suitable for the actual working conditions can be preferred, the sealing failure of injection and production tubular strings of several domestic gas storages was investigated comprehensively. It was found that the airtight threaded connections with different performance may leak during the service of tubular strings. Existing standards and testing methods have limitations, which are not fully applicable to the working environment of gas storage wells and the production mode of forced injection-production and cannot reflect the operation characteristics of multiround injection and production. Based on the stress analysis of the tubular string during injection and production, a full-scale simulation testing of 30 cycles of gas seal cycle under alternating load was proposed. The cyclic loading test results of two P110·13Cr tubing in domestic gas storage showed that after 30 cycles of cyclic loading, the yield strength, internal pressure strength, collapse strength, and compressive bearing capacity of tubing were all decreased; the compression efficiency of the joints should be fully considered when selecting the gas-sealed thread.

Research on casing erosion in reservoir section of gas storage wells based on Gas-solid Two-phase flow

Gas storage wells are characterized by large injection and production volumes and multi-cycle high-intensity cyclic injection and production, and the high-speed flowing sand particles have a strong erosion effect on the tubular column, threatening the safety of the gas storage wells' tubular column. In this paper, gas–solid two-phase flow erosion experiments and erosion simulation are used to study the effects of sand parameters, casing materials, and formation temperature on the erosion rate of reservoir section casing during gas recovery. The results show that due to the high temperature weakening the material strength of the casing in the reservoir section, the erosion rates of N80 and P110 casings increase with the growth of environment temperature. The casing erosion rate in the reservoir section increases with the raising of gas production volume, and the casing erosion rate increases rapidly when the gas production volume of the case well exceeds 162 × 104m3/d. The increases in sand particle diameter and mass flow rate also aggravate the casing erosion. The borehole dog-leg degree affects the erosion rate of the casing by influencing the attack angle of sand particles on the casing, and the erosion rate increases significantly when the borehole dog-leg degree exceeds 3°. The study results provide theoretical guidance for the building and operation of gas storage wells and are of great practical significance.

An Experimental Study on Phased Array Ultrasonic Testing for Internal Inspection of Gas Storage Wells

A reduction in wall thickness, caused by corrosion, of the inner and outer surfaces of underground compressed natural gas storage wells is one of the main causes of failure. Therefore, taking wall thickness measurements is an important task during periodic inspection. This study proposes a corrosion detection technique based on the well’s shape using cylindrical convex ultrasonic phased array and develops a cylindrical convex phased array probe with 512 elements. Using an example well of ∅177 × 10.36 mm, the influences of process parameters such as active aperture, focal length, gain, and gate threshold are studied. In addition, an experiment is conducted on a sample well with artificial defects for parameters optimization. Next, experimental tests are carried out on the well at the test platform according to the optimized parameters. The results show that the proposed technique is of high sensitivity and efficiency for the detection of corrosion defects and is able to detect pitting corrosion of more than ∅2 mm and line corrosion of 1 mm width.

Developing measures to eliminate of hydrate formation in underground gas storages

The objective of this article is the analysys of methods for preventing and eliminating hydrates formations, classifying them and choosing the best ones for use in underground gas storage facilities. Comprehensive measures for the stable operation of gas storage facilities in the presence of conditions for the occurrence of hydrates formations were developed. Zones, being potentially prone to the hydrates formation during the gas storage facilities operation were identified. The operational parameters of gas storage wells during gas withdrawal are analyzed. The identified wells were operated under difficult conditions due to the deposition of hydrates on the wellheads, in flowlines and process equipment of gas storage facilities. The places of the highest hydrates accumulation on underground gas storages were determined: from the bottomhole of wells to the gas purification unit of the gas gathering station. Hydrate-prone zones were identified by computational fluid dynamic (CFD) modeling at the location of regulating choke installations in underground gas storage facilities. The zones of the greatest hydrates accumulation on underground gas storages were determined: from the bottomhole of wells to the gas purification unit of the gas gathering station. The analysis of the methods used in gas storage facilities of Ukraine to prevent and eliminate hydrates formation was out. A set of measures was proposed to prevent the hydrates formation in storage facilities to ensure their stable operation. Based on the Euler approach (Mixture model) by CFD modeling, zones prone to hydrates formation were determined at the installation site of regulating chokes in underground gas storages. The influence of the degree of fittings opening on the location of potential zones prone to hydrates formation was estimated. The gas-dynamic processes in the internal cavity of the gas pipeline at the installation site of the control fittings were studied and their influence on the distribution of bulk particles of the gaseous and liquid phases was established. Based on the studies performed, it was recommended to change periodically the mode of well operation for a certain time by opening or closing the regulating choke under favorable conditions for the formation of hydrates, especially at low ambient temperatures. The obtained results of experimental studies and calculations showed that in order to solve the problem of hydrates formation at gas storage facilities, it is advisable to use diverse measures through the introduction of modern intelligent systems for monitoring and controlling the technological process. Further refinement of the algorithm of the proposed monitoring and control system with its approbation in production was provided. The results of the experimental studies and CFD modeling carried out allowed providing a more reasonable approach to the application of various available methods and measures to prevent hydrates formation in underground gas storage facilities. This approach made it possible to develop new effective ways and measures to prevent such complication. Based on the conducted experimental studies and modeling, the major zones prone to hydrates formation in underground gas storages were determined. The developed measures will allow timely detection and prevention of hydrates formation at gas storage facilities are original.

The Application of Breakthrough Pressure in the Evaluation of the Sealing Ability of Cement–Casing Interface and Cement Matrix in Underground Gas-Storage Wells

This paper proposes an evaluation system for the sealing ability of cement–casing interface and cement matrix, which was developed based on a permeability testing device and a model that predicts the breakthrough pressure of cement sheath matrix and interfacial transition zone (ITZ). It was found that the breakthrough pressure of ITZ was much smaller than that of cement matrix. Moreover, compared with water-based drilling fluid, oil-based one led to lower breakthrough pressure of ITZ even after the flushing treatment. Meanwhile, latex, resin and elastic materials enabled a substantial rise in the breakthrough pressure of cement matrix. However, compared with the latex, resin and elastic cement, the expansive cement had higher breakthrough pressure of ITZ, indicating an improvement on the interface sealing ability. Additionally, a small enlargement rate of the hole diameter and long effective bond were able to prevent gas storage wells from leakage.