Simulation of Underground Gas Storage Feasibility in a Depleted Gas Reservoir

Transcription

1 Simulation of Underground Gas Storage Feasibility in a Depleted Gas Reservoir Authors: Hamidreza Kakhsaz 1, Abdolhamid Ansari 1 * 1 Islamic Azad University of Lamerd, Petroleum Engineering Department Abstract Underground storage of natural gas is an inevitable necessity because of increasing growth of household energy consumption, the high share of natural gas in the energy basket, high costs of development of production resources, and refining. Considering the growth of demand and variation of natural gas consumption as a massive and inexpensive energy carrier, also unbalanced supply and demand for natural gas in cold seasons, there is a need for natural gas storage for preventing lack of gas during peak gas consumption. In this way, extra gas is injected into the underground reservoir during storage in summer and taken from that reservoir in the cold seasons. The creation of underground reservoirs for storing natural gas is scheduled to be implemented by the gas storage company and the vulnerability of the transmission and distribution system will be prevented by storing surplus gas in summer for reprocing in winter. Keywords: Natural Gas Storage, Gas Distribution, Energy Saving, Storing Feasibility, Nitrogen Injection 2018 by the author(s). Distributed under a Creative Commons CC BY license.

2 Introduction Iran has the second largest gas reserves in the world. According to the latest statistics, the country's gas reserves are estimated at trillion cubic meters. In addition, the country's natural gas purification capacity is 360 million cubic meters, 70% of which is from South Pars and Kangan gas fields. However, due to the increasing use of natural gas as an abundant and cheap energy carrier, as well as the imbalance in natural gas supply and demand in cold seasons, there is a need for planning the use of strategic reserves in the country, as these strategic reserves play an important role in balancing supply and demand in different seasons, and they can have more impact on global markets. Also, strategic gas reserves play an important role in terms of timely performance of the international obligations of Iran s gas exports. The use of underground gas storage tanks is a commonly known method in the world to compensate for the shortage of gas in cold seasons. In this process, the surplus of natural gas in summer is injected into a porous underground environment with a suitable rock coating to meet high consumption requirements in cold and high consumption seasons. Active gas fields produce natural gas throughout all seasons, but its consumption varies in different seasons. In addition, there is a long distance between gas fields and the population centers and the consumer market. For this reason, the storage of natural gas, like other fossil fuels, has been considered. Therefore, in the summer, when natural gas consumption is lower, the produced gas is stored in reservoirs built for this purpose and it is reproduced in the cold season. The construction of surface tanks is not feasible due to their limited capacity and high cost of storing natural gas. In countries where natural gas forms a significant part of their energy consumption basket, there are many of these reservoirs in operation (Lord, 2012). Generally, gas is stored for the following purposes: - To create balance and uniformity in gas consumption and resources at all times (seasonal, daily and hourly) - To ensure the continuity of gas consumption, especially at the times when technical problems occur in relevant facilities - To guarantee the provision of gas to consumption centers, especially during the cold seasons and peak consumption hours - To reduce the amount of investment required to build new capacity in the gas supply system, which in the long run reduces the need for refining capacity and pipeline capacity. - To serve a strategic support in times of crisis (war, earthquake, etc.) - To fulfill the obligations of the country to export natural gas in accordance with the relevant contracts - To establish business and commercial facilities for the country - To provide the possibility of buying and storing cheap gas for domestic use - To provide the possibility of earning more income in the event of rising prices in the market by exporting the stored gas The first successful underground gas storage experience happened in Canada in 1915 through the change in the condition of several wells from an almost discharged gas field. Currently, there are about 120 operational reserve reservoirs in Europe, and about one-fifth of the US gas is supplied from natural gas reserves during the winter season (Lord, 2012). Along with the consumption of urban and rural gas, large energy industries make a big consumer market, which puts domestic consumption of natural gas at the top of the agenda. Among these industries, power plants, steel, cement, and glass industries form a part of natural gas consumers. Natural gas in the industrial sector is used in two ways: the supply of energy (fuels) or feedstock

3 for petrochemical plants or conversion industries. The use of natural gas as a fuel is due to the constant need for electricity in some industries, such as aluminum, which are themselves generating electricity, as well as for water treatment, preheating of metals, especially in the iron and steel industry, reducing moisture, drying, melting glass, food production, and fuel for industrial boilers. Natural gas as well as all its compounds such as methane, ethane, propane and butane, which are separated from natural gas, are used as feedstock for the production of petrochemicals, as well as for synthesis gas, a mixture of hydrogen and carbon monoxide, in the industrial sector for the production of methanol and other chemicals derived from it. South Pars gas field is the world's largest gas field located in the Persian Gulf in the territorial waters of Iran and Qatar. The area of the field is 9700 square kilometers, with 3700 square kilometers in Iran's territorial waters and 6,000 square kilometers in Qatar's territorial waters. The volume of exploitable gas along with gas condensate is equivalent to 230 billion barrels of crude oil. The Iranian storage area is 14 trillion cubic meters in site, 10 trillion cubic meters of exploitable gas, and 17 billion barrels of gas condensate (9 billion exploitable barrels), which accounts for 50 percent of Iran's gas reserves and 8 percent of global gas reserves. Iran's natural gas storage plan has been regulated in order to prevent the pressure drop in gas pipes and to ensure the continuous flow of gas supply, especially at the peak of consumption in the cold months of the year and increase the load factor. In general, considering the amount of natural gas produced and consumed in Iran, and the significant difference between winter and summer consumption due to climatic conditions and the significant difference in air temperature in cold and hot seasons, natural gas storage with a final capacity of at least 10 billion cubic meters per year is needed. The purpose of this article is to perform a feasibility study of storing natural gas in discharged reservoirs of Nar and Kangan. There is a need to store natural gas in order to avoid gas shortages at times of peak gas consumption. In this way, extra gas is injected into underground reservoirs during the summer and is withdrawn in cold seasons from the reservoir. The main objective of gas storage is to balance supply and demand during the specified period. The storage of surplus gas for winter withdrawal would prevent the vulnerability of the gas transmission and distribution system. Storage in discharged hydrocarbon reservoirs is the most important and most common type of underground storage. The use of such reservoirs is important from the economic point of view as it allows the reuse of the exploitation infrastructure and the remaining distribution network from the production stage of the primary hydrocarbon and reduces the cost of their construction and installation. Also, due to the availability of information and geological, geophysical and reservoir characteristics of this type of reservoirs produced during the exploitation period, the study of the feasibility of gas storage and the amounts of gas that can be stored and withdrawn from them has a lower risk. Therefore, the use of discharged reservoirs is generally the cheapest and most cost-effective way to development, maintenance, and exploitation purposes compared to other underground gas storage methods. There are two important factors in the selection and reuse of discharged hydrocarbon reservoirs: - Geographic proximity to the gravity centers of consumption and infrastructure of the gas transmission network - High permeability and porosity of the porous reservoir rock in the formation is one of the factors that determine the amount of natural gas that can be stored in the reservoir. Permeability also determines the velocity of the flow of natural gas inside the formation and ultimately determines the rate of injection and discharge of natural gas.

4 The first step in constructing a natural gas storage reservoir is to find a reservoir with suitable profiles (Agate, 2017). The requirements for constructing a suitable storage tank are as follows: Sufficient continuity and closure of the rock coating, sufficient reservoir capacity, and acceptable permeability and deliverability (Warren, 2006). There are three types of gas in the gas storage reservoir (Yort-E-Shah, 2007): - Base or cushion gas that remains in the reservoir when the reservoir reaches the base pressure. Base pressure is the pressure in which production is stopped and the injection begins. - Working gas which is injected into the reservoir during the circulation process and is extracted from it. - Unused gas, which is defined as the unused reservoir capacity. Base pressure and also base gas are defined based on the need for gas delivery. On the other hand, it is necessary to maintain sufficient pressure in the reservoir to allow the reservoir to deliver gas to the transmission lines. Base gas is an important component of storage operations because it always stays inside the reservoir and maintains reservoir pressure throughout the production cycle. When a production reservoir is abandoned, some gas, oil, and water remain in it. The remaining natural gas can be used as a base gas. The base gas can be part of its gas reservoir or can be injected from the outside into the reservoir. In reservoirs requiring basic gas injection, gas supply and injection involve the largest cost of storage operations. Therefore, it is preferable to use a cheap gas such as nitrogen or carbon dioxide as a base gas. The base gas will always remain in the reservoir and cannot be removed during storage operations. The first study on the use of inert gas as the base gas was conducted in France in 1978 on an aquifer reservoir. The first natural gas storage project was implemented in Poland in 2008 in a low-quality storage reservoir (containing 30% nitrogen) called Vrieskoice (Wang, 2009). In 2010, a study was conducted to replace part of base gas with nitrogen on one of the gas reservoirs in Turkey, and the problem of mixing nitrogen gas and working gas was studied (Wieslaw, 2012). Important parameters for storage of underground gas The most important parameters in the field of gas storage are reservoir depth, reservoir geometry (diameter, height, and shape), reservoir distance from each other, formation distance to reservoir, and pressure inside the reservoir. The reservoir should be relatively close to the market and also be close to the transmission infrastructures (transmission lines and distribution systems), since it can connect them to the market. Parameters affecting the performance of gas storage reservoirs Parameters affecting the performance of gas storage reservoirs can be divided into three categories (Azin et al., 2008). - Reservoir parameters such as reservoir size, slope and thickness of storage area - Parameters related to rock properties such as permeability, porosity, and compressibility - Parameters related to fluid properties such as relative permeability and capillary pressure - The location of the wells - Injection/recovery plan Arastupour and Chen studied the effect of absolute permeability, porosity, and capillary pressure on gas production from a well. They showed that the rate of production and in particular the rate of gas production is both sensitive to both absolute permeability and relative permeability. Keshkare and Wicks (1992) study also confirmed this result. Vang s studies have shown that permeability is the most important parameter in the amount of gas recovery, while slope, porosity,

5 and thickness of the formation are of the secondary performance. A study by Gafen et al. showed that the amount of residual gas saturation depends on factors such as injection rate, static pressure, temperature, fluid saturation before injection, and the properties of the porosity network and the initial amount of gas in situ. Determination of residual gas saturation requires especial core analysis tests. Method In this study, reservoir conditions were simulated with the use of the Eclipse software. In order to study and model a reservoir, a general view of the reservoir must be obtained first. This review includes the geological situation of the area, the study of reservoir layering, and information of this type known as static model. The static model is a 3D geological view of the reservoir. The output of the static model serves as the input to construct a dynamic model. Therefore, the more static the model, a more quality dynamic the model will be achieved, and the more reliable the study will be. To construct a static model, Petrel software was used in this study. In this study, 32 blocks in X direction, 24 blocks in Y direction and 7 blocks in Z direction were used. The average dimensions of each block were feet in X, Y, and Z directions, respectively. The static model along with the petrophysical characteristics of the reservoir (e.g., porosity, permeability) and fluid flow properties (relative permeability, water saturation, capillary pressure, etc.) were entered into the eclipse simulation software. The PVC fluid model of the reservoir was also submitted to the software. The reservoir model was considered homogeneous and the porosity and permeability of the reservoir were 2% and 0.05 mbar, respectively. All studies were done on a single-well model. During the storage operation, this well was used alternately for injection and production, and the quality of the gas produced in the production cycles was checked. To increase the accuracy of the results, the blocks around the well were as small as possible. After placing the LGR around the well, the average dimensions of each block were feet in X, Y, and Z directions, respectively. Due to the difference in the composition of the injection gas and the reservoir gas, simulation of the gas storage process was carried out with a compositional (E-300) model. Table 1 shows composition of reservoir and injection gas. The density of the injected was is calculated to be pounds per cubic foot and the density of the reservoir gas was 14.7 pounds per cubic foot. Besides, Peng-Rabinson-3 Parameter Equation was used for predicting the behavior of the reservoir gas and the injected gas. The reservoir temperature was 263 F and reservoir pressure at a depth of 16,726 ft was reported to be about 4,700 psi, so the gas reservoir was in the supercritical state. Underground gas storage (UGS) is a well-known method to overcome the supply and demand imbalance problem in the cold seasons of the year. In reservoirs used to store gas, the presence of bas gas is essential to maintain reservoir pressure during the production cycle, as well as to ensure adequate deliverability. Base gas injection covers the maximum cost of storage operations. Therefore, the use of an inexpensive and inert gas, such as nitrogen or carbon dioxide as part of the base gas, dramatically reduces the cost of storage operations. Several factors affect the mixing of the base and working gas. The mixing process of the base and working gas occurs in various dimensions, where molecular penetration can be one of the factors affecting the mixing rate. In this study, the effect of two parameters of initial injection time and molecular diffusion on the mixing rate and thus the quality of the produced gas was investigated. One of the parameters affecting the process of natural gas storage is the mixing of the base gas and the working gas in the reservoir. Base gas is a key component of the storage operation. This gas will always remain in the reservoir to maintain reservoir pressure throughout the production cycle and allow the production of gas with adequate deliverability throughout the withdrawal season.

6 The base gas can be part of the reservoir gas or can be injected from the outside into the reservoir (Stopa, 2012 Hopper and Foutch, 2007) Considering that the greatest cost of storage operations relates to the supply and injection of base gas, the use of a cheap and inert gas such as nitrogen as the base gas can dramatically reduce the cost of the storage operation. The inert gas used as the base gas should not reduce the quality of the gas produced (Wallbrecht, 2006). Therefore, the key point is to control the degree of mixing of natural gas and the reservoir gas (Ozturk, 2004). In this study, the feasibility of using a nitrogen gas reservoir for storage of natural gas was investigated. The only potential problem is the mixing of natural gas and low-quality reservoir gas, which must be effectively controlled. Since the objective of natural gas storage is the production of high-quality gas during consecutive production cycles in the cold seasons, the optimization of storage operation is carried out in such a way that the quality of the produced gas during the successive production cycles is acceptable. To this end, this study explored the amount of injected and produced gases at the molecular scale. Since the fluid analysis showed a major part of the gas reservoir is made up of nitrogen, it can be used as the base gas. In the case of storage in this reservoir, the low-quality gas (which is cheap and has low methane content) acts as a cushion gas, which, while maintaining the reservoir pressure, boosts economic efficiency. On the other hand, the emergence of a series of undesired phenomena during underground gas storage in such reservoirs such as the mixing of the reservoir gas (which has a poor quality and high nitrogen content) with injected gas (which has good quality and high methane content) reduces the quality of the gas produced from the reservoir. For the produced gas to have a higher thermal value, the nitrogen content should be reduced to as low as possible until it reaches below 10%. The major part of the reservoir gas is nitrogen and a major part of the injected gas is methane. Given that the injected gas also contains 3.5% nitrogen, the amount of nitrogen in the produced gas may at best be at least 3.5%, and this will not decrease further. The rate of methane penetration in nitrogen is m 2 /s. Results and Discussion Simulation results shows that decrease in injection rate results in higher production rate (Fig. 1). Injection rate also affects nitrogen molar fraction in produced gas. As shown in Fig. 2, if the injection rate increases, the nitrogen mole fraction in the fluid produced from the well in the production cycles decreases. Besides, if the injection rate is 0.6 million cubic meters, the amount of nitrogen molar fraction in the initial production cycle will reach 5%, and this increase in nitrogen content in subsequent cycles will increase with a steeper slope. However, if the rate of injection increases, the amount of nitrogen molar fraction is lower and increases during the production phase with a less slope. Figure 3 shows the amount of methane molar fraction in the fluid produced in different initial injection rates. As it can be seen, the amount of methane molar fraction in the fluid produced during the production cycle decreases, and as long as the initial injection rate increases, methane production decreases less. Simulation results show that the amount of nitrogen molar fraction in the produced fluid is changed based on the production rate. As it can be seen in Fig. 4, the higher the production rate increases, the nitrogen molar fraction in the produced fluid will increase with a steeper slope, but after increasing the production rate to 1 million cubic meters, increasing the production flow does not affect the production of nitrogen in the produced fluid. The amount of methane molar fraction in

7 the produced fluid is also of great importance. This can be seen in Fig. 5. As it is shown in the figure, the methane molar fraction in the produced fluid in each of the production cycles is not dependent on the production rate of the well. Nonetheless in each cycle, the amount of methane molar fraction decreases slightly with the passage of time from the moment of starting production. In order to investigate more precisely the process of mixing the injected and reservoir gases, one of these zones was selected as representative of the properties of the reservoir studied and various parameters that affect the mixing process were investigated in this zone. DK-B4 zone was studied in terms of the mixing process. The thickness of this zone is 200 feet with water saturation of 43%, porosity of 3%, and permeability of 0.48 ma. The total volume of gas in the initial site in the DK-B4 zone is cubic feet. Due to the large size of the field and high percentage of nitrogen gas, the implementation of the reservoir discharge operation to start the storage cycle did not have a good efficiency. By implementing several scenarios, it was found that the storage capacity of the reservoir would not increase substantially even after 30 years of discharge.. Therefore, the storage operation began with a predetermined time of initial injection to form a region with a high percentage of methane content around the well, producing natural gas from the same area during the cold season when the production cycle starts. Due to the low permeability of the reservoir, natural gas remained in the space around the well after injection and did not spread to other areas of the field. One of the important parameters affecting the quality of the produced gas is the duration of the initial injection. Subsequent scenarios have been investigated and the nitrogen gas produced at the end of the six-month production cycle with the highest nitrogen content was estimated. - First scenario: Six months injection + six months production - Second scenario: One year injection + six months production - Third scenario: Two years injection + six months production - Fourth scenario: Three years injection + six months production - Fifth scenario: Four years injection + six months production - Sixth Scenario: Five years injection + six months production The optimum flow rate and optimal injection rate for each scenario were calculated, and the percentage of methane and nitrogen produced at the end of the sixth month was estimated. The optimum discharge means the maximum flow rate may be constant over a given injection or production period, and the pressure at the bottom of the well reaches the desired value. The optimal injection rate is set in a way that the rock push pressure reaches up to 8000 psi (the rock push is considered to be the highest layer of formation). The production flow rate is determined in such a way that the pressure at bottom of the well reaches 2000 psi. By increasing the duration of the initial injection, the optimum injection rate decreases and the optimum discharge rate increases. The percentage of nitrogen and methane produced at the end of the sixth month was calculated for each scenario. If the initial injection duration is six months, the production of nitrogen at the end of the sixth month of the production cycle would reach about 28%, which would reduce the quality of the gas produced. If the initial injection time is one year, the amount of nitrogen produced is up to 13%, which is still not sufficient. By increasing the initial injection time to two years, the percentage of nitrogen produced would be about 5%, which is an acceptable value. Therefore, the minimum initial injection time is 2 years. Increasing the initial injection time to 3, 4, and 5 years improves the quality of the produced gas, but does not significantly affect the quality of gas compared to 2 years of initial injection and only reduces the amount of nitrogen produced by 1.5%.

8 In order to investigate this phenomenon, the scenario for 2 years of injection and six months of production was selected. The produced flow rate was considered constant and injected flow was changed. By changing the injection rate, the amount of nitrogen and methane produced at the end of the production cycle was measured. As the injection rate increases, the quality of the produced gas increases and for the produced nitrogen be less than 10%, the injection rate should be greater than 160 Mm 3 /d, and the total injection volume should be greater than 1160 MMm 3.The injection rate was considered constant and the production pressure was changed. By changing the production rate, the amount of nitrogen and methane produced at the end of the production cycle was measured. The results show that with increasing the production rate, the mixing rate of natural gas and nitrogen increases, but this has no significant effect on nitrogen increase. Therefore, concerning the control of the mixing process, there is no limitation to increase the production rate. Since the reservoir fluid is a gas and the injection and production rates are high, the non-darcy effect should also be taken into account. Considering the non-darcy factor, the injection rate and optimal production flow rate are reduced, and since reducing the injection rate has a greater effect on the mixing process, the percentage of nitrogen produced at the end of the production cycle would increase. The percentage of methane and nitrogen produced at the end of the sixth month of production cycle is shown by taking into account the D-factor. As our results indicate, the optimal injection time to achieve the acceptable quality of the produced gas (with less than 10% nitrogen content) is 2 years. A comparison of the mixing rates for each scenario when the D-factor is taken and not taken into account is shown in Figure 6. According to the results, the Non-Darcy effect results in a 20% increase in nitrogen production. Considering the Non-darcy effect reduces the optimal injection rate by 30%, as shown in Figure 7. According to this figure, the optimum injection rate when the D-factor is taken for different scenarios is less than that for the condition where the D-factor effect is not taken into account. Conclusion The following conclusions are drawn based on the findings of this study: - If the injection rate increases, the nitrogen molar fraction in the produced fluid from the well in production cycles decreases and increases during the production with a slighter slope. - The methane molar fraction in the produced fluid during the production cycle decreases, and whatever the amount of initial injection rate is increased, the methane content reduce less frequently. - The nitrogen molar fraction in the produced fluid changes according to the production flow. The higher the production rate, the nitrogen molar fraction in the produced fluid will increase with a steeper slope, but after increasing the production flow to one million cubic meters, increasing the production flow does not affect the production of nitrogen in the produced fluid. - If the initial injection duration is six months, the production of nitrogen at the end of the sixth month of the production cycle would reach about 28%, which would reduce the quality of the gas produced. If the initial injection time is one year, the amount of nitrogen produced is up to 13%, which is still not sufficient. By increasing the initial injection time to two years, the percentage of nitrogen produced would be about 5%, which is an acceptable value. Therefore, the minimum initial injection time is 2 years.

9 - As the production rate increases, the mixing rate of natural gas and nitrogen increases, but this has no significant effect on nitrogen increase. Therefore, concerning the control of the mixing process, there is no limitation to increase the production rate. - Considering the non-darcy factor, the injection rate and optimal production flow rate are reduced, and since reducing the injection rate has a greater effect on the mixing process, the percentage of nitrogen produced at the end of the production cycle would increase. - The optimum injection rate when the D-factor is taken for different scenarios is less than that for the condition where the D-factor effect is not taken into account. Refrences [1] Anna S. Lord, Overview of Geologic Storage of Natural Gas with an Emphasis on Assessing the Feasibility of Storing Hydrogen, Prepared by Sandia National Laboratories, California. [2] BSI 1998a. BS EN : Gas supply systems underground gas storage Part 2: Functional recommendations for storage in oil and gas fields. British Standards Institution, London, 11 pp. [3] An appraisal of underground gas storage technologies and incidents, for the development of risk assessment methodology, prepared by the British Geological Survey for the Health and Safety Executive [4] EIA,Underground Natural Gas Storage Developments: 1998:2005. Energy information Administration, Office of Oil and Gas, October 2006, 16pp. [5] Mario Jorge, Estimating the required underground natural gas storage capacity in Brazil from the gas industry characteristics of countries with gas storage facilities, natural gas science and engineering, [6] M. Ayatollahi, Underground Natural Gas Storage in a Low Quality Gas Reservoir - Produced Gas Quality Control by Rate Optimization, [7] E. Priolo, Underground Natural Gas Storage in a Low Quality Gas Reservoir - Produced Gas Quality Control by Rate Optimization, [8] G.A. Knepper, J. F.Guthbert, Gas Storage Problems and Detection Methods, SPE 8412, presented at the 54th annual fall technical conference & exhibition, Las Vegas, Nevada, Sep. 2326, [9] Ehsan Khamehchi, Seyed Hamidreza Yousefi and Alireza Sanaei, Selection of the Best Efficient Method for Natural Gas Storage at High Capacities Using TOPSIS Method, Gas Processing Journal, 2013, Vol. 1 No. 1, PP [10] Geluk M.C., Paar W.A., Fokker P.A., Salt, Royal Netherlands Academy of Arts and Sciences, 2007: [11] M. R. Tek, Natural gas Underground Storage, Inventory and Deliverability, Pennwell Books, [12] Warren John K., Evaporates: Sediments, Resources and Hydrocarbons, Chapter 12: Solution mining and cavern use, 2006, Brunei. [13] G. Agate, A Numerical Modeling Approach To Investigate the Safety Aspects of the Gas Storage in a Deep Geological Reservoir, 2017.

10 [14] Drew R Michanowicz, A national assessment of underground natural gas storage: identifying wells with designs likely vulnerable to a single-point-of-failure, [15] Yort-E-Shah Underground Gas Storage Project, Oil and Energy Industries Development Company (OEID), [16] Xiuli Wang., XGas., Advanced natural gas engineering, University of Houston, copyright at 2009 Gulf Publishing Company. [17] H. De.Moegen, H. Giouse, H.,(1989). Long-Term Study of Cushion Gas Replacement by Inert Gas, SPE Annual Technical Conference and Exhibition, San Antonio, Texas. [18] Stephen E.Foh. (1991). Use of inert gas as cushion gas in underground storage: practical and economic issues, Institute of gas technology. Chicago. Illinoise [19] Labaune, F., Knudsen, J.E. (1987). Inert gas in Tonder aquifer storage: A complete preliminary computer study, SPE Annual Technical Conference and Exhibition, Dallas, Texas. [20] Szott Wieslaw, (2012). Simulation studies of gas-gas mixing processes in Wierzchowice underground gas storage reservoir Poland. [21] Kilincer Nilufer., Gumrah Fevzi. (2010). A numerical simulation on mixing of inert cushion gas with working gas in an underground gas storage reservoir [22] Stopa, J., Rychlicki S. (2012). Technical and Economic Performance of the Underground Gas Storage in Low Quality Gas Reservoirs. [23] Hopper J. M., Foutch J. H. (2007). The Role of Gas Storage in the Energy Value Chain. Jefferies & Co Presentation. [24] Ozturk B. (2004). Simulation of Depleted Gas Reservoir for Underground Natural Gas Storage, MSc thesis, Middle East technical university. [25] Wallbrecht, J. (2006). Storage Study , Trends in the UGS Business. presented at 23rd World Gas Conference.

11 Nitrogen Mole Fraction Filed Gas Production Rate (MMscm/day) Preprints ( NOT PEER-REVIEWED Posted: 25 May 2018 Figures and Tables: Time, Years Qinj = 0.6 MMscm/day Qinj = 1.2 MMscm/day Qinj = 0.8 MMscm/day Qinj = 1.4 MMscm/day Qinj = 1.0 MMscm/day Figure 1 Production rate vs. time Time, Years Qinj = 1.4 MMscm/day Qinj = 1.0 MMscm/day Qinj = 0.6 MMscm/day Qinj = 1.2 MMscm/day Qinj = 0.8 MMscm/day Figure 2 - Variations in nitrogen molar fraction for different initial injection rates

12 Nitrogen Mole Fraction Methane Mole Fraction Preprints ( NOT PEER-REVIEWED Posted: 25 May Time, Years Qinj = 1.4 MMscm/day Qinj = 1.0 MMscm/day Qinj = 0.6 MMscm/day Qinj = 1.2 MMscm/day Qinj = 0.8 MMscm/day Figure 3 - Methane molecule fraction in the fluid produced in different initial injection rates Time, Years Qprod = 0.4 MMscm/day Qprod = 1.0 MMscm/day Qprod = 0.6 MMscm/day Qprod = 1.2 MMscm/day Qprod = 0.8 MMscm/day Figure 4 - Nitrogen molar fraction of the fluid for different discharge rates

13 N2 mol fraction Methane Mole Fraction Preprints ( NOT PEER-REVIEWED Posted: 25 May Time, Years Qprod = 0.4 MMscm/day Qprod = 1.0 MMscm/day Qprod = 0.6 MMscm/day Qprod = 1.2 MMscm/day Qprod = 0.8 MMscm/day Figure 5 - Methane molar fraction in the fluid for different discharge rates with D-factor without D-factor 0 6 mnth inj 1 yr 2yr 3 yr 4 yr 5 yr Initial injection period Figure 6 - Nitrogen produced for each scenario with the D-factor taken and not taken into account

14 well gas inj rate, sm3/d Preprints ( NOT PEER-REVIEWED Posted: 25 May mnth 1 yr 2 yr 3 yr 4 yr 5 yr without D-factor with D-factor Figure 7 - The optimum injection rate for each scenario with and without considering D-factor Composition Reservoir Gas Injection Gas CO 2 1% 9% N % 3.6% C % 87% C % C % IC % C % + C 5 0 Trace Table 1 - Reservoir and injection gas composition