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Gas-water-rock interactions and factors affecting gas storage capacity during natural gas storage in a low permeability aquifer
PETROLEUM EXPLORATION AND DEVELOPMENT Volume 45, Issue 6, December 2018 Online English edition of the Chinese language journal Cite this article as: PETROL. EXPLOR. DEVELOP., 2018, 45(6): 1123–1128.
RESEARCH PAPER
Gas-water-rock interactions and factors affecting gas storage capacity during natural gas storage in a low permeability aquifer TOOSEH Esmaeel Kazemi1, JAFARI Arezou1,*, TEYMOURI Ali2 1. Petroleum Engineering Department, Chemical Engineering Faculty, Tarbiat Modares University, Tehran, Iran; 2. National Iranian Gas Company, Tehran, Iran
Abstract: Gas-water-rock interactions during natural gas storage in a low permeability aquifer and main factors affecting the storage capacity were investigated in laboratory with core experiments. The results showed that gas injection flow rate had a major impact on stored gas volume and stored gas volume is higher at high flow rate. Gas storage volume ranged between 6%20% of the pore space at experimental condition. Enhancing injection pressure can enhance gas storage volume. Statistics showed that injection flow rate had a greater influence on the gas storage volume than pressure. The retention time also had an impact on the gas storage process. Most of the natural gas was trapped in the reservoir and could not be produced after long time of retention. Atomic absorption spectroscopy indicated that ions concentrations of the brine and water evaporation increased when gas was injected into brine saturated core, and precipitation might occur, reducing porosity and permeability of core. Gas chromatography analysis showed that the concentration of carbon dioxide in the natural gas decreased and the concentration of methane increased after storage in the core. Key words: underground gas storage; natural gas; gas storage volume; aquifer; gas injection rate; gas injection pressure
Introduction Underground gas storage is an important way to store natural gas[1]. Depleted oil and gas reservoirs, aquifers and salt domes are the main types of reservoirs used for underground gas storage[2, 3]. Natural gas storage in saline aquifers is complicated and challenging[4], all aspects of the process should be considered[5]. Parameters affecting the process include flow characteristics of fluid in porous media, gas and water phase behavior, and reservoir conditions throughout the process[6], but they have not been studied thoroughly[7]. Among them, salinity of formation water and temperature of the aquifer may not vary during natural gas storage[8], but gas injection pressure and flow rate are controllable and need further investigation. Sohrabi et al.[9] investigated multiphase flow behavior and gaseous phase sweeping efficiency by injecting methane and water alternately. Pini et al.[10] studied heterogeneity effect on CO2 injection process by performing experiments on high and low permeability cores. They found that gas saturation was high at core entry and reduced through the core length, and gas saturation was much higher at high flow rate in both of the cores. Lorenz and Muller[11] tested nitrogen injection at temperatures below 100 °C. They found that salt precipitation
due to gas injection occurred near wells, also retention time and pressure loss during production resulted in more precipitation. Golghanddashti et al.[12] investigated salt precipitation by injecting natural gas into core plug at atmospheric pressure. The results showed that natural gas injection flow rate didn’t affect salt precipitation whereas thermodynamic condition was the main factor affecting the amount of salt precipitation. Torabi and Asghari[13] studied the effect of pressure on immiscible CO2 displacement of oil in porous media by conducting core flood experiment. Oh et al.[14] studied CO2-alternate-water displacement by simulation and experiment. They observed that by enhancing the injection rate, gas saturation at the inlet of the core increased. Peysson et al.[15] injected CO2 into brine saturated core and found gas flow rate had a strong impact on salt precipitation. Sadirli[8] studied natural gas storage in aquifer through numerical simulation. Obviously, natural gas storage in a low permeability saline aquifer has not been studied through core scale experiments. In this work, core flooding experiment is carried out on a real aquifer limestone core. The aquifer is a gas storage reservoir candidate and located in the center of Iran. The interaction between gas, water and rock in the low permeability aquifer is
Received date: 12 Feb. 2018; Revised date: 26 Aug. 2018. * Corresponding author. E-mail: [email protected] Copyright © 2018, Research Institute of Petroleum Exploration & Development, PetroChina. Publishing Services provided by Elsevier B.V. on behalf of KeAi Communications Co., Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).
TOOSEH Esmaeel Kazemi et al. / Petroleum Exploration and Development, 2018, 45(6): 1123–1128
tested to find out the effects of gas injection rate, pressure and retention time on gas storage capacity.
1. 1.1.
Materials and methods Rock sample
At first, 5 limestone cores were gathered from this aquifer. The core was taken from the depth of 1 041.15 m. The aquifer mainly consists of limestone and dolomite with micro-fractures in some sections. The core with the highest permeability and porosity was used in the experiments. The core is 7.62 cm long, 3.81 cm in diameter, 8.32% in porosity, 0.02×10−3 μm2 in permeability, and 7.22 cm3 in pore volume. 1.2.
Fluid properties
Synthetic brine used in the experiments was made of various salts according to brine analysis of the aquifer. From measurement, the brine has a density of 1.095 g/cm3 and viscosity of 0.75 mPaꞏs at the experiment temperature (46 °C). The concentrations of Ca2+, Na+, Mg2+, K+, Cl− and SO42− in the brine were 45.240, 30.270, 1.580, 0.641, 130.820 and 0.400 g/L, respectively, and the TDS (total dissolved solids) was 208.41 g/L. As the salinity of aquifer increases, the possibility of salt precipitation increases, which in turn could lower the gas storage capacity of the reservoir. In our experiments, core sample was washed after every experiment and the same brine was injected into the rock sample in each experiment. The natural gas used was taken from domestic gas pipe line. In order to gather sufficient amount of gas for the experiments, the natural gas needed to be stored and pressurized in a vessel. As domestic gas has a pressure of about 0.1 MPa, it was pressurized in several steps before storage. At first it passed through compressor and pressurized to 0.35 MPa, and the process was repeated for several times to till the pressure reached 8.0 MPa. The designed setup for gas pressurizing is shown in Fig. 1. Gas phase components were measured by gas chromatography (GC) and TCD detector. The results showed methane makes up about 98.98% of the gas and CO2 about 1.02%. 1.3.
Experimental setup
The core flooding setup is shown in Fig. 2. It consists of two transfer vessels, one for brine and the other for gas, a positive displacement pump displaces the fluids in the transfer vessels. The pump operates at a maximum pressure of 35 MPa
Fig. 1.
Schematic of gas pressurizing setup.
Fig. 2.
Schematic of experimental setup for gas storage process.
and flow rate range between 0.01–30.00 cm3/min. The accuracy of the pump is very important in this process, so it was measured before tests. The core plug was placed inside a stainless steel core holder which can hold cores up to 12 cm long and 3.81 cm in diameter. A back pressure regulator was used to maintain outlet pressure. Two transducers were placed at both ends of the core to measure pressure accurately at core faces. A separator was connected to the outlet line to separate produced liquid and gas. A hydraulic pump was used for applying overburden pressure. 1.4.
Experimental procedure
The experimental procedure is: (1) Rock sample was washed by injecting two pore volumes of methanol then, the core was dried inside the oven at 90 °C for 12 hours and weighed. (2) The dry core was wrapped inside aluminum foil and put in a rubber sleeve then placed inside the core holder and heated to 46 °C. In the course, the gas permeability was measured at 0.09×10−3 μm2. (3) The core plug was vacuumed before saturated by brine. Two pore volumes of the prepared synthetic brine were injected at low rate. (4) The core permeability was measured and core plug was removed and weighted. Then it was put into the core holder for gas injection. (5) The core was pressurized to the desired pressure and natural gas was injected at a constant flow rate till there was no brine produced any more. (6) The core was weighed after the test, and the stored natural gas was calculated with core weight difference before and after the experiment. The experimental design was based on central composite design (CCD), which is a perfect type of response surface methodology (RSM). In this method, the simultaneous effects of parameters on the process and each other can be investigated by fewer experiments compared with traditional methods. CCD introduces optimum condition in to the operational framework[16]. Even highly coupled processes can be investigated through experimental design[17]. In this study, injection flow rate and pressure were selected and their upper and lower limits were introduced to CCD. These limits are based on the real aquifer operational condition. The flow rate was set between 0.01 and 0.09 cm3/min and pressure was held between 8 and 16 MPa. For each parameter, five values were taken, and 12 experiments in total were carried out. Four experiments were done at the center point (that is, gas injection flow rate of 0.05 cm3/min and pressure of 12 MPa) to lower the errors.
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2.
Results and discussion
The results of 12 experiments are presented in in Table 1. The actual operation of gas storage shows retention time can affect the gas storage process. Therefore, the effect of time on gas storage process was studied by two experiments, one of 1 day and the other 5 days long. These experiments had nearly the same results, so the rest of experiments were all done in 1 day. Fig. 3 shows cross sections of the middle part of the core plug extracted from CT scan analysis. Table 2 shows the results of the 1-day and 5-day long experiments. From Fig. 3 and Table 2, there are few differences between two experiments, so the gas storage time is designed by 1 day in 12 experiments in Table 1. 2.1.
Fig. 4. Stored gas volume vs. flow rate at the pressure of 12 MPa.
Effect of injection rate
The effect of injection rate on storage is shown in Fig. 4. It can be seen from the figure that when the injection rate is low, the gas storage capacity decreases with the rise of injection rate, but when the injection rate is high, the gas storage capacity increases with the rise of injection rate. It is expected to Table 1.
Results of experiments.
Experiment Q/ No. (cm3ꞏmin−1) 1 2 3 4 5 6 7 8 9 10 11 12
0.03 0.07 0.03 0.07 0.01 0.09 0.05 0.05 0.05 0.05 0.05 0.05
P/ MPa 10 10 14 14 12 12 8 16 12 12 12 12
Percentage of gas Storage 3 storage volume to volume/cm pore volume/% 1.125 15.58 1.152 15.94 1.367 18.94 1.502 20.79 0.838 11.6 1.261 17.47 0.417 5.78 0.913 12.64 0.470 6.51 0.507 7.02 0.500 6.92 0.552 7.64
Fig. 5. Relationship between stored gas volume and pressure at gas injection rate of 0.05 cm3/min.
have an ascending trend at even higher flow rate, but the applicability of different types of rock to high flow rate should be considered[18]. The process of gas injection in this core was under capillary control. The calculated values of capillary number (Nc) for these experiments were around 1010-1011, therefore, capillary pressure is the major force driving flow of natural gas-water. Also Reynolds number of the experiments ranged from 0.049 to 0.117, indicating there were Darcy flow in all the experiments. 2.2.
Fig. 3. CT scan cross sections of middle part of the core (a) 1 day, (b) 5 days. Table 2.
Results of 1-day and 5-day long experiments.
Retention Q/ time/d (cm3ꞏmin−1) 1 0.05 5 0.05
P/ MPa 16 16
Stored gas/cm3 0.913 0.987
Recovered gas/cm3 0.867 0.926
Effect of pressure
Pressure plays a major role in behaviors of multi-phase systems flow including gas[13]. Here, gas and water act as immiscible phase displacement. Increase of pressure would make the gas density and viscosity rise, so the displacing phase performance would improve. Fig. 5 shows that gas storage capacity increases significantly with the rise of pressure. As shown in the figure, by increasing pressure from 8 to 16 MPa, gas saturation in the core goes up from 5.78% to 12.64%. 2.3.
Statistical analysis
Statistical approach was adopted to figure out the effects of gas injection rate and pressure on gas storage capacity and their interaction. It should be noted that experiment no.5 was ignored in the statistics because the p-value of the model was not acceptable. A cubic model for gas storage percentage (S) 1125
TOOSEH Esmaeel Kazemi et al. / Petroleum Exploration and Development, 2018, 45(6): 1123–1128
was obtained through analysis of variance (ANOVA) (see equation (1)). This analysis predicted model results by 95% confidence and implied p-values < 0.05 as significant terms[19]. The model R2 (complex correlation coefficient) is 0.998, confirming the model is reliable. The other statistical index is F value. F value represents the importance of a parameter[20]. Table 3 shows ANOVA of the model. It can be seen from the table P-value of this model is 0.000 5, which confirms the model significance with 95% confidence. Injection rate and pressure are two important parameters, which have P-values of less than 0.05 (0.000 1 and 0.001 9, respectively). The injection rate has a F-value of 657.09, indicating it is more important than pressure with F-value of 107.86. The term AB stands for the interaction of the injection rate and pressure and its P-value (0.209 0) shows there is no significant correlation between them. S = 7.02 15.26A + 1.71B + 10.24A2 + 0.55B2 + 0.34A2B + 15.81AB2 (1) Fig. 6 shows that the predicted results by the model are in good agreement with the experimental results. Fig. 7 shows that pressure has less impact on gas storage capacity than flow rate. This shows that the gas storage capacity is mainly Table 3.
ANOVA for the gas storage capacity results.
Source
Degree Sum of of freesquares dom
Mean square
F-value
P-value
320.94
7
45.85
210.16
0.000 5
A: Flow rate
143.35
1
143.35
657.09
0.000 1
B: Pressure
23.53
1
23.53
107.86
0.001 9
AB
0.56
1
0.56
2.54
0.209 0
2
248.70
1
248.70
1 140.01
<0.000 1
6.38
1
6.38
29.25
0.012 4
2
AB
0.30
1
0.30
1.39
0.323 1
AB2
133.39
1
133.39
611.46
0.000 1
3
0.000
0
0
B3
0.000
0
0
Pure error
0.65
3
0.22
B2
A
Total dispersion 321.59
affected by gas injection rate, which is consistent with the results of variance analysis. The optimum condition for obtaining maximum gas storage capacity was sorted out by using ANOVA, namely the flow rate of 0.07 cm3/min and pressure of 14.354 MPa. A confirmation experiment was done under the optimum condition, the stored gas volume predicted by the model was 27.66% and the experimental value was 21.32%, which are in good agreement with each other. 2.4.
Model
A
Fig. 7. Contour diagram of percentage of stored gas volume to pore volume at different gas injection rates and pressures.
10
Fig. 6. Model prediction results and experimental results of the percentage of stored gas volume to the pore volume.
Effect of retention time
Two experiments (1 day and 60 days, respectively) were performed to find out the effect of retention time on storage process under the optimum condition (0.07 cm3/min and 14.354 MPa). The interaction between water and gas lasted for 6 months in field scale operation[21], but experiments were done in shorter periods due to limitations of experimental study. Gas was injected into the core under the optimal condition. The gas storage volume to pore volume measured was 18.93% and the residual gas saturation was about 13.07%. This shows retention time affects storage process significantly. In fact, much of the stored gas is trapped during the process and about 6% can be recovered. This is one of the consequences of gas contacting with water inside the porous medium. In aquifer gas storage reservoirs, the stored gas can flow more easily than water due to lower gravity than water. The displacement is taking place in a heterogeneous porous medium, and as a result, the water and gas can’t separate normally. There is usually trapped gas in water-bearing gas storage. Previous researchers have also found low recovery of aquifer gas storage reservoirs[22]. Therefore, this issue needs to be considered when selecting gas storage reservoirs. In order to investigate the interactions between rock and fluids, CT scanning, atomic absorption spectroscopy and gas chromatography were done on core plug and the fluid. Fig. 8 shows the inlet, middle and outlet cross sections of the core after 60 days. It can be seen clearly in the picture that at higher flow rate, the pressure difference between inlet and
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tion, the gas-water-rock interactions will not be as great as carbon dioxide storage process.
3.
Fig. 8. CT scan cross sections of core (a) inlet, (b) middle, (c) outlet. Table 4.
Ion concentrations of injected and produced brine. Injected brine/ (mgL1) 45240 30270 1580 641
Ion Ca2+ Na+ Mg2+ K+ Table 5.
Produced brine/ (mgL1) 49390 38413 1795 710
Change rate/% 9.17 26.90 13.61 10.76
Results of GC analysis.
Component Methane CO2
Injected/% 98.98 1.02
1st day/% 99.06 0.94
60th day/% 99.85 0.15
Conclusions
This study investigated the interactions between rock and fluids and parameters affecting natural gas storage capacity in saline aquifers. First, injection rate and pressure, two main parameters controlling gas storage capacity were examined. It is found that higher injection rate and pressure can enhance the gas storage capacity, and the injection rate has a stronger impact on gas storage capacity than pressure. After two months of storage, the gas recovery rate low, showing the retention effect after long storage. The atomic adsorption spectrum analysis shows drying effect occurs when natural gas is injected into brine-saturated core, so during long term gas storage, the interactions between rock and fluid should be considered. Gas chromatography analysis shows after storage in core, the concentration of CO2 in the natural gas reduces while that of methane increases. Petrophysical characteristics and lithology of the reservoir should be considered when selecting an aquifer as and during injection/withdrawal cycles of gas storage.
Acknowledgement
outlet of the core increases and may overcome capillary force in smaller pores, resulting in higher gas saturation at high flow rate. Also pressure drops and the saturation of gas gets small along the core’s length. In order to figure out the effect of gas storage on brine, atomic absorption spectroscopy (AAS) analysis was done on a Shimadzu aa-670 device. It can be seen from Table 4 that the concentrations of all of the ions increased in the produced brine, thus the salinity of produced water is higher than that of injected water. Water evaporation during gas injection may lead to over saturation and precipitation of salt in the solution[23]. The drying effect is also common in gas injection/producing wells, which causes salt precipitation in water and reduction of rock permeability and well injectivity[24]. Gas chromatography (GC) analysis was done to find out gas composition variation during the storage process. Gas samples after 1 and 60 days were gathered for GC analysis. The injected gas is mainly methane including a small amount of CO2. Methane is insoluble in water whereas CO2 tends to dissolve and interact with water. It can be seen from Table 5 that dissolution of CO2 leads to rise of methane concentration in the produced gas, and this effect gets stronger as time goes on. In reservoir scale operation much attention should be paid to petrophysical properties of the aquifer. Existence of fractures in the reservoir will affect gas and brine migration. Also reservoir pressure limitations and cap rock failure strength should be considered. In real operation, the retention time is longer and there may be more gas-water-rock interactions, but as natural gas does not take part in any major chemical reac-
This work was funded by Natural Gas Storage Company. The authors appreciate Natural Gas Storage Company for their valuable support and encouragement during this research.
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RESEARCH PAPER
Gas-water-rock interactions and factors affecting gas storage capacity during natural gas storage in a low permeability aquifer TOOSEH Esmaeel Kazemi1, JAFARI Arezou1,*, TEYMOURI Ali2 1. Petroleum Engineering Department, Chemical Engineering Faculty, Tarbiat Modares University, Tehran, Iran; 2. National Iranian Gas Company, Tehran, Iran
Abstract: Gas-water-rock interactions during natural gas storage in a low permeability aquifer and main factors affecting the storage capacity were investigated in laboratory with core experiments. The results showed that gas injection flow rate had a major impact on stored gas volume and stored gas volume is higher at high flow rate. Gas storage volume ranged between 6%20% of the pore space at experimental condition. Enhancing injection pressure can enhance gas storage volume. Statistics showed that injection flow rate had a greater influence on the gas storage volume than pressure. The retention time also had an impact on the gas storage process. Most of the natural gas was trapped in the reservoir and could not be produced after long time of retention. Atomic absorption spectroscopy indicated that ions concentrations of the brine and water evaporation increased when gas was injected into brine saturated core, and precipitation might occur, reducing porosity and permeability of core. Gas chromatography analysis showed that the concentration of carbon dioxide in the natural gas decreased and the concentration of methane increased after storage in the core. Key words: underground gas storage; natural gas; gas storage volume; aquifer; gas injection rate; gas injection pressure
Introduction Underground gas storage is an important way to store natural gas[1]. Depleted oil and gas reservoirs, aquifers and salt domes are the main types of reservoirs used for underground gas storage[2, 3]. Natural gas storage in saline aquifers is complicated and challenging[4], all aspects of the process should be considered[5]. Parameters affecting the process include flow characteristics of fluid in porous media, gas and water phase behavior, and reservoir conditions throughout the process[6], but they have not been studied thoroughly[7]. Among them, salinity of formation water and temperature of the aquifer may not vary during natural gas storage[8], but gas injection pressure and flow rate are controllable and need further investigation. Sohrabi et al.[9] investigated multiphase flow behavior and gaseous phase sweeping efficiency by injecting methane and water alternately. Pini et al.[10] studied heterogeneity effect on CO2 injection process by performing experiments on high and low permeability cores. They found that gas saturation was high at core entry and reduced through the core length, and gas saturation was much higher at high flow rate in both of the cores. Lorenz and Muller[11] tested nitrogen injection at temperatures below 100 °C. They found that salt precipitation
due to gas injection occurred near wells, also retention time and pressure loss during production resulted in more precipitation. Golghanddashti et al.[12] investigated salt precipitation by injecting natural gas into core plug at atmospheric pressure. The results showed that natural gas injection flow rate didn’t affect salt precipitation whereas thermodynamic condition was the main factor affecting the amount of salt precipitation. Torabi and Asghari[13] studied the effect of pressure on immiscible CO2 displacement of oil in porous media by conducting core flood experiment. Oh et al.[14] studied CO2-alternate-water displacement by simulation and experiment. They observed that by enhancing the injection rate, gas saturation at the inlet of the core increased. Peysson et al.[15] injected CO2 into brine saturated core and found gas flow rate had a strong impact on salt precipitation. Sadirli[8] studied natural gas storage in aquifer through numerical simulation. Obviously, natural gas storage in a low permeability saline aquifer has not been studied through core scale experiments. In this work, core flooding experiment is carried out on a real aquifer limestone core. The aquifer is a gas storage reservoir candidate and located in the center of Iran. The interaction between gas, water and rock in the low permeability aquifer is
Received date: 12 Feb. 2018; Revised date: 26 Aug. 2018. * Corresponding author. E-mail: [email protected] Copyright © 2018, Research Institute of Petroleum Exploration & Development, PetroChina. Publishing Services provided by Elsevier B.V. on behalf of KeAi Communications Co., Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).
TOOSEH Esmaeel Kazemi et al. / Petroleum Exploration and Development, 2018, 45(6): 1123–1128
tested to find out the effects of gas injection rate, pressure and retention time on gas storage capacity.
1. 1.1.
Materials and methods Rock sample
At first, 5 limestone cores were gathered from this aquifer. The core was taken from the depth of 1 041.15 m. The aquifer mainly consists of limestone and dolomite with micro-fractures in some sections. The core with the highest permeability and porosity was used in the experiments. The core is 7.62 cm long, 3.81 cm in diameter, 8.32% in porosity, 0.02×10−3 μm2 in permeability, and 7.22 cm3 in pore volume. 1.2.
Fluid properties
Synthetic brine used in the experiments was made of various salts according to brine analysis of the aquifer. From measurement, the brine has a density of 1.095 g/cm3 and viscosity of 0.75 mPaꞏs at the experiment temperature (46 °C). The concentrations of Ca2+, Na+, Mg2+, K+, Cl− and SO42− in the brine were 45.240, 30.270, 1.580, 0.641, 130.820 and 0.400 g/L, respectively, and the TDS (total dissolved solids) was 208.41 g/L. As the salinity of aquifer increases, the possibility of salt precipitation increases, which in turn could lower the gas storage capacity of the reservoir. In our experiments, core sample was washed after every experiment and the same brine was injected into the rock sample in each experiment. The natural gas used was taken from domestic gas pipe line. In order to gather sufficient amount of gas for the experiments, the natural gas needed to be stored and pressurized in a vessel. As domestic gas has a pressure of about 0.1 MPa, it was pressurized in several steps before storage. At first it passed through compressor and pressurized to 0.35 MPa, and the process was repeated for several times to till the pressure reached 8.0 MPa. The designed setup for gas pressurizing is shown in Fig. 1. Gas phase components were measured by gas chromatography (GC) and TCD detector. The results showed methane makes up about 98.98% of the gas and CO2 about 1.02%. 1.3.
Experimental setup
The core flooding setup is shown in Fig. 2. It consists of two transfer vessels, one for brine and the other for gas, a positive displacement pump displaces the fluids in the transfer vessels. The pump operates at a maximum pressure of 35 MPa
Fig. 1.
Schematic of gas pressurizing setup.
Fig. 2.
Schematic of experimental setup for gas storage process.
and flow rate range between 0.01–30.00 cm3/min. The accuracy of the pump is very important in this process, so it was measured before tests. The core plug was placed inside a stainless steel core holder which can hold cores up to 12 cm long and 3.81 cm in diameter. A back pressure regulator was used to maintain outlet pressure. Two transducers were placed at both ends of the core to measure pressure accurately at core faces. A separator was connected to the outlet line to separate produced liquid and gas. A hydraulic pump was used for applying overburden pressure. 1.4.
Experimental procedure
The experimental procedure is: (1) Rock sample was washed by injecting two pore volumes of methanol then, the core was dried inside the oven at 90 °C for 12 hours and weighed. (2) The dry core was wrapped inside aluminum foil and put in a rubber sleeve then placed inside the core holder and heated to 46 °C. In the course, the gas permeability was measured at 0.09×10−3 μm2. (3) The core plug was vacuumed before saturated by brine. Two pore volumes of the prepared synthetic brine were injected at low rate. (4) The core permeability was measured and core plug was removed and weighted. Then it was put into the core holder for gas injection. (5) The core was pressurized to the desired pressure and natural gas was injected at a constant flow rate till there was no brine produced any more. (6) The core was weighed after the test, and the stored natural gas was calculated with core weight difference before and after the experiment. The experimental design was based on central composite design (CCD), which is a perfect type of response surface methodology (RSM). In this method, the simultaneous effects of parameters on the process and each other can be investigated by fewer experiments compared with traditional methods. CCD introduces optimum condition in to the operational framework[16]. Even highly coupled processes can be investigated through experimental design[17]. In this study, injection flow rate and pressure were selected and their upper and lower limits were introduced to CCD. These limits are based on the real aquifer operational condition. The flow rate was set between 0.01 and 0.09 cm3/min and pressure was held between 8 and 16 MPa. For each parameter, five values were taken, and 12 experiments in total were carried out. Four experiments were done at the center point (that is, gas injection flow rate of 0.05 cm3/min and pressure of 12 MPa) to lower the errors.
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2.
Results and discussion
The results of 12 experiments are presented in in Table 1. The actual operation of gas storage shows retention time can affect the gas storage process. Therefore, the effect of time on gas storage process was studied by two experiments, one of 1 day and the other 5 days long. These experiments had nearly the same results, so the rest of experiments were all done in 1 day. Fig. 3 shows cross sections of the middle part of the core plug extracted from CT scan analysis. Table 2 shows the results of the 1-day and 5-day long experiments. From Fig. 3 and Table 2, there are few differences between two experiments, so the gas storage time is designed by 1 day in 12 experiments in Table 1. 2.1.
Fig. 4. Stored gas volume vs. flow rate at the pressure of 12 MPa.
Effect of injection rate
The effect of injection rate on storage is shown in Fig. 4. It can be seen from the figure that when the injection rate is low, the gas storage capacity decreases with the rise of injection rate, but when the injection rate is high, the gas storage capacity increases with the rise of injection rate. It is expected to Table 1.
Results of experiments.
Experiment Q/ No. (cm3ꞏmin−1) 1 2 3 4 5 6 7 8 9 10 11 12
0.03 0.07 0.03 0.07 0.01 0.09 0.05 0.05 0.05 0.05 0.05 0.05
P/ MPa 10 10 14 14 12 12 8 16 12 12 12 12
Percentage of gas Storage 3 storage volume to volume/cm pore volume/% 1.125 15.58 1.152 15.94 1.367 18.94 1.502 20.79 0.838 11.6 1.261 17.47 0.417 5.78 0.913 12.64 0.470 6.51 0.507 7.02 0.500 6.92 0.552 7.64
Fig. 5. Relationship between stored gas volume and pressure at gas injection rate of 0.05 cm3/min.
have an ascending trend at even higher flow rate, but the applicability of different types of rock to high flow rate should be considered[18]. The process of gas injection in this core was under capillary control. The calculated values of capillary number (Nc) for these experiments were around 1010-1011, therefore, capillary pressure is the major force driving flow of natural gas-water. Also Reynolds number of the experiments ranged from 0.049 to 0.117, indicating there were Darcy flow in all the experiments. 2.2.
Fig. 3. CT scan cross sections of middle part of the core (a) 1 day, (b) 5 days. Table 2.
Results of 1-day and 5-day long experiments.
Retention Q/ time/d (cm3ꞏmin−1) 1 0.05 5 0.05
P/ MPa 16 16
Stored gas/cm3 0.913 0.987
Recovered gas/cm3 0.867 0.926
Effect of pressure
Pressure plays a major role in behaviors of multi-phase systems flow including gas[13]. Here, gas and water act as immiscible phase displacement. Increase of pressure would make the gas density and viscosity rise, so the displacing phase performance would improve. Fig. 5 shows that gas storage capacity increases significantly with the rise of pressure. As shown in the figure, by increasing pressure from 8 to 16 MPa, gas saturation in the core goes up from 5.78% to 12.64%. 2.3.
Statistical analysis
Statistical approach was adopted to figure out the effects of gas injection rate and pressure on gas storage capacity and their interaction. It should be noted that experiment no.5 was ignored in the statistics because the p-value of the model was not acceptable. A cubic model for gas storage percentage (S) 1125
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was obtained through analysis of variance (ANOVA) (see equation (1)). This analysis predicted model results by 95% confidence and implied p-values < 0.05 as significant terms[19]. The model R2 (complex correlation coefficient) is 0.998, confirming the model is reliable. The other statistical index is F value. F value represents the importance of a parameter[20]. Table 3 shows ANOVA of the model. It can be seen from the table P-value of this model is 0.000 5, which confirms the model significance with 95% confidence. Injection rate and pressure are two important parameters, which have P-values of less than 0.05 (0.000 1 and 0.001 9, respectively). The injection rate has a F-value of 657.09, indicating it is more important than pressure with F-value of 107.86. The term AB stands for the interaction of the injection rate and pressure and its P-value (0.209 0) shows there is no significant correlation between them. S = 7.02 15.26A + 1.71B + 10.24A2 + 0.55B2 + 0.34A2B + 15.81AB2 (1) Fig. 6 shows that the predicted results by the model are in good agreement with the experimental results. Fig. 7 shows that pressure has less impact on gas storage capacity than flow rate. This shows that the gas storage capacity is mainly Table 3.
ANOVA for the gas storage capacity results.
Source
Degree Sum of of freesquares dom
Mean square
F-value
P-value
320.94
7
45.85
210.16
0.000 5
A: Flow rate
143.35
1
143.35
657.09
0.000 1
B: Pressure
23.53
1
23.53
107.86
0.001 9
AB
0.56
1
0.56
2.54
0.209 0
2
248.70
1
248.70
1 140.01
<0.000 1
6.38
1
6.38
29.25
0.012 4
2
AB
0.30
1
0.30
1.39
0.323 1
AB2
133.39
1
133.39
611.46
0.000 1
3
0.000
0
0
B3
0.000
0
0
Pure error
0.65
3
0.22
B2
A
Total dispersion 321.59
affected by gas injection rate, which is consistent with the results of variance analysis. The optimum condition for obtaining maximum gas storage capacity was sorted out by using ANOVA, namely the flow rate of 0.07 cm3/min and pressure of 14.354 MPa. A confirmation experiment was done under the optimum condition, the stored gas volume predicted by the model was 27.66% and the experimental value was 21.32%, which are in good agreement with each other. 2.4.
Model
A
Fig. 7. Contour diagram of percentage of stored gas volume to pore volume at different gas injection rates and pressures.
10
Fig. 6. Model prediction results and experimental results of the percentage of stored gas volume to the pore volume.
Effect of retention time
Two experiments (1 day and 60 days, respectively) were performed to find out the effect of retention time on storage process under the optimum condition (0.07 cm3/min and 14.354 MPa). The interaction between water and gas lasted for 6 months in field scale operation[21], but experiments were done in shorter periods due to limitations of experimental study. Gas was injected into the core under the optimal condition. The gas storage volume to pore volume measured was 18.93% and the residual gas saturation was about 13.07%. This shows retention time affects storage process significantly. In fact, much of the stored gas is trapped during the process and about 6% can be recovered. This is one of the consequences of gas contacting with water inside the porous medium. In aquifer gas storage reservoirs, the stored gas can flow more easily than water due to lower gravity than water. The displacement is taking place in a heterogeneous porous medium, and as a result, the water and gas can’t separate normally. There is usually trapped gas in water-bearing gas storage. Previous researchers have also found low recovery of aquifer gas storage reservoirs[22]. Therefore, this issue needs to be considered when selecting gas storage reservoirs. In order to investigate the interactions between rock and fluids, CT scanning, atomic absorption spectroscopy and gas chromatography were done on core plug and the fluid. Fig. 8 shows the inlet, middle and outlet cross sections of the core after 60 days. It can be seen clearly in the picture that at higher flow rate, the pressure difference between inlet and
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tion, the gas-water-rock interactions will not be as great as carbon dioxide storage process.
3.
Fig. 8. CT scan cross sections of core (a) inlet, (b) middle, (c) outlet. Table 4.
Ion concentrations of injected and produced brine. Injected brine/ (mgL1) 45240 30270 1580 641
Ion Ca2+ Na+ Mg2+ K+ Table 5.
Produced brine/ (mgL1) 49390 38413 1795 710
Change rate/% 9.17 26.90 13.61 10.76
Results of GC analysis.
Component Methane CO2
Injected/% 98.98 1.02
1st day/% 99.06 0.94
60th day/% 99.85 0.15
Conclusions
This study investigated the interactions between rock and fluids and parameters affecting natural gas storage capacity in saline aquifers. First, injection rate and pressure, two main parameters controlling gas storage capacity were examined. It is found that higher injection rate and pressure can enhance the gas storage capacity, and the injection rate has a stronger impact on gas storage capacity than pressure. After two months of storage, the gas recovery rate low, showing the retention effect after long storage. The atomic adsorption spectrum analysis shows drying effect occurs when natural gas is injected into brine-saturated core, so during long term gas storage, the interactions between rock and fluid should be considered. Gas chromatography analysis shows after storage in core, the concentration of CO2 in the natural gas reduces while that of methane increases. Petrophysical characteristics and lithology of the reservoir should be considered when selecting an aquifer as and during injection/withdrawal cycles of gas storage.
Acknowledgement
outlet of the core increases and may overcome capillary force in smaller pores, resulting in higher gas saturation at high flow rate. Also pressure drops and the saturation of gas gets small along the core’s length. In order to figure out the effect of gas storage on brine, atomic absorption spectroscopy (AAS) analysis was done on a Shimadzu aa-670 device. It can be seen from Table 4 that the concentrations of all of the ions increased in the produced brine, thus the salinity of produced water is higher than that of injected water. Water evaporation during gas injection may lead to over saturation and precipitation of salt in the solution[23]. The drying effect is also common in gas injection/producing wells, which causes salt precipitation in water and reduction of rock permeability and well injectivity[24]. Gas chromatography (GC) analysis was done to find out gas composition variation during the storage process. Gas samples after 1 and 60 days were gathered for GC analysis. The injected gas is mainly methane including a small amount of CO2. Methane is insoluble in water whereas CO2 tends to dissolve and interact with water. It can be seen from Table 5 that dissolution of CO2 leads to rise of methane concentration in the produced gas, and this effect gets stronger as time goes on. In reservoir scale operation much attention should be paid to petrophysical properties of the aquifer. Existence of fractures in the reservoir will affect gas and brine migration. Also reservoir pressure limitations and cap rock failure strength should be considered. In real operation, the retention time is longer and there may be more gas-water-rock interactions, but as natural gas does not take part in any major chemical reac-
This work was funded by Natural Gas Storage Company. The authors appreciate Natural Gas Storage Company for their valuable support and encouragement during this research.
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