Influence of Hydrate Saturation on Methane Hydrate Dissociation by

Article pubs.acs.org/EF

Influence of Hydrate Saturation on Methane Hydrate Dissociation by Depressurization in Conjunction with Warm Water Stimulation in the Silica Sand Reservoir Jing-Chun Feng,†,‡,§ Yi Wang,†,‡ Xiao-Sen Li,*,†,‡ and Yu Zhang†,‡ †

Key Laboratory of Gas Hydrate, Guangzhou Institute of Energy Conversion, Chinese Academy of Sciences, Guangzhou 510640, P. R. China ‡ Guangzhou Center for Gas Hydrate Research, Chinese Academy of Sciences, Guangzhou 510640, P. R. China § University of Chinese Academy of Sciences, Beijing 100083, P. R. China ABSTRACT: In this study, the different saturations of hydrate samples were formed in a cubic hydrate simulator (CHS) filled with silica sand. Subsequently, the hydrate was dissociated by depressurization in conjunction with warm water stimulation using dual horizontal wells. The hydrate dissociation process includes the depressurizing period and the injection period (the constantpressure period). Hydrate was dissociated simultaneously in the whole reservoir during the depressurizing period. Meanwhile, gas production in the depressurizing period is mainly determined by the depressurizing rate, and it has little relation to the hydrate saturation (when the hydrate saturation ranges from 15.5% to 39.1%). During the injection period, more gas can be produced for the reservoir with the higher hydrate saturation, whereas the highest average gas production rate can be obtained for the reservoir with the middle-higher hydrate saturation. With respect to the gas production in the depressurizing period, gas production in the injection period is the dominant factor affecting the whole production efficiency in the experiment. In addition, the energy ratio only increases with the increase of the hydrate saturation in the prior stage of the constant-pressure period, and the final energy ratio with the middle-higher hydrate saturation is the maximum. Moreover, energy analysis indicates that heat injection plays the leading role for hydrate dissociation in the constant-pressure production period when the initial hydrate saturation is higher than 32.4%. and it has been successfully implemented in the field test of the offshore hydrate exploitation in the Nankai Trough18 and the onshore hydrate exploitation in the Mackenzie Delta.19 However, the single depressurization is ineffective in the cold hydrate deposit which is characterized as very low sensible heat. Moreover, the single depressurization is unsuitable in the following conditions as well: the absence of low permeability boundaries, the reservoir with low permeability, and the reservoir with the infeasibility of conducting large pressure drop.20 The efficiency of thermal stimulation is limited because the heat absorption of the dissociated water and the heat loss during the transmission of the injected water in the reservoir.21 The problems of the inhibitor stimulation are the high cost, the difficulty of recovering the inhibitors, and the limited effectiveness of the inhibitors.22 Therefore, the combination of thermal stimulation and depressurization is more plausible, and it has been validated by the experimental results of Li et al.23 Feng et al.24,25 further reported that the depressurization in conjunction with warm water stimulation was a favorable method for hydrate dissociation in the sandy reservoir. Thus, the depressurization combined with warm water stimulation was applied for hydrate dissociation in this work. The sample analysis indicates that natural gas hydrate exists as the following types in the in-place hydrate sediment:4 pore-

1. INTRODUCTION Natural hydrate is considered to be a new potential energy and has attracted extensive attention of the worldwide scientists on account of its enormous carbon content, which is twice as much as the conventional fossil energy.1 Under the favorable condition of high pressure and low temperature, natural gas hydrate exists as an ice-like solid in the seafloor sediment and arctic permafrost areas.2 Methane is the most common guest molecule in the natural gas hydrate, and a huge amount of methane, between 2.0 × 10 14 and 1.2 × 10 17 m3 (STP), is estimated to be trapped in the natural gas hydrate.3 Although the total reserves of the natural gas hydrate in the field is rich, there are extreme challenges and uncertainties for exploiting natural gas hydrate from the marine sediment due to the challenges in well log, sampling and sample analysis, interpretation of geophysical surveys, mechanical stability of the reservoir, well design, field operation, and so on.4 Until now, except for the small-scale field experiments, methane production from the natural hydrate reservoir has not been documented. Recovering natural gas from the hydrate accumulation necessitates in situ hydrate dissociation. Depressurization,5,6 thermal stimulation,7−10 inhibitor (such as salts and alcohols) stimulation,11,12 and carbon dioxide replacement13,14 are the four primary methods applied for dissociating the natural gas hydrate. Due to low energy cost and easy operation, depressurization has been widely used for hydrate dissociation in laboratory-scale experiment15,16 and numerical simulation,17 © 2015 American Chemical Society

Received: August 31, 2015 Revised: October 10, 2015 Published: November 9, 2015 7875

DOI: 10.1021/acs.energyfuels.5b01970 Energy Fuels 2015, 29, 7875−7884

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Energy & Fuels

Figure 1. Schematic of experimental apparatus.

Figure 2. Schematic of interior structure of the CHS, well design, and distributions of thermal couples.

filling hydrate occupying the coarse-grained sand, massive block hydrate with little sediment, grain-displacing hydrate as a form of nodules, veins, and fracture-filled gas hydrate. The investigation of Boswell et al.26 indicates that gas hydrate within the sand reservoirs is the only potential producible hydrate form, which can achieve the level of commercial production under the current technological condition. In addition to the geological features such as the temperature, pressure, and intrinsic permeability of the sediment, the producible ability of the hydrate reservoir is strongly dependent on the hydrate saturation of the hydrate accumulation.27 The hydrate saturation not only influences the intrinsic permeability of the reservoir but also affects the capillary pressure and fluid flow in the reservoir. The simulation results show that the middle-higher hydrate saturations (30−60%) are favorable for the movement of pore fluids, and they are recognized as the desirable hydrate targets.27 However, up to now, few experimental investigations have focused on the effects of hydrate saturation on hydrate dissociation behaviors, especially the hydrate dissociation with the horizontal wells.

In this work, the hydrate samples with different hydrate saturations were formed in a sand-filling cubic hydrate simulator. The pressure and temperature of the hydrate sample were consistent with the geological conditions of the hydrate in the South China Sea.28 Then, the hydrate samples were dissociated by depressurization in conjunction with warm water stimulation using the dual horizontal wells. The effects of the hydrate saturation on gas production, energy ratio, and temperature spatial distribution were investigated. Moreover, the analysis of the ratio of the heat from water injection to the heat absorbing from the environment was analyzed.

2. EXPERIMENTAL SECTION 2.1. Apparatus. Figure 1 gives the schematic of the experimental apparatus. The detailed information on the apparatus has been introduced in the previous work.29−31 The core of the experimental section is a 5.832 L cubic hydrate simulator (CHS), which is made of stainless steel. The CHS can sustain pressure as high as 30 MPa. A water bath (−15−30 °C ± 0.1 °C) is used for maintaining the stability of the temperature in the CHS. There are two gas flow meters, which are used for measuring the injected and the produced amount of gas 7876


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Energy & Fuels Table 1. Formation Conditions and Results of Methane Hydrate in the CHS runs

T0 (°C)

P0 (MPa)

VG,inj (L)

mW,inj (g)

Pend (MPa)

bath temperature(K)

pore volume (mL)

1 2 3

282.24 282.01 282.72

15.99 19.96 20.40

400.36 412.92 343.97

462.94 52.21 819.19

13.48 13.48 13.48

281.15 281.15 281.15

2752 2752 2752

aqueous phase, respectively. vm stands for the molar volume of the gas (mL/mol), determined by the fugacity model of Li et al.36 nm0 and mW,inj are the total amount of the injected methane (mol) and injected water (g) in the CHS. NH is the hydration number of the hydrate. MH and MW are the molar mass of the hydrate and water, respectively. ρH and ρW represent the densities of the hydrate and the water, respectively. The determination of the three phase saturation with respect to hydrate dissociation is expressed as follows:

during the experiment. The pressure in the CHS is measured simultaneously by two pressure transducers located at the top and bottom of the CHS, respectively. The working pressure is controlled by a back-pressure regulator (0−30 MPa ± 0.2 MPa, fabricated by the Nantong FeiYu Company), which is situated at the outlet. Water injection is implemented by a metering pump (0−50 mL/min ± 0.1 mL/min, from the Beijing ChuangXin Tongheng Company). The quantity of the water production is measured by a balance made by Sartorius (0−3100 ± 0.01 g). The parameter changes are gathered by the data acquiring system every 20 s during the experiment. Figure 2 shows the schematic of the inner structure in the CHS, the well configuration, and the distribution of the thermal couples. As seen, the z-axis of the CHS can be evenly divided into four sections by three horizontal layers (Layer A, B, and C). There are five thermal couples on both the x-axis and y-axis of each horizontal layer. There are a total of 75 (5 × 5 × 3 = 75) couples in the CHS. The 25th thermal couple located on layer A is named as T25 A, and the naming rule of the rest of the thermal couples is similar to T25 A. The dual horizontal wells are set as the well configuration during the dissociation experiment. Well HC is used as the injection well, and Well HA is performed as the production well. The repeatability of the experiments has been verified in our previous work.9,23−25,29−31 2.2. Process. Before hydrate formation, 8162 g silica sands were tightly packed in the CHS, making the porosity of the reactor as 48%. The particle diameter of the silica sand is about 300 to 450 μm. In order to expulse the residual air, the CHS was pressurized to approximately 1 MPa by methane injection, and then it was depressurized. After inflating and discharging methane three times, preweighed deionized water was injected into the CHS, and then pure methane was pumped into the CHS to pressurize it to the desired pressure. Then the inlet and outlet value were closed, and the temperature of the water bath was set as 281.15 K. Hydrate formation occurred with the reduction of the system pressure. When the system pressure decreased to 13.5 MPa, the hydrate formation process finished. The detailed condition of hydrate formation was summarized in Table 1. After the completion of hydrate formation, the dissociation process started. First, the outlet valve was opened, and the produced fluid flowed out from Well HA by depressurization. The back-pressure regulator was set as 4.7 MPa. Warm water was injected into the CHS from Well HC simultaneously when the system pressure decreased to 4.7 MPa. The dissociation experiment was terminated when there is no more gas produced from the CHS. 2.3. Determination of Hydrate Saturation. The relationship of the gas saturation (SG), water saturation (SW) and hydrate saturation (SH) in the CHS follows the following rule: SG + S W + SH = 1

SH = SH0(1 − φ) SG =

SH =

NHMW ρH SH0k MH

−

(6) mW ρW Vpore

(7)

3. RESULTS AND DISCUSSION In this work, three experimental runs with different hydrate saturation were carried out. The detailed experimental condition and results were shown in Table 2. The initial hydrate saturation with hydrate dissociation for run 1, 2, and 3 is 15.5%, 32.4%, and 39.1%, respectively. Table 2. Experimental Conditions and Results of Methane Hydrate Dissociation in the CHS depressurizing period

injection period

mW,inj − NH(nm0 − nm,G − nm,W )MW

initial hydrate saturation duration (min) depressurizing rate (MPa/min) cumulative gas production (L) average gas production rate(L/min) working pressure (MPa) injection rate (mL/min) initial hydrate saturation duration (min) cumulative gas production (L) average gas production rate(L/min)

run 1

run 2

run 3

15.5% 20.58 0.087

32.4% 20.25 0.089

39.1% 17.33 0.104

69.19

77.60

96.20

3.39

3.83

5.56

4.70 20.00 12.6% 163.67 61.75

4.70 20.00 25.0% 230.43 129.29

4.70 20.00 28.0% 296.40 145.41

0.38

0.56

0.49

(3)

3.1. Dissociation Procedure. As an example, Figure 3 shows the evolutions of the system pressure and temperature for the dissociation experiment with the hydrate saturation of 32.4%. As shown in Figure 3, Teq represents the equilibrium dissociation temperature corresponding to the system pressure. Tave is the average temperature of all the temperature measuring

(nm0 − nm,G − nm,W )MH ρH Vpore

Vpore

where SW0 and SH0 are the water and hydrate saturation before hydrate dissociation, respectively. NH is the hydration number. nm01 is the total mole of the free gas before hydrate dissociation. vmp is the molar volume of gas in the state of gas production. φ is the percentage of the dissociated hydrate. mW and Vp are the accumulative amount of water production (g) and gas production (L).

(1)

ρW Vpore

(nm01 + SH0VporekρH /MH − nm,w − VP/vmp)vm

S W = S W0 +

The three phase saturation with regard to hydrate formation is determined by the following equations:32−35 vmnm,G SG = Vpore (2)

SW =

(5)

(4)

where Vpore is the pore space of the CHS. Vpore is tested as 2752 mL by using water injection. nm,G and nm,W are the molar amount of the methane in gas phase in the CHS and the dissolved methane in 7877


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equal to the dissociation temperature, which illustrates that the hydrate near point 8B is undissociated during this period. T8B increases gradually from point C, indicating that the hydrate at point 8B starts to be dissociated. T(8A) do not increase until from point D (t = 140 min), which demonstrates that the dissociation boundary moves to point 8A when t = 140 min. In a word, by using the depressurization in conjunction with warm water stimulation with the dual horizontal wells, the hydrate dissociation propagates as a way of moving boundary problem, and the dissociation boundary transfers from the lower part in the CHS to the upper layer. 3.2. Gas Production. Figure 4 shows the evolution of the cumulative volume of gas production over time during the

Figure 3. Pressure and average temperature during hydrate dissociation for run 2.

points. T(8A), T(8B), and T(8C) are the temperatures at the measuring point of 8A, BB, and 8C, respectively. During all the experimental runs, there is little difference of the pressures at different measuring points of the CHS on account of the high porosity and permeability of the sandy reservoir.37 Therefore, the pressure at any point can be regarded to be the system pressure. As shown in Figure 3, the hydrate dissociation process can be divided into the depressurizing period and the injection period (constantpressure period). Before the beginning of hydrate dissociation, the free gas in the CHS was discharged, and the system pressure reduced from the initial point to point A. During this stage, the system pressure was higher than the equilibrium dissociation pressure, and thus, there is no hydrate dissociation in the CHS. The system temperature first decreases, which is caused by the Joule−Thomson effect,5 and then it increases due to the heat release of hydrate-reformation.24 Point A is regarded to be the starting point of hydrate dissociation. As shown in Figure 3, the system temperature is lower than the equilibrium temperature before point A, which is favorable for the stability of hydrate. The system temperature and pressure at point A are 281.81 K and 6.47 MPa, respectively. The equilibrium dissociation temperature corresponding to the system pressure is 281.87 K using the fugacity model of Li et al.,36 which is good agreement with the system temperature. The depressurizing period lasts from 0 to 20.25 min. The system pressure in this period decreases from 6.47 to 4.70 MPa, and the equilibrium dissociation temperature decreases correspondingly. The sensible heat of the reservoir provides energy for hydrate dissociation, and the system temperature decreases due to the cooling effect of hydrate dissociation. During the injection period (from point B to the end of the experiment), the system pressure is maintained at 4.7 MPa controlled by the back pressure regulator. Therefore, the hydrate equilibrium dissociation temperature approximately keeps constant, which is shown in Figure 3. During this period, the system temperature increases continuously under the effect of the heat convection caused by water injection and the heat conduction in the silica reservoir. The temperature at point 8C increases instantly when the warm water was injected into the CHS, indicating that the hydrate near this point is dissociated quickly under the effect of thermal stimulation. Before point C (t = 70 min), the temperature at point 8B keeps stable, and it is approximately

Figure 4. Cumulative volume of gas production for runs with different hydrate saturation.

hydrate dissociation process for runs 1−3. It is noted that the total cumulative volume of the produced gas for runs 1−3 are 130.99, 206.89, and 241.61 L, respectively. This indicates that the recoverable amount of gas increases with the increase of hydrate saturation. Figure 4 shows that the difference of gas production for runs with the different hydrate saturations during the depressurizing period is inconspicuous. As shown in Table 2, the depressurizing rate for runs 1−3 are 0.087, 0.089, and 0.104 MP/min, respectively. Figures 5 and 6 give the final cumulative volume of produced gas and the average gas

Figure 5. Final cumulative volume of gas production during depressurizing period and injection period. 7878


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cumulative volume of gas production and the time required for the completion of hydrate dissociation increase with the increment of hydrate saturation. The total cumulative volume of the produced gas for runs 1−3 during this period is 61.75, 129.29, and 145.41 L, respectively. The corresponding average gas production rate is 0.38, 0.56, and 0.49 L/min, respectively. When the hydrate saturation increases from 12.6% to 25.0%, the increment of the gas production rate is 47.37%. However, the gas production rate reduces 12.5% when the hydrate saturation increases from 25.0% to 28.0%.This is because the duration for the completion of hydrate dissociation for run 3 is much longer. This indicates that the higher hydrate saturation may be not more economical. The reasons may be the intrinsic permeability of the reservoir reduces with the increase of hydrate saturation, and the heat transfer rate correspondingly decreases. As seen from Figure 6, the ratio of the average gas production rate in the depressurizing period to that in the injection period for runs 1−3 is 8.98, 6.84 and 11.34, respectively. It indicates that the gas production rate in the depressurizing period is far larger than that in the injection period. The lower gas production rate in the injection period decreases the whole production efficiency in the experiment. Therefore, the gas production performance in the injection period is the dominant factor affecting the whole production efficiency. 3.4. Temperature Spatial Distribution. Figure 8 gives the spatial distribution of temperature in the reservoir over time for run 2. Figure 8a,b show the spatial distribution of temperature in the reservoir after hydrate formation and the temperature at the beginning of the depressurizing period, respectively. The temperature at different points of the reservoir in Figure 8b is almost the same with that in Figure 8a, which confirms the above-mentioned conclusion that there is no hydrate dissociation before point A in Figure 3. Figure 8c depicts the temperature spatial distribution at 20.25 min, which is the starting point of the injection period (point B in Figure 3). The temperatures in Figure 8c decreases drastically to the lowest temperature, which is due to the cooling effect of depressurization, compared to that in Figure 8b. The decline degree of temperature at each point is almost the same, indicating that the hydrate is dissociated simultaneously in the whole reservoir. Figure 8d shows the temperature spatial distribution at 70 min, which is the initial time when the temperature at point 8B is higher than the equilibrium dissociation temperature (point C shown in Figure 3). It indicates that in the lower part of the reservoir, the hot temperature region caused by water injection spreads along the injection well. The temperatures around the injection well is already higher than the equilibrium temperature, representing that the hydrate in these areas has been dissociated. The temperatures in the areas along the injection well is higher than that perpendicular to the injection well. It manifests that the effect of heat convection caused by water injection is stronger than that of heat conduction through the porous media. The temperatures in the upper part is still lower than the equilibrium dissociation temperature, which indicates that the hydrate in the upper part of the reservoir keeps undissociated. Figure 8e shows the temperature spatial distribution at 140 min, which is the initial time when the temperature at point 8A is higher than the equilibrium temperature. It illustrates that except the top and corner region, the temperatures in the reservoir is already higher than the equilibrium dissociation temperature. It can be found that under the effect of

Figure 6. Average gas production rate during depressurizing period and injection period.

production rate during the depressurizing period and the injection period, respectively. The cumulative volumes of gas production for runs 1−3 during the depressurizing period is 69.19, 77.60, and 96.20 L, respectively. The corresponding average gas production rate is 3.39, 3.83, and 5.56 L/min, respectively. The hydrate saturation for run 2 is approximately twice as that for run 1, whereas the difference of the gas production rate for the two runs is very small. This indicates that the gas production in the depressurizing period is mainly controlled by the depressurizing rate rather than the hydrate saturation. The cumulative volume of produced gas and the average gas production rate both increase with the rise of depressurizing rate. To investigate into the gas production performance in the injection period, the evolution of the cumulative volume of gas production during the injection period is shown in Figure 7.

Figure 7. Evolution of cumulative volume of gas production during injection period for runs with different hydrate saturation.

Recall the time zero as the initial point of hydrate dissociation (point A in Figure 3). As shown in Table 2, the initial hydrate saturation in the injection period for runs 1−3 is 12.6%, 25.0%, and 28.0%, respectively. It is shown that during the initial 10 min, there is little difference between the gas production rate with different hydrate saturations. Subsequently, the difference of gas production for the experiments with different hydrate saturation gradually emerges. It is noted that the final 7879


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Figure 8. Spatial distribution of temperature in the CHS over time for run 2.

Figure 9. (a) Spatial distribution of temperature in the CHS at the end of the depressurizing period for different runs. (b) Spatial distribution of temperature in the CHS at the end of the injection period for different runs.

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Energy & Fuels depressurization in conjunction with warm water stimulation, the hydrate dissociation front moves from the lower part to the upper part of the reservoir. The temperature spatial distribution for run 1 and run 3 is similar to run 2, because the experimental process is similar for all the experimental runs. Figure 9a gives the temperature spatial distribution at the end of the depressurizing period for different runs. As seen, for all the experimental runs, the temperatures in the near-wall region is higher than that in the central region. This is because during the depressurizing period, the sensible heat of the reservoir is consumed for hydrate dissociation, and the heat from the environment is transferred into the reservoir through the boundary. It is shown that the temperature in the near-wall region increases with the reduction of hydrate saturation, because the heat consuming for hydrate dissociation with the lower hydrate saturation is lower. In addition, the heat from the environment has been transferred into the inner-wall region, causing the increase of temperature in these areas. Figure 9b shows the temperature spatial distribution at the end of the injection period for different experimental runs. It is noted that for different experimental runs, the temperatures in the whole reservoir are approximately higher than the equilibrium dissociation temperature, indicating that the hydrate in the CHS can be dissociated completely by using the depressurization in conjunction with thermal stimulation using dual horizontal wells. As seen, the temperatures in the central region increases with the reduction of hydrate saturation. This results from the following reasons: (i) the heat consumption for hydrate dissociation is lower with the lower hydrate saturation, and less energy is required for hydrate dissociation; (ii) the permeability of the reservoir reduces with the increase of hydrate saturation, causing the decrease of the heat convection rate; (iii) the thermal resistance of the reservoir increase of hydrate saturation, resulting in the decrease of the heat conduction rate. 3.5. Energy Ratio. In this work, the energy ratio in the injection period is evaluated. Energy ratio is an indicator to assess the production efficiency of gas production from the hydrate-bearing reservoir, which means the ratio of the obtained energy to the total input energy. A higher energy ratio stands for a better production efficiency. The energy ratio can be defined as the following equation: η=

Figure 10. Evolution of energy ratio over time during injection period for runs with different hydrate saturation.

of the input energy for run 3 is wasted rather than applied for hydrate dissociation. In a word, generally, the energy ratio increases with the increase of hydrate saturation in the prior phase of the injection period. However, the experimental run with the highest hydrate saturation obtains a lower final energy ratio than that with the middle-higher hydrate saturation. 3.6. Energy Analysis. During the injection period, the heat supplied for hydrate dissociation stems from the environment and the heat provided by water injection. In order to analyze the contribution of heat source, the ratio of the heat from water injection to the heat absorbing from the environment is described as eq 9: R=

Q env

(9)

where Qinj and Qenv are the heat from water injection and the heat absorbing from the environment, respectively. During the injection period, the energy balance equation for the whole system is as follows: Q h + Q res + Q inj + Q env + Q gp + Q wd = 0

(10)

The detailed calculation methods for each term in Figure 10 are described as the following description, in which Qh is the heat provided for hydrate dissociation:

VpMgas Cwm w (Tinj − Tenv ) + Ppump

Q inj

Q h = NhΔHh

(8)

(11)

where Nh is the mole of the dissociated hydrate. ΔHh is the dissociation heat of hydrate, which is 54.1 kJ/mol.38 Qres is the heat supplied for heating the reservoir:

where Mgas (890.3 kJ/mol) is the combustion heat of the produced methane. VP is the cumulative volume of gas production. Cw is the specific heat of water. As the production pressure is kept as 4.7 MP, therefore, the Cw in this work is regarded as constant (4.167 × 103 kg/m3). mw stands for the cumulative mass of the injected water during the experiment. Tinj is temperature of the injected water, and Tenv is the temperature of the environment. PPump represents the working power of the metering pump. Figure 10 gives the changes of energy ratio over time during the injection period for different experimental runs. As shown in Figure 10, the energy ratio for run 1 is the lowest because of the least amount of produced methane. In the initial 160 min, the energy ratio for run 3 is higher than that for run 2. While thereafter, the difference of energy ratio between the two runs gets smaller, and the final energy ratio for run 3 is lower than that for run 2. This is because in the later period, the majority

Q res = (Csms + Cgmgo + Cwm wo)(T2 − T0)

(12)

where Cx is the specific heat. The subscript s, g, and w represent sand, gas, and water, respectively. ms, mgo, and mwo are the mass of sand, original gas, and original water in the reservoir before water injection. T0 and T2 are the temperature of the reservoir at the initial and the ending point of water injection. In order to calculate the temperature in the reservoir as accurately as possible, the sand, gas, and water are considered to be uniformly distributed in the reservoir. The mass of sand, gas, and water can be evenly divided into 75 tiny parts. The temperature distribution in each tiny part is uniform, additionally, and the center of each tiny part is regarded to be the situation of the local thermal couple (a total of 75 7881


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Energy & Fuels thermal couples displayed in Figure 2). Consequently, the temperature of the local thermal couple represents the temperature of each tiny part, and eq 12 can be transformed to eq 13: j = 75

∑ (Csms,j + Cgmgo,j + Cwmwo,j)(T2,j − T0,j)

Q res =

j=1

(13)

Qinj is the amount of heat from water injection. The amount of the injected water is divided to two parts: the water remaining in the reservoir and the water removed through production. Therefore, the heat from water injection is described as follows: Q inj = Cwm ws(T2 − T1) + Cwm wp(T3 − T1)

(14)

Figure 11. Ratio of amount of injection heat to amount of heat absorbing from environment.

where mws and mwp are the mass of the water remaining in the reservoir and the water removed through production, respectively. T1 and T3 are the temperature of the injected water and the temperature at the outlet, respectively. The temperature at the outlet changes over time. It is assumed that the temperature at the outlet is invariable during a very short period. The amount of water production during this period is very small, which can be described as mwp,i. Thus, eq 14 can be rewritten as the following equation. j = 75

Q inj =

hydrate saturation, indicating that more heat from water injection is required for the complete dissociation of hydrate with the increase of hydrate saturation. By dividing the value of R for a different experimental run by that for run 1, the normalized R for different runs can be acquired. The normalized R for runs 1−3 is 1, 2.49, and 8.35, respectively. As shown in Table 2, although the difference of hydrate saturation for run 2 and run 3 is only 3% in the injection period, the normalized R for run 3 is 3.35 times larger than that for run 2. This indicates that heat injection plays the leading role for hydrate dissociation in the constant-pressure production period when the initial hydrate saturation is higher than 32.4%. Without heat injection, the production efficiency for the completion of hydrate dissociation during the constantpressure stage can be very low, which agrees well with the previous investigation of hydrate dissociation by pure depressurization.5

i=n

∑ Cwmws,j(T2,j − T1) + ∑ Cwmwp,i(T3,i − T1) j=1

i=1

(15)

Qwd is the amount of heat applied for heating the dissociated water. The water originating from hydrate dissociation is considered to be remaining in the reservoir. As shown in Table 1, the pore volume of the reservoir is 2752 mL, which is far larger than the amount of water from hydrate dissociation (the volume of water from hydrate dissociation is 654.5 g). Thus, this assumption is reasonable, and the heat applied for heating the dissociated water is described as eq 16:

4. CONCLUSIONS In this work, depressurization in conjunction with warm water stimulation was employed for hydrate dissociation in a 5.8 L three-dimensional experimental apparatus. The effect of hydrate saturation on hydrate dissociation behaviors in the porous media with silica sand was investigated. The conclusions can be drawn as follows: (1) The dissociation procedure consists of the depressurizing period and the injection period (constant-pressure period). The effect of hydrate saturation (ranges from 15.5% to 39.1%) on gas production in the depressurizing period is inconspicuous, and the gas production in this period is mainly controlled by the depressurizing rate. Increasing the hydrate saturation can improve the cumulative volume of produced gas, whereas the experimental run with the middle-higher hydrate saturation obtains the highest average gas production rate. (2) With respect to the gas production in the depressurizing period, the gas production in the injection period is the dominant factor affecting the whole production efficiency in the experiment. (3) During the depressurizing period, the temperature in the whole reservoir decreases simultaneously caused by the cooling effect of hydrate dissociation. Moreover, for different experimental runs, the temperature reduction

j = 75

Q wd = Cwm wd (T3 − Tequ) =

∑ Cwmwd,j(T3,j − Tequ) j=1

(16)

Qgp is the amount of heat applied for gas production: i=n

Q gp = Cgmgp(T3 − Tequ) =

∑ Cgmgp,i(T3,i − Tequ) i=1

(17)

where mgp is the mass of the produced water. Combining eqs 10, 11, 13, 15, 16, and 17, the result is eq 18: j = 75

Q env = − [NhΔHh +

∑ (Csms,j + Cgmgo,j + Cwmwo,j)(T2,j − T0,j) j=1

j = 75

+

j=1 i=n

+

i=n

∑ Cwmws,j(T2,j − T1) + ∑ Cwmwp,i(T3,i − T1) i=1 j = 75

∑ Cgmgp,i(T3,i − Tequ) + ∑ Cwmwd,j(T3,j − Tequ)] i=1

j=1

(18)

Therefore, the value of R can be obtained by solving the eqs 9, 15, and 18 simultaneously. Figure 11 gives the ratio of the amount of heat from heat injection to the amount of heat absorbing from the environment for runs with different hydrate saturation. As seen, the value of R increases with the rise of 7882


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degree in different regions is similar. In the injection period, the heat convection rate and heat conduction rate decrease with the increase of hydrate saturation. (4) The energy ratio increases with the increase of hydrate saturation in the prior phase of the injection period. However, the energy ratio with the highest hydrate saturation is lower than that with the middle-higher hydrate saturation. (5) Heat injection plays the leading role for hydrate dissociation in the constant-pressure production period when the initial hydrate saturation is higher than 32.4%. In addition, more heat from water injection is required for the complete dissociation of hydrate with the increase of hydrate saturation.

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AUTHOR INFORMATION

Corresponding Author

*(X.-S.L.) E-mail: [email protected]. Tel.: +86-20-87057037. Fax: +86-20-87034664. Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS This work is supported by National Science Fund for Distinguished Young Scholars of China (51225603), National Natural Science Foundation of China (51406210 and 51476174), Key Arrangement Programs of the Chinese Academy of Sciences (KGZD-EW-301-2), and International S&T Cooperation Program of China (2015DFA61790) which are gratefully acknowledged.

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