Article Cite This: Energy Fuels XXXX, XXX, XXX−XXX
pubs.acs.org/EF
Methane Recovery from Hydrate-Bearing Sediments by the Combination of Ethylene Glycol Injection and Depressurization Yi-Fei Sun,†,‡ Jin-Rong Zhong,† Wen-Zhi Li,‡ Yi-Ming Ma,† Rui Li,† Tao Zhu,† Liang-Liang Ren,† Guang-Jin Chen,*,† and Chang-Yu Sun*,† †
State Key Laboratory of Heavy Oil Processing, China University of Petroleum, Beijing 102249, People’s Republic of China State Key Laboratory of Special Functional Waterproof Materials, Beijing Oriental Yuhong Waterproof Technology Company, Limited, Beijing 101309, People’s Republic of China
Downloaded via UNIV OF CALIFORNIA SANTA BARBARA on July 7, 2018 at 03:31:18 (UTC). See https://pubs.acs.org/sharingguidelines for options on how to legitimately share published articles.
‡
ABSTRACT: Considering the limitations of a single method for hydrate recovery, the combination of the traditional methods receives more attention nowadays. In this work, the gas production behavior from a synthesized methane hydrate reservoir by the combined method of ethylene glycol (EG) injection and depressurization was investigated in a medium-size threedimensional reactor. The hydrate-bearing sediments were prepared according to the temperature and pressure conditions of the South China Sea reservoir. The results indicated that the production period could be significantly shortened by the combination method. After comparison of different EG injection conditions, it is found that the migration characteristics of EG solution in the reservoir were quite different in the EG injection stage, which caused different gas production rates in the follow-up process. Moreover, the increase of the EG concentration or EG injection volume could enhance the gas production rate. From analysis of the evolution of the low-temperature region, it is seen that EG was mainly concentrated between the injection well and production well. The migration of EG was largely influenced by the injection rate. When a higher EG injection rate was used, EG solution would arrive at the production well faster and spread to a larger region over time. It is necessary to avoid EG output caused by excessive injection. In addition, EG efficiency was found to be influenced by EG injection patterns. The maximum values of EG efficiency could be enhanced significantly by decreasing the EG concentration. Meanwhile, the EG efficiency at the end of gas production also relied on the injection volume and injection rate.
1. INTRODUCTION Natural gas hydrate is an ice-like crystalloid solid compound formed by water and small molecules, typically methane, under low temperature and high pressure.1 In nature, gas hydrate widely occurs in the submarine sediments on continental margins (97%) and shallow permafrost regions (3%),2−4 and the gas reserves are estimated to be over 1.5 × 1016 m3; thus, it is considered to be a potential strategic energy resource for the future.4,5 Therefore, the research on hydrate recovery is receiving more and more attention from many countries.6 In the last few decades, the studies on hydrate dissociation characteristics have made significant progress. Briefly, if the stability conditions of hydrate are sufficiently altered, the hydrate dissociation will occur and revert back to gas and water. Up to now, the primary and promising methods for gas production from hydrate reservoirs include depressurization,7,8 heat stimulation,9−12 thermodynamic inhibitor injection,13 and CO2 replacement.14,15 Among them, depressurization is regarded as the most economical and feasible method, while thermodynamic inhibitor injection is evaluated as a highly effective method, which is beneficial to the alterations of both hydrate equilibrium conditions16 and hydrate decomposition heat.17 However, the above production methods have their own disadvantages: e.g., depressurization may cause ice blockage and hydrate reformation and low gas production rate in the later period;18 heat stimulation causes low energy efficiency, considering the unavoidable heat loss; and inhibitor injection will increase the production cost and may affect the ecological environment. In addition, several field tests of © XXXX American Chemical Society
hydrate exploitation have been conducted in some countries19−22 and have made great achievements and knowledge. However, hydrate exploitation is still not entering the commercial exploitation stage, which implies that the selection and optimization of production methods are not effectively solved. Given the limitations of the above production methods, the combinations of these techniques are proposed and widely considered to be a better way to enhance the effectiveness of gas production. Konno et al.23 attempted some production pressure values and found that depressurization above the quadruple point could not completely dissociate existing hydrate as a result of the lack of sensible heat in the sediments. Wang et al.18 confirmed the ice generation and hydrate reformation using magnetic resonance imaging visualization. The results indicated that the hydrate decomposition characteristics were dominated by pressure drop and ambient heat transfer. To solve these problems, a thermal stimulation method was added to the depressurization process. On the basis of this combined production method, many related physical and numerical simulations have been performed.24−27 The results demonstrated that the combination method could enhance the gas production rate and energy efficiency simultaneously compared to single-heat stimulation or depressurization. However, Kurihara et al.28 compared the Received: May 12, 2018 Revised: June 21, 2018 Published: June 25, 2018 A
DOI: 10.1021/acs.energyfuels.8b01682 Energy Fuels XXXX, XXX, XXX−XXX
Article
Energy & Fuels
Figure 1. Schematic graph of the experimental apparatus: (1) CH4 cylinder, (2) mass balance, (3) relief valve, (4) beaker, (5) booster pump, (6) vacuum pump, (7) metering pump, (8) reactor, (9) injection well, (10) production well, (11) water bath, (12) gas−water separator, (13) filter, (14) back-pressure valve, (15) production gas cylinder, and (16) computer and MCGS system.
employed as an inhibitor to prevent hydrate formation during natural gas transportation and production.35 On the basis of the above studies, the technique of inhibitor injection can be a vital solution to solve the low gas production rate in the depressurization process and enhance the production efficiency. The combination of inhibitor injection and depressurization can also remedy the drawback of ice blockage and hydrate reformation when using single depressurization. However, few investigations into the gas production by the combination method were carried out. In this study, the EG injection method was combined with the depressurization method to conduct hydrate exploitation experiments with dual vertical wells. As a contrast, the hydrate exploitation experiment using a single depressurization method was also conducted under the same reservoir conditions. Hereinto, the conditions of synthesizing hydrate samples were based on the specific hydrate reservoir conditions in the northern slope area of the South China Sea.36 The gas production process was divided into three stages: the EG injection stage, the soaking stage, and the depressurization stage. The variations of the temperature and pressure, EG migration characteristics, gas production behaviors, and EG efficiency during the production process were expected to be comprehended under different EG injection patterns. The combination method was optimized accordingly based on the experimental results, and suggestions were provided for further study.
theoretical energy efficiency of several different combination methods and concluded that the key problem was still the poor energy efficiency. By comparison, inhibitor injection has been relatively less studied, especially in the past few years. Sung et al.29 analyzed the hydrate dissociation behavior and flowing phenomena of the dissociated gas and water using the depressurization and methanol injection methods. They discovered that, in the production process after methanol injection, the pressures of the inlet and outlet instantly declined as soon as the production valve was opened, which proved that the whole hydrate in the reactor was simultaneously dissociated. This was quite different from the dissociation characteristics using the depressurization method, in which the outlet pressure behaves as the pulse type and the hydrate successively decomposed. Li et al.30 simulated the hydrate dissociation process in a one-dimensional (1D) reactor by ethylene glycol (EG) injection and discovered that the gas production efficiency was related to the EG concentration and EG injection rate. Kawamura et al.31 tested the hydrate dissociation by EG injection at different temperatures, and the results showed that the effect of EG on gas production was very obvious. Fan et al.32 studied the hydrate dissociation heat in EG solution and grasped that less energy for hydrate dissociation would be required with a higher EG concentration. Wang et al.18 found that the presence of water could increase the heat capacity of the reservoir, thereby further improving the rate of hydrate dissociation. In addition, Aminnaji et al.33 studied the effect of EG and methanol mixtures on hydrate blockage removal and reported that a mixture with a density of 1 g/cm3 could remove hydrate blockage successfully and efficiently. It also indicated that the ice formation during hydrate dissociation could be inhibited using EG injection. Chong et al.16 observed a monotonic increase in the gas production ratio with an increasing EG concentration, while an optimum concentration exists when NaCl was used as an inhibitor. This was attributed to the clogging of pores caused by the excess brine concentration, which did not occur with EG. Additionally, Dong et al.34 contrasted methanol and EG and considered EG to have greater application potential. That is because EG is more available in the market and has lower toxicity and better performance in hydrate production. Therefore, EG was more
2. EXPERIMENTAL SECTION 2.1. Materials and Apparatus. Methane gas with a purity of 99.99% was supplied by the Beijing Beifen Gas Industry Corporation. EG with a purity of 99.99% was supplied by Beijing Modern Eastern Fine Chemical. Brine with a salinity of 33.5 g/L was prepared in the laboratory with sodium sulfate. Deionized water was used in all experiments. The hydrate-bearing sediments were formed by 20−40 mesh quartz sands with the porosity of 0.387. Figure 1 shows the schematic graph of the experimental apparatus used in this work. As shown in Figure 1, the experimental apparatus includes four sections: the reaction system, the injection system, the production system, and the monitor and control generated system (MCGS). The main part of the reaction system was a high-pressure reactor with an effective volume of 10.6 L (Φ 300 × 150 mm) and a maximum operating pressure of 32 MPa. The injection well and B
DOI: 10.1021/acs.energyfuels.8b01682 Energy Fuels XXXX, XXX, XXX−XXX
Article
Energy & Fuels production well were symmetrically distributed in the edge of the reactor. During the experimental process, the reactor was immerged in a water bath filled with EG solution, which could be maintained at a constant temperature with a precision of ±0.1 K. A total of 54 temperature transducers with a precision of ±0.1 K were inserted into the reactor to monitor the temperatures at different positions in the reactor. Four pressure transducers with the precision of ±0.1% were installed at the bottom and top of the reactor and in the two wells. The injection system mainly included a balance with a precision of ±0.01 g to record the quality of EG injection and a customized metering pump with a measurement range of 0−10 mL/s. The production system was mainly composed of a gas−liquid separator, a filter, two back-pressure valves, a gas collection cylinder, and a balance with a precision of ±0.01 g to record the quality of water production. The MCGS was used to show and record the variation of temperatures and pressures during the experiments. Figure 2 gives the schematic plots of the specific spatial distributions of the temperature/pressure transducers and the two
wells. The 54 temperature transducers were distributed in three horizontal layers, which were at the heights of 20, 75, and 130 mm from the bottom of the reactor, respectively. On each layer, there were 18 transducers evenly distributed in six directions at the distances of 20, 75, and 130 mm from the reactor center axis. The dual vertical well, that is, the injection well and production well, was symmetrically distributed in the reactor, and the horizontal distance from the reactor central axis was 132 mm. Small holes with the diameter of 2 mm were evenly distributed on the four sides of the wells. 2.2. Experimental Procedure. 2.2.1. Hydrate Sample Preparation. First, 15 540 g of dry quartz sand was frozen to 258.2 K and 2103 g of brine solution was cooled to 273.2 K and kept for at least 12 h. Then, the sand and brine were mixed and stirred adequately to ensure a uniform distribution of brine in the sand. After mixing evenly, the mixture was packed into the reactor, which was immersed in a water bath at 276.2 K. The mixture just filled the reactor by artificial compaction, and the brine saturation was ∼48 vol %. Then, the temperature transducers were inserted into the sand, and the reactor was sealed. Thereafter, nitrogen gas was injected into the reactor to check for leaks. If no bubbles emerged around the reactor, the whole apparatus would be vacuumed for 20 min and washed twice by methane gas. Then, methane gas was reinjected into the reactor to 8.3 MPa, which was much higher than the hydrate equilibrium pressure. After 5−10 h, the system pressure started to decrease rapidly as a result of the rapid formation of hydrate (exothermic process), which caused the corresponding average temperature in the reactor to rise for a short duration.37,38 The pressure eventually stabilized at ∼4.1 MPa after ∼150 h. Afterward, methane gas was pumped into the reactor to pressurize the hydrate reservoir up to 13.0 MPa, and after ∼30 h, the pressure stabilized again at ∼11.2 MPa. Then, the temperature of the water bath was raised step by step to simulate the actual hydrate reservoir temperature in the northern slope area of the South China Sea.36 After ∼50 h for the temperature adjustment, the final hydrate reservoir samples were obtained. The temperature and pressure conditions of each experiment were basically consistent, as shown in Table 1. The calculation of the saturation of gas, brine, and hydrate can be referenced in the study by Yuan et al.13 2.2.2. Hydrate Dissociation. The hydrate dissociation process was initiated after the accomplishment of hydrate sample preparation. The whole process was divided into three stages: the EG injection stage, the soaking stage, and the depressurization stage. In the EG injection stage, the back-pressure value was preset to the pressure, consistent with that in the reactor. Then, valves 3, 5, and 7 in Figure 1 were opened, and almost simultaneously, the EG solution started to be injected at a constant rate. In this process, opening the production well could guide the EG migration, thereby weakening the effect of the reactor wall on the EG flow. Then, a part of the pore space in the sediments was occupied by EG solution, which therewith caused the dissociation of the affected hydrate. As a result, methane gas was continuously produced. When the EG injection volume reached the planned value, the dual wells were closed immediately and the soaking stage started. EG solution continued to diffuse in the pores at this stage and further stimulated hydrate dissociation. Meantime, the backpressure regulator was adjusted to 8 MPa for the next depressurization stage. After 60 min of the soaking stage, the valves 5 and 7 were opened again and the depressurization stage was carried out. In this stage, the residual hydrate was gradually decomposed. When there was no gas release, the gas production process was considered to be terminated. The durations of this stage were 6−16 h for runs 1−6. The detailed experimental parameters are shown in Table 1.
3. RESULTS AND DISCUSSION 3.1. Effect on Gas Production. Figure 3 shows the evolutions of pressure in the reactor and the corresponding cumulative volume of the produced gas (VG) for runs 1−6. Because the porosity and permeability of the quartz sands deposits were relatively high, it can be considered that the pressures of each point in the reactor were uniform; that is, the monitoring pressure could represent the pressure of the whole
Figure 2. Distributions of the (a) thermometers and (b) wells in the reactor. C
DOI: 10.1021/acs.energyfuels.8b01682 Energy Fuels XXXX, XXX, XXX−XXX
Article
Energy & Fuels
EG, which was 808 and 561 mL, respectively. The corresponding VG value in run 1 was much larger than that in run 3. In run 1, more time was used for EG migration and EG solution took up more pore volume finally, thus causing more hydrate dissociation and more gas to be replaced. For runs 4 and 5, the EG volume difference was the same as that between runs 1 and 2, but the gap in VG was obviously reduced. This is due to the fact that the EG solution had reached the production well before the end of the EG injection. Excessive injection caused 146 g of EG solution to be produced with the output gas at this stage, while there was almost no water production in runs 1−4 and 6. In addition, as a result of the existence of the reactor wall, the excessive EG solution largely concentrated in the corner near the production well, thus resulting in a decrease in the EG efficiency of run 5. For runs 1 and 4, the increase of the EG injection rate caused the decrease of VG, which was due to the decrease of the consumed time in this stage. However, the slope of the VG curve for run 4 is larger, indicating that the gas production rate was higher. Therefore, the increase of the EG injection rate was beneficial to hydrate dissociation as a result of the higher diffusion rate. To summarize, the origins of produced gas were composed of two parts. One part was driven out from the pore space by EG solution, and another part came from the hydrate dissociation as a result of the contact of EG with hydrate. In theory, the former shows that more EG injection could replace more free gas in the pores. The latter indicates that a higher EG concentration or larger contact area of EG and hydrate could lead to more hydrate dissociation. Therefore, either increasing the EG injection volume or increasing the EG concentration can both theoretically improve the amount of hydrate dissociation, which is consistent with that observed by Fan et al. (10−30 wt %),17 Yuan et al. (30−100 wt %),13 and Chong et al.16 In addition, when the volume and concentration of EG solution are fixed, the increase of the EG migration range can be more conductive to the diffusion of EG solution, which increases the contact area of hydrate and EG and then accelerates the hydrate dissociation. At the end of this stage, the volumes of produced gas for runs 1−5 were 183.81, 170.78, 112.41, 133.17, and 156.91 L, respectively. After completion of the EG injection, the soaking stage began and lasted for 60 min. For runs 1−5, the pressures all increased continuously but the pressure increments and slopes of pressure curves were different from each other, as shown in Figure 3, which meant that hydrate was still being decomposed and hydrate dissociation rates were different. In this stage, VG remains constant for the closure of the production well. In the depressurization stage, the back-pressure regulator was preset to 8 MPa and the production valve was opened. As shown in Figure 3, VG increased dramatically with the rapid decrease of the system pressure for runs 1−5 at the initial period of the depressurization stage. Then, VG turned to increase slowly, which was consistent with the characteristics by the single depressurization in run 6. Figure 4 shows the average gas production rates during the production process for runs 1−6. In this work, the recovery ratio (Rt) is calculated as follows:
Table 1. Properties of Prepared Methane Hydrate and Experimental Parameters experimental run initial temperature (K) initial pressure (MPa) initial hydrate saturation initial methane gas saturation initial brine saturation well spacing (mm) temperature of EG injected (K) EG concentration (wt %) EG solution quantity (g) volume of EG solution (mL) EG injection rate (mL/min) soaking time (min) production pressure (MPa)
1
2
3
4
5
6
286.0
285.9
286.4
285.1
285.3
285.9
11.34
11.33
11.02
11.37
11.43
11.32
0.31
0.32
0.39
0.34
0.38
0.40
0.53
0.52
0.51
0.52
0.51
0.51
0.16
0.16
0.10
0.14
0.11
0.09
264
264
264
264
264
293.2
293.2
293.2
293.2
293.2
100
70
100
100
100
900
900
626
902
1220
808
837
561
809
1094
26.9
27.0
26.7
118.6
118.5
60
60
60
60
60
8.1
8.0
8.1
8.0
8.0
7.9
Figure 3. Variations of the pressures in the reactor and corresponding cumulative volumes of gas production.
hydrate samples. In EG injection stage, it can be seen that the pressures in the reactor fluctuate up and down near 11.3 MPa, which is caused by the EG solution migration driven by the plunger metering pump and the consequent hydrate decomposition. Meanwhile, the corresponding cumulative volumes of gas production comparatively evenly increase with the elapsed time. As shown in Figure 3, the VG value for run 1 was larger than that for run 2, which is due to the larger EG concentration for run 1. A higher EG injection concentration meant that a higher EG concentration could be maintained as EG solution flowed around. Furthermore, a higher EG concentration decreased the hydrate dissociation heat, which was beneficial to the hydrate dissociation.32 The difference between runs 1 and 3 was the volume of injected
Rt =
nG, t nG,0 + nH,0
× 100% (1)
where nG,0 and nH,0 represent the mole number of methane in the gas phase or hydrate sample at the initial time (t = 0), D
DOI: 10.1021/acs.energyfuels.8b01682 Energy Fuels XXXX, XXX, XXX−XXX
Article
Energy & Fuels
Figure 4. Evolutions of the average production rate for runs 1−6. Figure 5. Percentages of hydrate dissociation in the three stages for runs 1−6.
respectively, and nG,t represents the mole number of methane in the gas phase at a specified time (t) of the gas production. It can be seen that the production rates all decreased to the minimum values until the end of gas production. After the recovery ratio was >50%, the production rate was doubly reduced when the recovery ratio increased by 10%. At last, the recovery ratios were 69.4, 69.7, 68.9, 70.6, 70.9, and 61.4% for runs 1, 2, 3, 4, 5, and 6, respectively. The corresponding production rates were 0.711, 0.646, 0.520, 0.998, 1.059, and 0.424 L/min, respectively. In the process of run 6, which single depressurization was used, the gas production rate was always the smallest. The reason is due to the fact that the hydrate dissociation in run 6 was only controlled by the rate of ambient heat transfer after the system pressure fell to the production pressure. However, in the other five runs, the EG injection also promoted the hydrate dissociation. That is, the hydrate dissociation in this stage was under the synergistic effect of the depressurization and EG stimulation. Therefore, the EG concentration, EG volume, or injection rate could influence the production efficiency. It can be noted that the EG injection rate might be the most prominent influential factor. Figure 5 shows the hydrate dissociation ratios in the three stages for runs 1−6, and Table 2 gives the corresponding consumed time for each stage. Hereinto, the hydrate dissociation ratio (Dt) is calculated as follows: nH,0 − nH, t Dt = × 100% nH,0 (2)
Table 2. Consumed Time at Each Stage for Runs 1−6 experimental run consumed time (min)
stage 1 stage 2 stage 3 total
1
2
3
4
5
6
30 60 557 647
31 60 629 720
21 60 800 881
7 60 363 430
9 60 352 421
963 963
0.218%/min. These results showed that the higher EG injection rate could enhance the hydrate dissociation rate in the soaking stage significantly. The reason may be related to the migration characteristic of EG in the reservoir. In addition, the injection volume and EG concentration were also beneficial to the hydrate dissociation. For example, runs 1 and 2 were performed under different EG concentrations but the same for other production conditions, and a higher hydrate dissociation rate was attained when the EG concentration is higher. In comparison to run 3, which were performed under lower EG injection volumes, the hydrate dissociation rate of run 1 was higher. In the depressurization stage (stage 3), the average hydrate dissociation rates of the residual hydrate for runs 1, 2, 3, 4, and 5 were 0.117, 0.115, 0.087, 0.212, and 0.210%/min, respectively. The differences were mainly influenced by EG injection conditions in the reservoir. For example, the residual hydrate in run 4 was more than that in run 1, but less time was consumed for the dissociation of residual hydrate in run 4 than that in run 1. Similarly, it can be seen that the hydrate dissociation rate could be improved by increasing the EG concentration, injection volume, or injection rate. In addition, the hydrate dissociation by single depressurization in run 6 was analyzed for comparison. The durations for runs 1−5 were all less than that for run 6, and hydrate dissociation rates for runs 4 and 5 were evenly more than doubled in comparison to run 6, which indicating that the presence of EG could effectively shorten the hydrate dissociation time. 3.2. Characteristics of EG Migration. Figure 6 shows the variations of the pressure and average temperature in the top layer, middle layer, and bottom layer of the sediments for run 4 during the exploitation process. Here, the average temperature
where nH,t is the molar amount of methane trapped in hydrate at a specified time (t) of the gas production process. In the EG injection stage, the hydrate dissociation ratios for runs 1, 2, 3, 4, and 5 were 29.5, 23.5, 17.6, 10.8, and 13%, respectively. The values of Dt in this stage (stage 1) increased with the increase of the EG concentration and injection volume or the reduction of the injection rate, which was in accordance with the results mentioned above. By calculation, the average hydrate dissociation rates for runs 1, 2, 3, 4, and 5 were 0.983, 0.758, 0.838, 1.543, and 1.625%/min, respectively. It illustrated that the increase of the injection rate could improve the hydrate dissociation rate but reduce the recovery ratio simultaneously in this stage. In the soaking stage (stage 2), the hydrate dissociation ratios for runs 1, 2, 3, 4, and 5 were 5.3, 4.3, 4.0, 12.3, and 13.1%, respectively. The corresponding hydrate dissociation rates were 0.088, 0.072, 0.067, 0.205, and E
DOI: 10.1021/acs.energyfuels.8b01682 Energy Fuels XXXX, XXX, XXX−XXX
Article
Energy & Fuels
of the top layer refers to the average value of T1−T18, and the average temperature of the middle layer and bottom layer corresponded to the average value of T19−T36 and T37−T54, respectively. In the EG injection stage, the EG solution was almost evenly injected into the reactor at the rate of 2 mL/s and the opening of the production well in this stage was propitious to guide the transfer of EG solution from the injection well to production well. As shown in Figure 6, the average temperature of the top layer rapidly decreased to the lowest point. It indicated that the hydrate in the top layer of the reservoir had decomposed as a result of the contact with EG solution. EG solution not only affected the thermodynamic stability of hydrate but also brought in a certain quantity of heat, and the forced convection caused by EG solution injection also promoted the heat exchange rate for hydrate dissociation. Then, the average temperature turned to increase in the last 1−2 min of this stage, because the heat required for hydrate dissociation
Figure 6. Variations of the average temperature and pressure for run 4.
Figure 7. Evolutions of the boundary and volume fraction of the low-temperature region. F
DOI: 10.1021/acs.energyfuels.8b01682 Energy Fuels XXXX, XXX, XXX−XXX
Article
Energy & Fuels
absence of EG. For runs 1−3, the low-temperature regions were all concentrated on the half side of the injection well, which indicated that the hydrate dissociation region was mainly concentrated on the side of the injection well. However, the boundaries of low-temperature regions for runs 4 and 5 had connected the dual wells. It indicates that the EG migration in the horizontal direction is mainly controlled by the injection rate. In addition, the low-temperature regions for runs 2 and 3 were shrinking compared to run 1 on account of the decrease of the EG concentration and EG injection volume. In comparison to run 4, the low-temperature region around the production well was obviously expanded in run 5, which was due to the accumulation of EG solution here. The results indicate that the EG injection volume and concentration have greater influence on the volume of the lowtemperature region. In the subsequent soaking stage, lowtemperature regions of runs 1−5 shrank gradually and moved from the top layer to the bottom layer over time. Furthermore, low-temperature regions for runs 1−3 moved toward the production well at the same time. The phenomena were due to the hydrate dissociation leading to the increase of pressure in the reactor. Then, the driving force of hydrate decomposition decreased, which would reduce heat absorption. Moreover, heat transfer from the water bath to the reservoir also caused gradual temperature recovery in the reactor. Therefore, lowtemperature regions shrank in the soaking stage. Meanwhile, the results further illustrated the transport characteristics of EG solution in the reservoir. First, most EG solution flowed through the top layer of the reservoir from the injection well to the production well, and some EG solution flowed through the middle layer; however, little EG solution flowed into the bottom layer straightly. It might be related to the inhomogeneous distribution of water and hydrate in the pores of different heights. 3.3. EG Efficiency. In this study, EG efficiency (ξ) is employed to evaluate the potency of EG injection in the gas production process. Here, the EG efficiency is calculated as follows:
became smaller than the injected heat. In the middle layer, the average temperature decreased in the EG injection stage but both the temperature descending slope and range became smaller than those of the top layer, indicating that hydrate dissociation became mild. Additionally, the average temperature in the bottom layer almost keeps constant in the EG injection stage, indicating that few hydrates in the bottom layer decomposed in this stage. That is, the injected EG solution was easier to flow in the top layer in the EG injection stage, probably because the brine saturation in the top layer was relatively low and the permeability was higher than that of the lower layers. In the second stage, the injection well and production well were both closed and the soaking stage lasted for 60 min. EG solution continued to spread as a result of the gravity and inertia effect. As shown in Figure 6, three temperature curves for three layers decreased first and turned to rise at different time points. The corresponding turning points were at 8, 14, and 44 min for the top, middle, and bottom layers, respectively. Evidently, the position had a significant impact on the temperature, on account of heat transfer from the environment and EG migration in the reservoir. The meaning of the soaking stage was to provide time for the EG migration. In the depressurization stage, the residual hydrate continued to decompose as a result of the synergistic effects of EG injection and depressurization. As shown in Figure 6, the variations of the temperature and pressure were similar to that in the hydrate mining by depressurization. At 300 min, the average temperature of the upper layer was almost back to the initial reservoir temperature. However, the gaps between the average temperatures of the lower layers and the initial temperature were relatively larger. Moreover, the heat transfer between the bottom layer and the environment should be faster, but the slope of the temperature curve in the bottom layer was the smallest. The results indicated that the residual hydrate mainly distributed in middle and bottom layers to some extent. It might take a longer time for hydrate dissociation at the bottom of the reservoir because EG solution in contact was diluted. To further analyze the migration characteristic of EG in the reservoir, the three-dimensional (3D) images of the boundaries and corresponding volume fractions of low-temperature regions at different times for runs 1−5 are depicted in Figure 7. Here, the low-temperature region refers to the region more than 3 K below its initial temperature. It reflects the main hydrate dissociation region, because only hydrate dissociation was endothermic in the reactor. Moreover, the hydrate dissociation was affected by the presence of EG solution; thus, the low-temperature region also reflects the covering region of EG solution to a certain extent. As shown in Figure 7, four images of each run are corresponding to four time points, which are the beginning of the production, the end of the EG injection stage, the middle time of the soaking stage, and the end of the soaking stage. At the initial time, the reservoir temperature was the same as the water bath temperature; thus, there was no low-temperature region. During the EG injection stage, the boundary of the low-temperature region expanded from the injection well along the direction of EG migration. The temperatures at different distances from the injection well declined successively. For example, the temperatures in the region close to the injection well would first decrease and then increase as a result of the injected heat of EG solution. Additionally, in the region far away from the injection well, the temperature would not decrease significantly as a result of the
ξt =
VC, t − VP, t mEG
(3)
where VC,t is the cumulative volume of gas production by the combination method (runs 1−5) at a specified time (t), VP,t is the cumulative volume of gas production by a single depressurization method (run 6) at a specified time (t), and mEG is the quality of injected pure EG; that is, EG efficiency is the volume increment of gas production influenced per gram of EG injection in the production process. When EG efficiency is negative, it indicates that the cumulative volume of gas production by the combination method is smaller than that by a single depressurization method at that time. Figure 8 shows the evolution of EG efficiency for runs 1−5. In the injection stage, EG efficiencies for runs 4 and 5 increased continuously to a peak value; however, for runs 1−3, EG efficiencies decreased first and then increased. This was mainly controlled by the EG injection rate and EG concentration. Although increasing the injection rate improved EG efficiency in this stage, most of the produced gas was not derived from the hydrate dissociation but displaced by the EG injection instead. Therefore, with regard to the injection rate, it was more important to consider the effect on EG distribution, which would affect the subsequent hydrate dissociation rate. In G
DOI: 10.1021/acs.energyfuels.8b01682 Energy Fuels XXXX, XXX, XXX−XXX
Article
Energy & Fuels
Figure 9. Evolution of EG efficiency with the ratio of (VG)t and (VG)end for runs 1−5.
Figure 8. Evolution of EG efficiency with time for runs 1−5.
the soaking stage, there was no gas production for runs 1−5; thus, EG efficiency decreased straightly until the end of this stage. On account of the different qualities of EG injection, there were slight differences in the slopes. In the depressurization stage, EG efficiencies for runs 1−3 rapidly increased to the peak values, which were 137.0, 171.6, and 132.6 mL/g, respectively. For runs 4 and 5, EG efficiencies continued to increase slowly after the rapid increase, of which the corresponding peak values were 136.0 and 133.6 mL/g, respectively. The results showed that, when pure EG was used, the maximum values of EG efficiency were basically the same, although the injection volume and rate were different. In addition, the maximum efficiency was obviously enhanced when EG solution had a concentration of 70 wt %. Then, EG efficiencies decreased over time until the end of gas production. The reason was that the gas production rate would be significantly reduced with the increase of the hydrate dissociation ratio in the later stage, which was mentioned in Figure 4. In Figure 8, the dotted lines mark the times for runs 1−5, after which there was no gas production. The corresponding EG efficiencies at the dotted lines were 92.5, 127.4, 81.9, 126.5, and 120.3 mL/g, respectively. The results indicated that EG efficiency could be enhanced by increasing the EG volume, increasing the injection rate, or decreasing the EG concentration to a certain extent. However, if excessive EG injection leads to the output of EG solution in the injection stage, the EG efficiency would decrease, as the result of run 5. Therefore, in the injection stage, the injection volume could be best when the EG solution just reached the production well, as the result of run 4. After the end of gas production, EG efficiencies gradually decreased to a stability value, which was the end of gas production by depressurization. Figure 9 shows the relationships between EG efficiency and the ratio of (VG)t and (VG)end for runs 1−5, where (VG)t is the cumulative volume of the produced gas at a specified time (t) and (VG)end is the cumulative volume of the produced gas at the end of gas production. It can be seen that the curves are stretched or contracted at different stages as a result of the change of the gas production rate compared to Figure 8. At the initial depressurization stage, the ratio of (VG)t and (VG)end for runs 1, 2, 3, 4, and 5 was 0.386, 0.354, 0.299, 0.282, and 0.308, respectively. The corresponding EG efficiencies were all
negative. Thereafter, EG efficiency increased with the ratio of (VG)t and (VG)end until reaching the peak value. The corresponding ratios at the peak value were between 0.7 and 0.9. In addition, after the peak value, the EG efficiencies of runs 4 and 5 decreased more slowly than those of runs 1−3. The results indicated that EG efficiencies could be maintained at a high level until the end of gas production for runs 4 and 5. However, for runs 1−3, after the ratio of (VG)t and (VG)end was >0.8, EG efficiency would be obviously reduced.
4. CONCLUSION The depressurization method for hydrate exploitation has been extensively researched for the characteristics of low cost and well applicability for large area mining. However, the low rate of hydrate dissociation leads to low production efficiency. Considering that EG can change hydrate equilibrium conditions, reduce hydrate decomposition heat, and suppress ice blocking, this work tried to combine EG injection and depressurization to enhance gas production with dual vertical wells. The gas production process was divided into three stages: EG injection stage, soaking stage, and depressurization stage. As expected, the results proved that the combination method could obviously improve gas production efficiency compared to a single depressurization method. Furthermore, the gas production rate could be enhanced by increasing the EG concentration, increasing the injection volume, or adjusting the injection rate appropriately. When the injection rate was slow, the hydrate dissociation ratio was higher in the EG injection stage but the total time for hydrate dissociation was longer. On the contrary, when a higher injection rate was used, the hydrate dissociation ratio was lower in the EG injection stage but the total time for hydrate dissociation had been shortened. The cause of the difference in the hydrate dissociation rate was related to the migration characteristics of EG in the reservoir. From analysis of the evolution of the low-temperature region, it is found that increasing the EG concentration and injection volume could enlarge the lowtemperature region, which indicated that EG had a larger impact range. Moreover, the acceleration of the injection rate dramatically changed the shape of the low-temperature region, so that EG could spread to affect a larger region in the H
DOI: 10.1021/acs.energyfuels.8b01682 Energy Fuels XXXX, XXX, XXX−XXX
Article
Energy & Fuels
Hydrate in Porous Sediment with Hot Brine Stimulation. Ind. Eng. Chem. Res. 2008, 47 (23), 9696−9702. (12) Li, B.; Liu, S. D.; Liang, Y. P.; Liu, H. The use of electrical heating for the enhancement of gas recovery from methane hydrate in porous media. Appl. Energy 2017, DOI: 10.1016/j.apenergy.2017.08.066. (13) Yuan, Q.; Sun, C.-Y.; Yang, X.; Ma, P.-C.; Ma, Z.-W.; Li, Q.-P.; Chen, G. J. Gas Production from Methane-Hydrate-Bearing Sands by Ethylene Glycol Injection Using a Three-Dimensional Reactor. Energy Fuels 2011, 25 (7), 3108−3115. (14) Yuan, Q.; Sun, C.-Y.; Yang, X.; Ma, P.-C.; Ma, Z.-W.; Liu, B.; Ma, Q.-L.; Yang, L.-Y.; Chen, G.-J. Recovery of methane from hydrate reservoir with gaseous carbon dioxide using a three-dimensional middle-size reactor. Energy 2012, 40 (1), 47−58. (15) Yang, J.; Okwananke, A.; Tohidi, B.; Chuvilin, E.; Maerle, K.; Istomin, V.; Bukhanov, B.; Cheremisin, A. Flue gas injection into gas hydrate reservoirs for methane recovery and carbon dioxide sequestration. Energy Convers. Manage. 2017, 136, 431−438. (16) Chong, Z. R.; Yang, S. H. B.; Babu, P.; Linga, P.; Li, X.-S. Review of natural gas hydrates as an energy resource: Prospects and challenges. Appl. Energy 2016, 162, 1633−1652. (17) Fan, S. S.; Zhang, Y. Z.; Tian, G. L.; Liang, A. D.; Li, D. Natural Gas Hydrate Dissociation by Presence of Ethylene Glycol. Energy Fuels 2006, 20, 324−326. (18) Wang, B.; Fan, Z.; Wang, P. F.; Liu, Y.; Zhao, J. F.; Song, Y. C. Analysis of depressurization mode on gas recovery from methane hydrate deposits and the concomitant ice generation. Appl. Energy 2017, DOI: 10.1016/j.apenergy.2017.09.109. (19) Zhou, S. W.; Zhao, J. Z.; Li, Q. P.; Chen, W.; Zhou, J. L.; Wei, N.; Guo, P.; Sun, W. Optimal design of the engineering parameters for the first global trial production of marine natural gas hydrates through solid fluidization. Nat. Gas Ind. 2018, 5, 118−131. (20) Yoneda, J.; Masui, A.; Konno, Y.; Jin, Y.; Egawa, K.; Kida, M.; Ito, T.; Nagao, J.; Tenma, N. Mechanical properties of hydratebearing turbidite reservoir in the first gas production test site of the Eastern Nankai Trough. Mar. Pet. Geol. 2015, 66, 471−486. (21) Suzuki, K.; Schultheiss, P.; Nakatsuka, Y.; Ito, T.; Egawa, K.; Holland, M.; Yamamoto, K. Physical properties and sedimentological features of hydrate-bearing samples recovered from the first gas hydrate production test site on Daini-Atsumi Knoll around eastern Nankai Trough. Mar. Pet. Geol. 2015, 66, 346−357. (22) China Extracts Natural Gas Hydrates in South Sea, 2017; http:// www.energy-business-review.com/news/china-extracts-combustibleice-in-south-china-sea-190517-5819046. (23) Konno, Y.; Jin, Y.; Shinjou, K.; Nagao, J. Experimental evaluation of the gas recovery factor of methane hydrate in sandy sediment. RSC Adv. 2014, 4, 51666−51675. (24) Demirbas, A. Methane hydrates as potential energy resource. Part 2Methane production processes from gas hydrates. Energy Convers. Manage. 2010, 51, 1562−1571. (25) Bai, Y.; Li, Q. Simulation of gas production from hydrate reservoir by the combination of warm water flooding and depressurization. Sci. China: Technol. Sci. 2010, 53, 2469−2476. (26) Song, Y. C.; Cheng, C. X.; Zhao, J. F.; Zhu, Z. H.; Liu, W. G.; Yang, M. J.; Xue, K. H. Evaluation of gas production from methane hydrates using depressurization, thermal stimulation and combined methods. Appl. Energy 2015, 145, 265−277. (27) Falser, S.; Uchida, S.; Palmer, A. C.; Soga, K.; Tan, T. S. Increased gas production from hydrates by combining depressurization with heating of the wellbore. Energy Fuels 2012, 26, 6259−6267. (28) Kurihara, M.; Sato, A.; Ouchi, H.; Narita, H.; Masuda, Y.; Saeki, T.; Fujii, T. Prediction of gas productivity from eastern Nankai Trough methane hydrate reservoirs. Spe Reserv. Eval. Eng. 2009, 12 (3), 477−499. (29) Sung, W.; Kang, H. Experimental Investigation of Production Behaviors of Methane Hydrate Saturated in Porous Rock. Energy Sources 2003, 25 (8), 845−856. (30) Li, G.; Li, X. S.; Tang, L. G.; Zhang, Y. Experimental investigation of production behavior of methane hydrate under
subsequent dissociation process. In addition, it was found that the maximum value of EG efficiency was mainly influenced by the EG concentration. The decrease of the EG concentration could increase the EG efficiency significantly. However, EG efficiency at the end of gas production could be enhanced by increasing the injection volume or injection rate. In particular, EG efficiencies could be maintained close to peak values until the end of gas production when an optimized injection rate was employed. Finally, this study reveals a combination method to enhance hydrate recovery efficiency, and more research is still required to further optimize the injection patterns.
■
AUTHOR INFORMATION
Corresponding Authors
*Fax: +861089739033. E-mail:
[email protected]. *Fax: +861089739033. E-mail:
[email protected]. ORCID
Guang-Jin Chen: 0000-0002-8454-2485 Chang-Yu Sun: 0000-0001-6931-6554 Notes
The authors declare no competing financial interest.
■
ACKNOWLEDGMENTS This work was financially supported by the National Natural Science Foundation of China (21636009, 51576209, and 51676207) and the National Key Research and Development Program of China (2016YFC0304003 and 2017YFC0307302).
■
REFERENCES
(1) Sloan, E. D. Fundamental principles and applications of natural gas hydrates. Nature 2003, 426, 353−359. (2) Rees, E. V. L.; Priest, J. A.; Clayton, C. R. I. The structure of methane gas hydrate bearing sediments from the Krishna−Godavari Basin as seen from Micro-CT scanning. Mar. Pet. Geol. 2011, 28, 1283−1293. (3) Zhao, X.; Deng, J.; Li, J.; Lu, C.; Song, J. Gas hydrate formation and its accumulation potential in Mohe permafrost, China. Mar. Pet. Geol. 2012, 35 (1), 166−175. (4) Makogon, Y. F. Natural gas hydratesA promising source of energy. J. Nat. Gas Sci. Eng. 2010, 2, 49−59. (5) Makogon, Y. F.; Holditch, S. A.; Makogon, T. Y. Natural gashydratesA potential energy source for the 21st century. J. Pet. Sci. Eng. 2007, 56, 14−31. (6) Lu, S. M. RETRACTED: A global survey of gas hydrate development and reserves: Specifically in the marine field. Renewable Sustainable Energy Rev. 2015, 41 (4), 884−900. (7) Yang, X.; Sun, C.-Y.; Su, K.-H.; Yuan, Q.; Li, Q.-P.; Chen, G.-J. A three-dimensional study on the formation and dissociation of methane hydrate in porous sediment by depressurization. Energy Convers. Manage. 2012, 56 (2), 1−7. (8) Kono, H. O.; Narasimhan, S.; Song, F.; Smith, D. H. Synthesis of methane gas hydrate in porous sediments and its dissociation by depressurizing. Powder Technol. 2002, 122 (2−3), 239−246. (9) Yuan, Q.; Sun, C.-Y.; Wang, X.-H.; Zeng, X.-Y.; Yang, X.; Liu, B.; Ma, Z.-W.; Li, Q.-P.; Feng, L.; Chen, G.-J. Experimental study of gas production from hydrate dissociation with continuous injection mode using a three-dimensional quiescent reactor. Fuel 2013, 106 (4), 417− 424. (10) Yang, X.; Sun, C. Y.; Yuan, Q.; Ma, P. C.; Chen, G. J. Experimental Study on Gas Production from Methane HydrateBearing Sand by Hot-Water Cyclic Injection. Energy Fuels 2010, 24 (11), 5912−5920. (11) Li, X.-S.; Wan, L.-H.; Li, G.; Li, Q.-P.; Chen, Z.-Y.; Yan, K.-F. Experimental Investigation into the Production Behavior of Methane I
DOI: 10.1021/acs.energyfuels.8b01682 Energy Fuels XXXX, XXX, XXX−XXX
Article
Energy & Fuels ethylene glycol injection in unconsolidated sediment. Energy Fuels 2007, 21, 3388−3393. (31) Kawamura, T.; Yamamoto, Y.; Ohtake, M.; Sakamoto, Y.; Haneda, H.; Komai, T. Experimental study on dissociation of hydrate core sample accelerated by thermodynamic inhibitors for gas recovery from natural gas hydrate. Proceedings of the Fifth International Conference on Gas Hydrates; Trondheim, Norway, June 13−16, 2005. (32) Fan, S.; Zhang, Y.; Tian, G.; Liang, A. D.; Li, D. Natural gas hydrate dissociation by presence of ethylene glycol. Energy Fuels 2006, 20, 324−326. (33) Aminnaji, M.; Tohidi, B.; Burgass, R.; Atilhan, M. Effect of injected chemical density on hydrate blockage removal in vertical pipes: Use of MEG/MeOH mixture to remove hydrate blockage. J. Nat. Gas Sci. Eng. 2017, 45, 840−847. (34) Dong, F.; Zang, X.; Li, D.; Fan, S.; Liang, D. Experimental investigation on propane hydrate dissociation by high concentration methanol and ethylene glycol solution injection. Energy Fuels 2009, 23, 1563−1567. (35) Yousif, M. H. Effect of under inhibition with methanol and ethylene glycol on the hydrate-control process. SPE Prod. Facil. 1998, 13 (3), 184−189. (36) Liang, J.; Wang, H.; Xin, S.; Fu, S. Y.; Wang, L. F.; Guo, Y. Q.; Shang, J. J. Natural gas hydrate formation conditions and the associated controlling factors in the northern slope of the South China Sea. Nat. Gas Ind. 2014, 5 (26), 218−221. (37) Wang, X. H.; Sun, Y. F.; Wang, Y. F.; Li, N.; Sun, C. Y.; Chen, G. J.; Liu, B.; Yang, L. Y. Gas production from hydrates by CH4− CO2/H2 replacement. Appl. Energy 2017, 188, 305−314. (38) Sun, Y. F.; Zhong, J. R.; Li, R.; Zhu, T.; Cao, X. Y.; Chen, G. J.; Wang, X. H.; Yang, L. Y.; Sun, C. Y. Natural gas hydrate exploitation by CO2/H2 continuous injection−production mode. Appl. Energy 2018, 226, 10−21.
J
DOI: 10.1021/acs.energyfuels.8b01682 Energy Fuels XXXX, XXX, XXX−XXX
