Underground Gas Storage Operations Research Articles

Cartographic support of design, construction and operation of underground gas storage in rock salt

Abstract. Investigated the directions of use of topographic maps and requirements for them at different stages of design, construction and operation of underground gas storages in rock salt – one of the most important parts of Russia's Unified gas supply system. The specificity, complexity and diversity of cartographic support of this industry emphasized. A new type of topographic map is proposed, the content of which is subjected specially to the purpose of creating underground gas storage with the display of information about the objects of the entire complex of storage, their parameters, and data about development of dangerous natural and anthropogenic processes.The system of notation conventions is developed: a) wells of various type and purpose, their characteristics; b) underground and surface objects of storage in the form of water-brine and technological complexes, pipelines for various purposes; c) environmental monitoring facilities, specially protected areas. The necessity substantiated to supplement the main original of the map with text characteristics with thematic maps-insert and 3-D models (figure 1).As the most current thematic maps are considered: the depth and power of the salt rocks (figure 2); the calculated subsidence trough of the earth's surface (figure 3); the zone of maximum spread of the construction of the brine and mineralization of groundwater (figure 4).In general, all the presented developments characterize a new type of specialized topographic map for the design, construction and operation of underground gas storage.

Stresses and Temperature Affecting Acoustic Emission and Rheological Characteristics of Rock Salt

Synchronized acoustic emission and strain measurements were carried out in rock salt samples subjected simultaneously to different levels of uniaxial mechanical and incrementally increasing temperature effects. Methodological and hardware support of such measurements is described. Experimental dependences are obtained, which reflect changes in shear strains and acoustic emission activity of samples as functions of time and temperature for different axial stresses. As the stresses increase, rock salt transits to the stage of progressive creep at lower temperatures. The transition to each subsequent stage of the temperature effect is accompanied by an increase in the steepness of shear strains and activity-average acoustic emission. The patterns of changes in these parameters at the stages of steady and progressive creep of rock salt are analyzed. The advantages of using acoustic emission measurements to predict rock salt failure due to progressive creep, as well as their importance for solving the problem on estimating salt rocks properties in real thermobaric conditions for the construction and operation of underground gas storages are noted.

Картографическое обеспечение проектирования, строительства и эксплуатации подземных хранилищ газа в каменной соли

Картографическое обеспечение проектирования, строительства и эксплуатации подземных хранилищ газа в каменной соли

Pseudo-Elastic Response of Gas Bearing Clastic Formations: An Italian Case Study

The research presented in this paper focuses on the analysis of land movements induced by underground gas storage operations in a depleted reservoir in Northern Italy with the aim of increasing the understanding of the deformation response of deep formations via a real case study. The a priori knowledge of the pseudo-elastic parameters showed a substantial discrepancy between static values from triaxial lab tests and dynamic values obtained via the interpretation of sonic data at wellbore scale. The discrepancy is not surprising for the formations under investigation: a thousand meters of a silty to shaly sequence intercalated with arenaceous banks above a reservoir formation, which is basically made up of sandstone intercalated with shale intervals and conglomerates. Information collected for over more than ten years of seasonal production/injection cycles (i.e., time and space evolution of the reservoir fluid pressure and of the induced land surface movements) was then combined in a 3D numerical geomechanical model to constrain and update the a priori knowledge on the pseudo elastic model parameters via a back analysis approach. The obtained calibrated model will then be used for reliable prediction of system safety analyses, for example in terms of induced ground movements.

Numerical simulation on oil rim impact on underground gas storage injection and production

A large number of underground gas storage operating experience shows: the oil rim has a great impact on gas injection and production. Here, the underground gas storage in the Dagang Oilfield (G393) was taken as an example to study the oil rim impact mechanism. Firstly, the G393 gas reservoir developmental history was simulated, based thereon, the equations governing the distribution of gas, oil, and water in the reservoir before building the storage injection and production equipment was established. Then, the oil rim impact mechanism on the gas seepage of underground gas storage operation was studied using numerical simulation method and the factors affecting oil recovery from the oil rim for the gas diffusion were outlined. The result shows that oil rim may prevent seepage of gas, resulting in a one-way gas onrush, thus affecting the smooth operation of underground gas storage. In addition, crude oil recovery in the oil rim may affect the gas well’s production capacity, the lower the degree of recovery of crude oil, the harder for the underground gas storage to run quickly and smoothly. Finally, the most appropriate injection wells for the G393 fault-block gas storage were designed, by which process the oil production period was shortened to 8 years, ensuring stable and efficient operation of the underground gas storage.

Optimization of basic parameters of cyclic operation of underground gas storages

The problem of optimization of process parameters of cyclic operation of underground gas storages in gas mode is determined in the article. The target function is defined, expressing necessary capacity of compressor station for gas injection in the storage. Its minimization will find the necessary technological parameters, such as flow and reservoir pressure change over time. Limitations and target function are reduced to a linear form. Solution of problems is made by the simplex method

Cement design for underground gas storage well completion

In order to shave the peak demands during the cold seasons, underground gas storage (UGS), balancing the supply-demand chain throughout the year, has been accepted as a strategic method. During the successive UGS cycles, the well cement experiences cyclic mechanical, thermal, and hydraulic stress and may crack due to its low elasticity and ductility. This could lead to the transmission of stored gas through cementing behind casing, one of the major challenges experienced in UGS operations, so posing high workover costs on UGS wells. In addition to workover costs, the loss of inventory due to gas transmission makes the reservoir insufficient in proper gas supply during the high-demand season. In this work, a new formulation has been invented in order to prevent cement cracking, improve cement elasticity and ductility, and reduce the crack propagation in the cement used for completion of UGS well. The new formulation adds a polymer and an elastomer to cement composition. Results showed that addition of latex to cement decreases the density, hydration and fluid loss of cement; also, the rate of cement bonding decreases. On the other hand, addition of polypropylene fibers results in dramatic improvement of compressive strength and stress strain properties of the cement. In comparison with elastomer, this additive provides a higher threshold elasticity of cement. Also, the combined cohesive effect of latex and flexibility of microfibers brings about the best resistance against excessive pressures.

Initial gas full-component simulation experiment of Ban-876 underground gas storage

Numerical simulation can provide guidance to resolve injection production contradiction during the operation of underground gas storage, it is the key to ensure the smooth operation of underground gas storage. To perform accurate numerical simulation, accurate gas full-component analysis data is essential. In this study, the full-component experiment simulation of Ban-876 underground gas storage was done according to the laboratory experiment natural gas component analysis data. The saturation pressure calculation, phase diagram characteristics analysis, constant composition expansion experiment and constant volume depletion experiment were carried out with simulation methods. Finally, the full experimental data of initial condensate gas component was obtained which can provide reliable equation of state (EOS) parameters for the underground gas storage history matching and effect prediction.

The feasibility analysis of underground gas storage caverns

This paper presents the fuzzy concept for the feasibility analysis of Underground Gas Storage (UGS) designed from Lined Rock Caverns (LRC). For this purpose, it is necessary to carry out a number of steps. The first is the determination of the geological model of the UGS region. The next is transferring of the geological model into the geomechanical model, which could be achieved by applying the system of Hoek and Brown based on the geological strength index (GSI). The equivalent Mohr–Coulomb strength parameters should be determined. The geomechanical analysis for risk during construction and later during operation of UGS using Finite Element Method (FEM) is carried out. The series of FEM analyses should be calculated for the determination of changes in the response functions due to changes in the design variables. The results of FEM analyses are given in table form. The cost of UGS is calculated with developed equations. The construction costs comprise the investment and operational costs of the UGS system. The total construction costs per unit of gas include the sum of fixed costs and variable costs. Once the results of FEM and cost analysis are obtained, we use those solutions to develop ANFIS models. In this paper the ANFIS model for cost prediction is described in detail and the similar procedure is used to develop geomechanical constrain functions. These models are the basis for the feasibility analysis of underground gas storage caverns.

An optimization model for managing compressors in salt cavern gas storage

In light of the upcoming gas market liberalization, the storage in underground gas stor‐ age should be treated as a commercial activity, providing profit to investors. Gas fuel con‐ sumed for the operation of underground gas storage facility, mainly by work of compressors injecting gas into storage, will have to be carefully accounted and bought at market prices. In a competitive gas market, technical and economic optimization of the underground gas storage operation takes on particular significance. Liberalized market requires that the under‐ ground gas storage operator manages the operation in the most efficient way, affecting the profitability of service storage provision. Optimization of operation of underground gas storage in salt cavern (CUGS) is an im‐ portant operational problem in CUGS management. Despite many works on this subject [6, 16, 17, 20], it is not totally resolved. The reduction of gas storage capacity in a bed of rock salt, called convergence is inevitable, but its size also depends on the cavern depth and the operating storage [5, 19]. Operation practice suggests that the first step is to inject a large cavern convergence, then the lower and finally the shallowest cavern lying. In the withdraw process, the situation is reversed. However, the optimization that takes into account only the speed of storage caverns convergence is not ideal. You may find that maintaining a regime of operation that minimizes the effect of reducing the volume of the storage spaces can increase the cost of the gas installation (surface infrastructure). It is because Injection of the gas to the deepest caverns requires more power compressors. This occurs in CUGS Mogilno where the system can transport up to 400,000 standard cubic meter per hour [SCm/hr] of natural gas which about 2% is used by the compressor sta‐ tions to inject gas into storage caverns. It is estimated [13] that the global optimization of the

A study of subsurface integrity issues for the Mondarra underground gas storage field

In gas reservoirs, issues related to declining deliverability and injectivity, well integrity and reservoir integrity are often found. These may become more common, however, in fields used for underground gas storage (UGS). This may be due to extreme operating conditions–primarily cyclical phases of production and injection often associated with large pressure and temperature fluctuations within the reservoir and wellbore, in addition to operating with significant pressure depletion. This study identifies specific sub-surface integrity issues that have affected the Mondarra gas storage facility. The Mondarra facility is Western Australia’s only UGS operation, owned and operated by the APA Group: Australia’s largest natural gas infrastructure business. Specific sub-surface integrity issues related to UGS were investigated. Results indicate that the production and injection cycles have decreased deliverability by 4.4% annually since 2007, primarily by plugging pore throats with inorganic precipitates, such as siderite and organic residues from the reciprocating compressor. Reservoir integrity, represented as a reduction in effective connected volume, has been identified as an issue following early re-pressurisation of the field. Detailed production monitoring and reservoir modelling has been used to investigate this risk and determine the likely range of outcomes. The mechanism of this reduced effective connected volume is uncertain; however, suggested reasons include: pressure-induced changes in the conductivity of micro-fractures and transmissibility of faults; compaction of the reservoir; or, water encroachment post depletion. Furthermore, sub-surface modelling has indicated a complex connectivity picture with multiple compartments and variable permeability layers impacting gas storage operations.

Minimizing Risk of Gas Escape in Gas Storage

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 113509, "Minimizing Risk of Gas Escape in Gas Storage by In-Situ Measurement of Gas Threshold Pressure and Optimized- Completion Solutions," by L. Ostrowski, SPE, Baker Hughes, and B. Ulker, RWE Dea A.G., originally prepared for the 2008 SPE Europec/EAGE Conference and Exhibition, Rome, 9-12 June. The paper has not been peer reviewed. Underground gas-storage operations and carbon dioxide (CO2) sequestration in aquifers rely on proper wellbore construction and on the sealing function of the caprock. Potential leakage paths are by migration along the wellbore as a result of poor cementation and flow through the caprock. Capillary pressure data, which are critical for prediction of gas leakage through the caprock, are seldom available and yet are necessary. An in-situ method of determining gas-entry pressure was developed to help reduce uncertainties in gas-leakage predictions. Simulations were performed using this gas threshold entry pressure to investigate the gas leak-age amount through the caprock and along the wellbore for both natural-gas- and CO2-storage models. Introduction Capture and geologic storage of CO2 are being considered to reduce CO2 emissions. Managing geological storage requires an understanding of the processes and risks, including the likely time scales and flux rates involved. Key processes are the migration of CO2 after injection into deep geologic formations, stratigraphic trapping, dissolution, residual-gas trapping, mineralization, and potential leakage. The storage capacity of an underground CO2-storage project must be related not only to the amount of CO2 that can be stored but also to long-term storage effectiveness. Experience with underground natural-gas storage provides useful insight into the geologic storage of CO2. Both methane (CH4) and CO2 are less dense than the usual formation water and thus exhibit a tendency to migrate to the top of the storage formation. Potential leakage of CO2 and CH4 from the storage formation can occur through the caprock, along the wells, and through faults and fractures. In many instances, underground natural-gas- storage projects are operated at pressures exceeding the initial reservoir pressure. Overpressurization usually occurs at the early stages of storage and is essential for increasing storage capacity and gas deliverability. This overpressure can result in pushing water out of the caprock and causing gas to leak from the storage formation. In CO2-storage projects, less is known about the risks of leakage through the caprock because of lack of experience. It is essential to determine the gas-entry pressure into the caprock before proceeding with any gas-storage project.

Underground Gas Storage in a Partially Depleted Gas Reservoir

In this work, underground gas storage (UGS) was studied on a partially depleted gas reservoir through compositional simulation. Prediction of reservoir fluid phase behavior and history matching was done by utilizing detailed reservoir information. The performance of UGS with different scenarios of reservoir depletion, gas injection, and aquifer strength was analyzed. The injection capacity and deliverability of reservoir was set to 350 MMSCF/D (6 months) and 420 MMSCF/D (5 months), respectively. Based on different scenarios and the anticipated target rate, the optimum pressure for converting this reservoir to UGS was found to be about 1600 psia. Also, it was found that if the reservoir is depleted to a lower pressure, it contains insufficient base gas reserve and may not meet the target withdrawal rate. Results showed that this problem can be overcome by injecting higher volume of gas in the first cycle. Furthermore, it was shown that an active aquifer can lead to irreversible reservoir shrinkage, increase in water-gas ratio, and pressure rise in reservoir. Another source of pressure rise during the UGS operations is the difference between z-factors of injected and reservoir fluids. It was found that injecting lean gas with high z-factor into a reservoir containing fluid of lower z-factor results in pressure rise at the end of each cycle. At successive cycles, composition of reservoir fluid approaches that of the injected gas because of continual mixing. Theoretically, composition of reservoir fluid will be near the injected fluid after infinite cycles, provided complete mixing occurs in reservoir. Under these conditions, difference between z-factors of injected and reservoir fluids become smaller, and reservoir pressure stabilizes.

Optimisation of the wells placement in gas reservoirs using SIMPLEX method

This paper presents novel optimisation model to evaluate the optimal number of wells for underground gas storage operations. More specifically, generalized well-placement scheme has been formulated to minimize the total number of wells required to fulfil prescribed multiple constrains including wells interference. The scheme integrates nonlinear models of reservoir and well performance. The optimization problem has been formulated mathematically and solved by iterative use of the SIMPLEX method. The method is dedicated to gas reservoirs or underground gas storages management. The method may be useful as a base for more detailed numerical reservoir simulation. The paper is illustrated by a field example related to optimisation of the production cycle of the underground gas storage in Poland.

Norg Underground Gas Storage: an Integrated 3-D Geological and Geophysical Reservoir Modeling Study

The Netherlands have an extensive gas distribution infrastructure supplying 80 x 10[sup 9] m[sup 3] per annum to the domestic and European market. The capacity requirement exceeds 600 x 10[sup 6] sm[sup 3]/d, of which 430 x 10[sup 6] sm[sup 3]/d is provided by the giant Groningen gas field. The Groningen field will soon reach a pressure at which this capacity can no longer be met without considerable investments. It will also become difficult to maintain the market gas quality, because of the increasing supply from small fields with widely varying gas qualities. Underground Gas Storage (UGS) will satisfy both capacity and gas-quality requirements. This UGS must eventually store 4.5 x 10[sup 9] m[sup 3] with injection/production capacities of 36/80-100 x 10[sup 6] sm[sup 3]/d, making it one of the largest UGS projects in the world. These extremely high-capacity requirements demand both high-matrix permeability and good understanding of vertical and lateral reservoir continuity. Matrix permeability is predictable due to the close relationship with the lithofacies defined within the primary Rotliegende depositional model. Minor faults, identified on three-dimensional (3-D) seismic attribute maps, represent potential transmissibility impairment zones, compartmentalizing the reservoir. This was initially suggested by core fracture studies and confirmed bymore » a subsequent field shut-in and pressure buildup test. Lithofacies and seismic structural data are integrated within a computerized reservoir geological modeling system known as [open quotes]Monarch[close quotes] to provide a highly detailed 3-D permeability model that is then tranformed into a model for dynamic reservoir simulation. The results confirm the required working volume for the UGS operation and provide a basis for the initial field development planning.« less

Calculation of the Leak Location in an Aquifer Gas Storage Field

Abstract A leak location method for aquifer gas storage fields utilizing nonsteady flow calculations is presented. The calculation method uses pressure responses in observation wells completed in a permeable zone in or above the caprock overlying a gas storage reservoir to locate leakage which exists in a single area. The leakage considered is localized - different from the leaky aquifer case which is well known to ground water hydrologists. Field data from an operating gas storage field where gas leakage exists are used to calculate location of the leakage. The location is determined graphically using water level changes in three observation wells. The leak location is calculated to be at distances from the observation wells proportional to the square roots of the times of equal pressure responses at the wells. No absolute values of porosity, permeability, sand thickness or composite water and rock compressibility are required in the graphical solution. The leak location method presented is generally restricted to gas storages which have single-point leaks. However, the method is also applicable in cases where all observation wells are relatively close to one leak, with distances from other possible leaks too far, or other leaks too small, to affect appreciably the water level responses of the observation wells. Introduction In underground gas storage operations leakage from the storage reservoir to higher porous formations sometimes occurs through fractures in the caprock, behind the casings of improperly cemented wells or through improperly plugged abandoned wells. If the leakage rate is too great, the storage field may be uneconomical to operate. Sometimes it is feasible to collect gas from wells drilled to the higher formations for reinjection into the storage reservoir. Nevertheless, leakage is an economic burden to the storage operation, and gas injection pressures and corresponding injection rates must be limited to control the leakage rate. Accordingly, it is highly desirable to determine the nature and location of the leakage and to correct it if possible. In the storage field discussed in this article, tracer tests were conducted which indicated that major leakage was occurring in the southern end. Three wells were drilled almost through the caprock surrounding the indicated general area of leakage, and an attempt was made to hydraulically seal off the leak by injecting water through a porous sand stringer in the caprock. Water injection proved unsuccessful in sealing the leak, probably because permeability of the sand stringer was too low to permit injection of water at sufficiently high rates. Following the attempt to seal the leak hydraulically, water levels of the three wells were measured continuously and calculations were made from data obtained to try to determine location of the leak. The calculation method developed considers lateral flow in a permeable sand within the caprock. JPT P. 623ˆ