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Comparison of base gas replacement using nitrogen, flue gas and air during underground natural gas storage in a depleted gas reservoir
Abstract
Base gas is considered as an important factor in the storage operation as it remains permanently in the reservoir and maintains the reservoir pressure along the production cycle. Depending on the reservoir under consideration, base gas may occupy as little as 15% or as much as 75% of the total underground gas storage (UGS) reservoirs. Providing and injecting the cushion gas has the most contribution to the cost of the storage operations. Therefore, part of the base gas can be replaced by a cost-effective gas such as nitrogen, flue gas or air to reduce the costs of the investment. Some degree of mixing takes place when two miscible gases come into contact with one another that affects the quality of the produced natural gas. Therefore, the process needs to be studied and controlled. In this study, the feasibility of underground gas storage and the substitution of the base gas by a cheaper gas, i.e., nitrogen, flue gas, and air, are investigated in a partially depleted dry gas reservoir with very low initial pressure. To do so, a comparative study is performed among nitrogen, flue gas and air as the alternative gases to the base gas. In addition, the effect of flue gas composition on the performance of base gas replacement and ultimate gas recovery is investigated. Pure CO2 is considered as flue gas with zero mole% N2. In the end, the effect of the reservoir properties on mixing between the gases is studied. The results indicated that it is possible to substitute 24.8% of the base gas by nitrogen to obtain a 16.2% increase in the gas recovery of the reservoir. In this case, the ultimate recovery reaches 50.90%. Using flue gas as the alternative gas, the results showed a 15.6% increase in the gas recovery of the reservoir, obtained by substituting 23.9% of the base gas. The ultimate recovery using flue gas is 50.31%. According to the results, flue gas can be used as an appropriate option to replace the base gas of the UGS reservoir under consideration, and hence, there would be no more need for separation and purification of N2 and CO2. Increasing the CO2 composition in the flue gas up to 46.6 mole% leads to a decrease in the base gas replacement amount. When the composition increases above 46.6 mole%, the amount of the replaced gas does not change. However, in this composition range, more flue gas is injected into the reservoir, which has environmental advantages. The highest injection rate of the flue gas is obtained when the flue gas contains 100 mole% of CO2. The main problem in using air as the base gas is the high viscosity of air which requires a high injection pressure. According to the results, using air as the replacement gas, 21.3% of the base gas is substituted by air. In this case, gas recovery increases by 13.9% with respect to the reservoir depletion scenario and the ultimate recovery reaches 48.62%.
... Based on a comprehensive analysis of the economic and gas mixing levels with actual engineering parameters, Li and Hu pointed out that an appropriate permeability level is beneficial for CH 4 production. In addition, Sharif compared the results of Cao, Mu, and Namdar and found that the permeability was positively correlated with the gas flow speed, as shown in Figure 11 [25,37,44,45]. The higher permeability leads to the easier occurrence of the viscous fingering phenomenon during the process of the gas storage operation. ...
... The reservoir pressure dominates the flow of gas, and the pressure changes directly affect the operation efficiency of gas storage and the CH 4 recovery. An increase in pressure leads to a decrease in the molecular diffusion coefficient, which affects the physical properties of the gases, including the density, viscosity, and compression factor, etc. [44]. Li and Hu et al. showed that when the reservoir pressure is lower than the supercritical pressure of CO 2 , the diffusion of CO 2 molecules intensifies, resulting in a greater degree of mixing between CO 2 and CH 4 [40,43]. ...
... In summary, after the injection of the CO 2 cushion gas, it is more inclined to settle between the CH 4 working gas and the formation water, i.e., at the gas-water contact (GWC) area. Thus, the CO 2 injection location should be away from the methane operation area with perforations with the lowest fluid flow properties, i.e., low permeability close to the GWC area [44]. ...
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.
... However, other factors, such as cost and technical issues, should be considered to meet the entire point of cushion gas replacement requirement, which is the optimization of the underground gas storage operation from an economic standpoint. The main technical issue in substituting cushion gas with a cheaper gas is the mixing phenomenon between the replaced cushion gas and natural gas, which can devaluate the quality of the produced gas and must be controlled by operational parameters to avoid additional costs on the surface for the separation of impurities [9]. Multiple studies and practical projects have been conducted to evaluate the economic and operational feasibility of utilizing nitrogen and carbon dioxide as cushion gas in an underground gas storage reservoir, while other studies have considered a mixture of these gases along with methane. ...
... Multiple studies and practical projects have been conducted to evaluate the economic and operational feasibility of utilizing nitrogen and carbon dioxide as cushion gas in an underground gas storage reservoir, while other studies have considered a mixture of these gases along with methane. In recent studies, air has also been considered a cushion gas [9][10][11][12]. These studies are reviewed in this paper with the aim of providing future researchers with a brief but thorough and comprehensive review of the previous studies to specify notable findings that can lay the groundwork and insights for answering current challenges and future works about cushion gas replacement using cheaper gases such as nitrogen and carbon dioxide. ...
... The injection of candidate gas with higher viscosity (such as air or oxygen) to replace the cushion gas requires a higher injection pressure. Therefore, to control the injection pressure from exceeding the fracture gradient of formation and cap rock, it may not be possible to replace the cushion gas with the planned injection rate during the scheduled time [9]. The abnormal viscosity rise of carbon dioxide can be seen passed the 1000 psia checkmark (Fig. 8-a), demonstrating a liquid-like viscosity range. ...
Due to the significance of gas storage in recent years, the importance of its most crucial operational and economic aspect, the cushion gas, has come under great scrutiny. The cushion gas is injected into the reservoir to raise the pressure to a specific range, ensuring optimum rate and sufficient deliverability during the production phase. 20 to 70 % of the total gas in an underground gas storage (UGS) operation can be comprised of cushion gas, and it is widely known that it's the most expensive part of the procedure. If the natural gas itself is used as the cushion gas, it cannot be produced, reducing the efficiency of resource delivery to the consumer market. Consequently, nitrogen and carbon dioxide have been considered to replace a portion of the cushion gas. Although this application can prove beneficial, there are still gray areas that have not been addressed conclusively. This paper aims to categorize the advantages and disadvantages of the application of nitrogen and carbon dioxide as cushion gas from previous studies for the first time and provide future researchers with challenges that are yet to be resolved. Initially, a brief history of prior operations and studies is given. Secondly, the properties of nitrogen and carbon dioxide and their potential effect on the operation and mixing between cushion gas and working gas are discussed. After that, the operational parameters affecting the mixing phenomenon concerning each gas are presented, and future challenges and opportunities regarding the utilization of nitrogen and carbon dioxide as the cushion gas are introduced. It was concluded that the abnormal changes in CO2's properties, specifically density, and viscosity, can heavily impact the cushion gas selection process. Furthermore, an increase in production and injection rates can increase the mixing percentage. Simultaneous injection of cushion gas and working gas can potentially limit the mixing phenomenon and decrease the duration of the UGS process before it is ready for the initial production phase.
... However, by increasing the porosity, the concentration of N 2 in the produced well stream decreases. This decrease in the mixing phenomenon may be caused by the increased volume of the injection gas arising from the increased porosity [49]. ...
Due to the increasing world population and environmental considerations, there has been a tremendous interest in alternative energy sources. Hydrogen plays a major role as an energy carrier due to its environmentally benign nature. The combustion of hydrogen releases water vapor while it also has a vast industrial application in aerospace, pharmaceutical, and metallurgical industries. Although promising, hydrogen faces storage challenges. Underground hydrogen storage (UHS) presents a promising method of safely storing hydrogen. The selection of the appropriate cushion gas for UHS is a critical aspect of ensuring the safety, efficiency, and reliability of the storage system. Cushion gas plays a pivotal role in maintaining the necessary pressure within the storage reservoir, thereby enabling consistent injection and withdrawal rates of hydrogen. One of the key functions of the cushion gas is to act as a buffer, ensuring that the storage pressure remains within the desired range despite fluctuations in hydrogen demand or supply. This is achieved by alternately expanding and compressing the cushion gas during the injection and withdrawal cycles, thereby effectively regulating the overall pressure dynamics within the storage facility. Furthermore, the choice of cushion gas can have significant implications on the performance and long-term stability of the UHS system. Factors such as compatibility with hydrogen, cost-effectiveness, availability, and environmental impact must be carefully considered when selecting the most suitable cushion gas. The present study provides a comprehensive review of different types of cushion gases commonly used in UHS, including nitrogen, methane, and carbon dioxide. By examining the advantages, limitations, and practical considerations associated with each option, the study aims to offer valuable insights into optimizing the performance and reliability of UHS systems. Ultimately, the successful implementation of UHS hinges not only on technological innovation but also on strategic decisions regarding cushion gas selection and management. By addressing these challenges proactively, stakeholders can unlock the full potential of hydrogen as a clean and sustainable energy carrier, thereby contributing to the global transition towards a low-carbon future.
... Among them, the elastic model is widely used to simulate caprock mechanics during CO 2 storage owing to its ease in carrying out multifield coupling calculations with a high degree of coupling [17,18]. Based on the elastic constitutive model, a large number of hydromechanical coupling geomechanical models have been developed to analyze the mechanical integrity of caprock during the processes of injection and production [19][20][21][22][23]. Current research shows that the mechanical integrity of caprock will be affected by many factors during these processes [24,25]. ...
The rapidly increasing demand for the consumption of natural gas has attracted the interests to store natural gas in aquifer reservoir. However, natural gas injected into the aquifer reservoir, which could cause ground surface deformation and mechanical integrity destruction of caprock. Taking the aquifer gas storage of S trap as the research object, according to the geological structure and hydrogeological information, a coupling large-scale hydromechanical model is established to evaluate the damage risk of the gas reservoir in S aquifer. The proposed methodology is based on the development of fluid-solid coupling and application of FEM. The different failure mechanisms of S aquifer gas storage caprock can be evaluated on the basis of the tensile failure criterion and Mohr-Coulomb shear failure criterion. To analyze the change of caprock in gas injection and production process more clearly, a reference model is defined as an ideal calculation condition to discuss the mechanical response, pore pressure variation, and surface deformation characteristics of the caprock during injection and production. On this basis, the second scheme of sensitivity analysis is defined. The pressure injection rate, reservoir parameters, in situ stress, and other factors are considered, respectively, and the influence of different input parameters on mechanical stability and surface deformation of caprock is analyzed. Finally, the mechanical stability is analyzed and combined the above two criteria to predict the upper limit injection pressure of S. Simulation results show that the permeability and in situ stress have a significant influence on ground surface deformation and mechanical integrity of caprock, but Young’s modulus and Poisson’s ratio can be ignored; the upper limit pressure coefficient of S is 1.908.
... Also, the competitiveness of CCS can be improved if CO 2 injection has additional benefits. For example, CO 2 can be injected into natural gas storage facilities to replace cushion gas (Oldenburg, 2003;Ma et al., 2019;Namdar et al., 2020). Cushion gas costs can exceed 50% of the initial capital investment cost of the deployment of a natural gas storage facility. ...
Reservoir simulations of the co-injection of natural gas, carbon dioxide, and other non-condensable gases into saline aquifers are in demand in many areas of subsurface utilization, ranging from excess energy and greenhouse gas storage to the substitution of cushion gas with CO2. We aim at extending our reservoir simulator MUFITS for modeling flows in porous media related to these applications. For the accurate prediction of phase equilibria in aqueous systems, we implement a modified method of Søreide and Whitson in the compositional module of the software. The modified equation of state (EoS) involves the most recent literature data on the binary interaction coefficients and several new correlations for volume shifts to improve the accuracy of the EoS for predicting the partial volume of dissolved gases. All the aggregated and developed correlations are built into the simulator to facilitate its usage by the scientific community. The extended software is validated against a benchmark study of pure CO2 injection into a saline aquifer. Furthermore, two more complicated studies concerning the co-injection of several gases are conducted to demonstrate the potential application areas of MUFITS. First, we simulate the injection of impure carbon dioxide into an aquifer and briefly discuss the influence of N2 impurity on the propagation of the gas plume. We show that the plume is significantly wider in the case of impure CO2 injection. Second, we simulate the injection of supercritical CO2 into a synthetic natural gas storage reservoir to substitute cushion gas. We show that the mechanical dispersion can cause a rapid CO2 spread into the wells used for natural gas production.
Hydrogen has attracted attention worldwide with its favourable inherent properties to contribute towards a carbon-free green energy future. Australia aims to make hydrogen as its next major export component to economize the growing global demand for hydrogen. Cost-effective and safe large-scale hydrogen storage in subsurface geology can assist Australia in meeting the projected domestic and export targets. This article discusses the available subsurface storage options in detail by first presenting the projected demand for hydrogen storage. Australia has many subsurface formations, such as depleted gas fields, salt caverns, aquifers, coal seams and abandoned underground mines, which can contribute to underground hydrogen storage. The article presents basin-wide geological information on the storage structures, the technical challenges, and the factors to consider during site selection. With the experience and knowledge Australia has in utilizing depleted reservoirs for gas storage and carbon capture and sequestration, Australia can benefit from the depleted gas reservoirs in developing hydrogen energy infrastructure. The lack of experience and knowledge associated with other geostructures favours the utilization of underground gas storage sites for the storage of hydrogen during the initial stages of the shift towards hydrogen energy. The article also provides future directions to address the identified important knowledge gaps to utilize the subsurface geology for hydrogen storage successfully.
An economy based on hydrogen is widely regarded as the potential successor of the fossil-fuel-driven present energy sector. One major obstacle in developing the hydrogen economy is the suitable storage systems for different applications. This article presents an overview of the role of different storage technologies in successfully developing the hydrogen economy. It reviews the present state of various hydrogen storage systems from the surface and underground storage methods, their applications, and the associated scientific challenges. The integration of renewable energy in existing energy infrastructure requires developing suitable storage solutions along the energy supply chain. Large-scale seasonal hydrogen storage can be achieved through a subsurface geologic medium such as salt caverns, depleted hydrocarbon reservoirs, aquifers and hard rock caverns. The suitability of the geostructures depends on the desired storage cycles, capacities, and purity of stored hydrogen. The storage of hydrogen for stationary and mobile applications according to end user demands, generally less in capacity and requiring rapid storage cycles, is facilitated by surface storage methods. The physical storage of hydrogen is trapping it in vessels in its different physical states, such as compressed gaseous, cryogenic and cryo-compressed forms. Material-based storage of hydrogen is by adsorbing or absorbing hydrogen using solid-state materials. The performance of surface storage technics is characterized by gravimetric and volumetric densities, storage uptake and release kinetics, the cost involved, and operational safety. The technical insights of each storage technology are presented with recommendations and relevant fields of applications. No storage technic in its ideal conditions can be considered the best fit for all the applications, and each technic requires intense work to become acceptable for energy application.
Ten sandstone samples were chosen to conduct rock pore structure change law experiment before and after injection and production and the NMR fluid test experiment, the changes of pore size, permeability, and space filling degree were compared and analyzed. According to the findings, certain authigenic minerals (authigenic quartz and feldspar) in sandstone pores may come off after repeated rounds of high-intensity fluid erosion, obstructing the seepage channel. The composition and amount of clay minerals vary little due to gas–water interaction displacement, although some banded clay particles readily break off (polyhydrate kaolinite). The cracks produced by certain brittle rock particles can enhance the rock's porosity and permeability by about 20% and 10%, respectively. The fluid wettability of the rock changes as the operating cycle of subterranean gas storage rises, the gas saturation degree in the pores gradually increases, and the water gradually declines. Gas injection and production tended to attain equilibrium after 10 injection production cycles, and gas loss steadily decreased. It can be considered the node for the stable operation of subterranean gas storage at the present moment. As a result, high-intensity and numerous cycles of injection and production for sandstone underground gas storage may expand storage space, improve permeability, and progressively improve the gas-water ratio, all of which are beneficial to the stable and efficient operation of underground gas storage.
Base gas replacement by a cheap gas is one of the approved methods to reduce the cost of investment in underground gas storage process. Maximizing the amount of replaceable base gas is an attractive issue. However, the amount of base gas replacement can be reduced due to some limiting factors. By changing the composition of the candidate base gas, it is possible to obtain a smart gas with an optimized composition through which all limiting factors are simultaneously satisfied. In the present study, the feasibility of this idea is investigated in a real depleted gas reservoir by flue gas as the candidate gas with the aid of GEM compositional simulator and proxy model. The proxy model and Excel Solver optimization tools are used to improve the speed and accuracy in determining the optimum composition of flue gas composition. In addition, the effect of flue gas composition on the reservoir pressure and gas deviation factor is analyzed during gas storage cycles. The results show that when the CO2 content of the flue gas exceeds a specific value, carbon dioxide effect is dominant, which increases the wetting effect of the flue gas. In this case, the simultaneous injection of flue gas and storage gas in odd cycles reduces the reservoir pressure and the reservoir gas deviation factor. The results indicate that it is possible to replace 28.4% of the base gas and reach an enhanced gas recovery of about 18.55% in the reservoir under study using the optimized replacing gas composition of 17.24% CO2 and 82.76% N2.
The paper presents basic data on Enhanced Gas Recovery (EGR) by gas-gas displacement for nearly depleted natural gas reservoirs by injecting waste gases. The soundness of the concept of gas-gas displacement for enhancing gas recovery was investigated via laboratory investigations, compositional modelling and economic analyses. Paramount Resources is field testing the concept in their GRIPE Project in the Athabasca region of Alberta, to enhance production from a gas bearing stratum overlying the oil sand interval.
This paper is a part of a series of papers presenting results of EGR research conducted over a five-year period (2003 – 2007). The main targets were volumetric (closed) reservoirs in advanced phases of exploitation. Results of basic research on methane displaced from core samples by pure gases (pure CO2 or pure N2), as well as flue gases (mixtures of CO2 and N2), are presented.
A series of nine gas/gas displacement tests in 30 cm long, 4 cm diameter, Berea cores were conducted at a temperature of 70?C and a pressure of 6,200 kPa. Most of the tests were conducted in the presence of connate water, while others were conducted without connate water (dry cores) to confirm and benchmark the results by other investigators. The tests on consolidated cores showed that for pure nitrogen and pure CO2, used as the displacing medium, the recovery was comparable.
Where a mixture of CO2 and nitrogen displaced the natural gas, it was observed that there was a delay in CO2 breakthrough, associated with a period when only a mixture of methane and nitrogen was produced. This is so because solubility of CO2 in connate water is considerably higher than that of nitrogen. This leads directly to a higher gas recovery due to a longer exploitation period, given the fact that up to 20% nitrogen can be tolerated in the produced stream, as opposed to only 1% for the CO2 case. For this period of methane and nitrogen production, there are no operational problems associated with the corrosive nature of CO2.
EGR by gas-gas displacement is seen as a promising way of prolonging the productive life and economic recovery of many depleting volumetric gas reservoirs.
Introduction
Alberta currently has 42,000 gas pools, which are in different stages of exploitation. For these gas reservoirs, the pools that should be considered first in the implementation of large-scale EGR-CO2 and CO2 storage have not yet been identified, and no screening criteria have yet been developed. Currently, only the concept of "disused gas reservoirs" has been advanced(1) for CO2 storage. This concept implies that only those reservoirs that are in an advanced stage of depletion (with very little marketable gas left), traditionally with extremely low current pressure, or which are water invaded, should be considered. In this context, they have been considered exclusively for CO2 storage and not for enhanced gas recovery (EGR). This paper brings a new concept: that of simultaneous EGR and CO2 storage.
The development of a new two-constant equation of state in which the attractive pressure term of the semiempirical van der Waals equation has been modified is outlined. Examples of the use of the equation for predicting the vapor pressure and volumetric behavior of single-component systems, and the phase behavior and volumetric behavior of binary, ternary, and multicomponent systems are given. The proposed equation combines simplicity and accuracy. It performs as well as or better than the Soave-Redlich-Kwong equation in all cases tested and shows its greatest advantages in the prediction of liquid phase densities.
Using nitrogen and carbon dioxide as cushion gases can bring economic profit due to their cheap costs. However, the different properties of these gases cause differences in behavior when operating in underground gas storage (UGS). In particular, the mass density of nitrogen gas is similar to methane, while carbon dioxide is much heavier than methane in reservoir conditions. These differences cause loss of inert gas or productivity to vary. From this perspective, it is crucial to analyze the behavior of nitrogen and carbon dioxide during the operation of UGS reservoir. The purpose of this study is to evaluate loss of inert gas of injected gas and to determine productivity according to different cushion gases. A simulation research was performed to compare the effects of nitrogen and carbon dioxide and their behavior. The results showed that nitrogen has less loss of inert gas than carbon dioxide, but reduced productivity compared with carbon dioxide.
Porous media compressed air energy storage (PM-CAES) and geologic carbon sequestration (GCS) can potentially be combined when CO2 is used as the cushion gas. The large increase in density of CO2 around its critical pressure at near-critical temperature means that a PM-CAES reservoir operated around the CO2 critical pressure could potentially store more air (energy) for a given pressure rise in the reservoir. One-dimensional (1D) radial TOUGH2 simulations of PM-CAES with CO2 as the cushion gas have been carried out to investigate pressurization and gas-gas mixing effects. We find that pervasive pressure gradients in PM-CAES make it desirable to position the air-CO2 interface close to the well, but cushion gas at such locations is subject to strong and undesirable air-CO2 mixing and subsequent production of CO2 up the well. To avoid this negative effect, CO2 cushion gas should be located at the far outer margins of storage reservoirs where mixing will be very slow. In such a configuration, the super-compressibility of CO2 will not be exploited, but CO2 can be stored in the GCS context potentially earning significant value for the PM-CAES project depending on the price of carbon. © 2013 Society of Chemical Industry and John Wiley & Sons, Ltd
The cushion gas, providing the pressure energy necessary for withdrawal of working gas, makes up the largest part of the investment in underground gas storage projects. The suggested method of reducing this cost is the replacement of some part of the cushion gas with less expensive inert gas, such as nitrogen. In the replacement, there might be some problems due to mixing between natural gas and inert gas. Turkey has sharply increasing demand for natural gas. The constant imported gas and varying demand throughout the year due to the distinct seasons in the region are the reasons for severe need for gas storage in Turkey. There are no underground storage units in Turkey, but two gas reservoirs in the Thrace basin grant the potential for gas storage. From this point of view, the gas mixing problem is investigated for a typical gas reservoir by coupled use of a gas reservoir simulator and a transport model. A two-dimensional (2-D), single-phase numerical gas reservoir simulator is developed to obtain the pressure distribution during production and injection cycles. The velocity distribution is found by using these pressures. Then the two-dimensional transport model is used to calculate nitrogen concentrations around the injection wells. Both models are used effectively for controlling the mixing problem in an underground gas storage reservoir.
Enhanced gas recovery by gas-gas displacement can be achieved economically in several situations. For mature volumetric gas reservoirs suffering from low productivity due to low reservoir pressure, injection of waste gas can increase the ultimate gas recovery by maintaining gas production rates and preventing premature well abandonment. For water-driven gas reservoirs, pressure maintenance by gas injection will serve to (1) retard the influx of aquifer and (2) partially mitigate water coning caused by excessive pressure drawdown.
This paper presents the results of laboratory core displacement tests conducted to investigate the feasibility of enhanced natural gas production by using exhaust gas from combustion of bitumen in an oxygen rich atmosphere. A synthetic gas mixture containing carbon dioxide, nitrogen and sulfur dioxide was used to represent the exhaust gas of interest. Displacement tests were conducted in Berea core and in porous media prepared with silica sand as well as crushed carbonate rocks at pressures ranging from 0.69 to 6.2 MPa. The objectives of the experiments were to determine the effects of (1) pressure, (2) displacing gas composition (3) formation water and (4) rock mineralogy on recovery efficiency of uncontaminated methane from the porous media.
Several interesting phenomena were observed during the course of this investigation. Separation of injection gas components was observed in the effluent gas during displacement. Breakthrough of carbon dioxide and sulfur dioxide were delayed relative to nitrogen. This can be attributed to the higher solubility of CO2 and SO2 in water relative to nitrogen. These results are beneficial to natural gas production as they reduce the operating costs associated with corrosion during production of CO2 and SO2. The amount of green house gases and acid gases being sequestered in the reservoir will also increase due to these effects.
Diffusion coefficients in binary dense, fluid systems are measured and used along with data available in the literature to obtain a generalised correlation for predicting binary molecular diffusion coefficients in dense gases over a broad range of conditions.
Introduction
Attempts to quantify mixing phenomena in porous media are often encountered in design studies of processes related to petroleum recovery. Dispersion, an important part of mixing phenomena, can be related to the distribution in travel times that results when a fluid passes through a porous media(1). On a microscopic scale, the two most important mechanisms contributing to dispersion are variations in velocity between fluid elements flowing in neighbouring pores or groups of pores (often referred to as convective mixing) and molecular diffusion(1, 2, 3). Although there is some controversy over the magnitude of convective effects, it has been thought that in vertical gravity stabilized miscible floods, such as those carried out in the carbonate pinnacle reefs of Alberta, molecular diffusion played an important role in the mixing of the solvent bank with drive gas and oil(3, 4, 5). In other processes, such as gas, solvent or CO2 horizontal miscible floods, the effects of molecular diffusion are difficult to quantify, but are thought to be important in the recovery of non-flowing oil by mass transfer(6, 7, 8).
The estimation of molecular diffusion coefficients in low-pressure gases using the Chapman Enskog Theory(11) is adequate for a wide variety of single component and binary gases(10, 12), In liquids, the success of theoretical models has been more limited, perhaps because of the complex nature of molecular interactions in the liquid state, Nevertheless, except in the critical region, liquid diffusion coefficients can at present be predicted by empirical correlations with sufficient accuracy for many engineering purposes(9, 13, 14). In the critical or dense fluid state, there are few experimental studies of diffusion coefficients in binary mixtures. This has made it difficult to assess predictive techniques, which have so far been tested largely on the basis of self-diffusion data and are generally considered unreliable(9, 10).
The present two-part paper describes Petroleum Recovery Institute work that was directed toward developing improved predictive methods for molecular diffusion coefficients in the high-pressure dense gas state which is commonly encountered under reservoir conditions. The first part presents previously unobtained data on binary diffusion coefficients for fluids in the dense gas state, and a general correlation for binary molecular diffusion coefficients at conditions ranging from ambient to those likely to exist in Alberta reservoirs. The second part presents a method for using the binary con-elation to estimate diffusion in multicomponent systems and shows how the effects of convection and diffusion can be combined to calculate concentration profiles for fluid mixtures flowing in porous media.
Two causes of poor recoverability are migration of stored gas far from the injection well and upward coning of water into withdrawal wells. The authors conducted laboratory and numerical simulation investigation of the use of aqueous foams to block the flow of gas or liquid to ameliorate these problems. Experiments in sandstone cores showed that foam reduces the permeability to gas and liquid by approximately three orders of magnitude. A numerical simulation study showed that water coning could be significantly delayed by placing a horizontal foam lens just above the gas-water interface. Also discussed are the conditions for forming foam in situ, the feasibility of emplacing a foam bank, and the durability of permeability reduction. Laboratory experiments and numerical simulation indicate potential for significantly improving the efficiency of aquifer gas storage with aqueous foams. A field trial of foam to prevent water coning is recommended.
The conversion of a depleted gas reservoir into underground storage is currently considered to substitute liquefied liquefied natural gas tanks. This study investigates the validity of the operation scenario of the storage with a compositional simulation model and analyzes potential compositional changes of the gas for the purpose of predicting and managing the gas quality in the future. According to the simulation results, the overall operation conforms to the design concepts and operation scenario, confirming the validity of the pre-storage operation scenario. Moreover, the compositional variation of gas in the reservoir was closely examined, clarifying the changes in each component.
This book presents concepts and applications of reservoir engineering principles needed for the development of natural gas reservoirs. A systems approach is used to explore how a change in any component of the field production system affects the performance of other components. Topics include: abnormally pressured gas reserves; gas well testing; and optimum gas field development strategies; estimation of gas reserves; gas condensate reservoirs; production decline curves; deliverability testing of gas wells; transient testing of gas wells; gas field development; and storage of natural gas.
The aim of this study is to supply the variable gas demand from an underground gas storage reservoir during heating season by an optimal selection of production rates. Because of the interaction of many influences, parameters, and previous decisions, determination of production rates becomes so involved that the manager can no longer use intuitive judgment. The objective, therefore, is to reach an optimum decision by applying the linear programming method in problem optimization. A candidate gas storage field in the Thrace Basin of Turkey is selected as a case study. The gas reservoir simulator developed provided the raw data for the formulation of a linear programming model. The solution process involves the use of superposition in time and space to develop the constraints for the optimization model. The constraints are based on the physical limitations of the system. Optimizing the production rates maximized the total amount of gas produced from the storage field and minimized the makeup gas according to the given constraints.
It is possible to predict the behavior of fluids in permeable and porous medium under different operating conditions by using reservoir models. Since geological data and reservoir properties can be defined most accurately by reservoir models, it has been accepted as a reliable prediction tool among reservoir engineers. In this study, a gas reservoir has been modeled with IMEX Module of CMG Reservoir Simulator. Rock properties, gas composition and certain production data were entered to the model as input data and the measured field data were matched with simulated ones. After the 5 year depletion of the reservoir by vertical wells, the average reservoir pressure dropped from an original reservoir pressure of 2150 psi to 1200 psi. This depleted reservoir was planned to be used for gas storage purposes. The remaining gas was used as cushion gas during the conversion of this reservoir to an underground gas storage field. Afterwards, horizontal wells were defined in the model and certain production/injection scenarios were simulated for the gas storage operation.
Natural gas storage is used to smooth the natural gas supply to meet high peak demand. In natural gas storage, the working gas (methane) is injected and produced seasonally while a cushion gas that is not extracted is used to provide pressure support. In the case of depleted gas reservoirs being used for gas storage, the cushion gas is commonly leftover native gas (methane). Another approach is to produce most of the methane from the reservoir since it can be sold for profit and inject a cheap inert gas for use as the cushion gas. Carbon dioxide injection during carbon sequestration with enhanced gas recovery can be carried out to produce the methane while simultaneously filling the reservoir with carbon dioxide. Carbon dioxide undergoes a large change in density near its critical pressure, an advantageous feature if used as a cushion gas. Furthermore, the injection of carbon dioxide into the ground may in the future be economically favorable through carbon credits or tax advantages offerred to encourage carbon sequestration. Reservoir simulations of methane injection into a model gas storage reservoir with carbon dioxide as cushion gas demonstrate that 30% more methane can be stored relative to a native gas cushion. Along with economic considerations of carbon dioxide and natural gas prices, the critical issue for the use of carbon dioxide as a cushion gas is limiting the rate of mixing between methane and carbon dioxide through careful reservoir selection and operations.
Preface 1. Models for diffusion Part I. Fundamentals of Diffusion: 2. Diffusion in dilute solutions 3. Diffusion in concentrated solutions 4. Dispersion Part II. Diffusion Coefficients: 5. Values of diffusion coefficients 6. Diffusion of interacting species 7. Multicomponent diffusion Part III. Mass Transfer: 8. Fundamentals of mass transfer 9. Theories of mass transfer 10. Absorption 11. Absorption in biology and medicine 12. Differential distillation 13. Staged distillation 14. Extraction 15. Absorption Part IV. Diffusion Coupled with other Processes: 16. General questions and heterogeneous chemical reactions 17. Homogeneous chemical reactions 18. Membranes 19. Controlled release and related phenomena 20. Heat transfer 21. Simultaneous heat and mass transfer Problems Subject index Materials index.
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