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Numerical analysis of gas production from reservoir-scale methane hydrate by depressurization with a horizontal well: The effect of permeability anisotropy
Marine and Petroleum Geology 102 (2019) 817–828
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Research paper
Numerical analysis of gas production from reservoir-scale methane hydrate by depressurization with a horizontal well: The effect of permeability anisotropy
T
Yongchang Fenga,∗, Lin Chenb, Anna Suzukia, Takuma Kogawac, Junnosuke Okajimaa, Atsuki Komiyaa, Shigenao Maruyamaa,c a b c
Institute of Fluid Science, Tohoku University, Sendai, 980-8577, Japan Institute of Engineering Thermophysics, Chinese Academy of Sciences, Beijing, 100190, China National Institute of Technology, Hachinohe College, Tamonoki, 039-1192, Japan
A R T I C LE I N FO
A B S T R A C T
Keywords: Methane hydrate Permeability anisotropy Depressurization Horizontal well Gas production
Methane hydrate (MH) is regarded as one of the potential and substantial energy resources. The permeability of hydrate-bearing layer (HBL) can potentially influence heat and mass transfer during hydrate dissociation by depressurization. In this study, a reservoir-scale MH model was constructed to investigate the effect of permeability anisotropy on gas production behaviors by depressurization with a horizontal well. The numerical results indicate that permeability anisotropy can initially negatively influence the hydrate dissociation and gas production, but later promote the process. Meanwhile, permeability anisotropy can lead to an increase of ratio of gas phase to total production and gas-to-water ratio during long-term gas production. Moreover, permeability anisotropy can enhance the horizontal flow and the dissociation reaction in the top part of the HBL for a long period, but also leads to an increase of accumulated free gas in the reservoir. Furthermore, the comparison of horizontal well production and vertical well production indicates that the horizontal well can increase the gas production by one order of magnitude than that of vertical well during a production period of 360 days, and permeability anisotropy appears to have less effect on gas production in the initial short stage when using the vertical well.
1. Introduction Gas hydrate in Nature, most are methane hydrate (MH), is considered as one of the most promising alternative energy resources to address the world's energy demand because of its high-energy density, huge resource potential, and cleanliness (Boswell and Collett, 2011; Milkov, 2004). Over the last few decades, much attention has been focused on the problems of extracting gas from methane hydrate, and it is expected that MH reservoirs could be efficiently explored and economically exploited in the near future. In general, methane hydrate is in a solid state under the condition of low-temperature and high-pressure. The natural gas extraction from methane hydrate is a process of dissociating solid-state hydrate into the fluid phase, involving the complex multiphase (gas, liquid, ice and hydrate) flow and endothermic reaction. According to the phase-equilibrium curve of methane hydrate, the gas production from hydrate deposits include three basic techniques: Depressurization, thermal
∗
stimulation and inhibitor injection. Among these production methods, depressurization is conducted by drawing water from methane hydrate to decrease the pressure to a level below the equilibrium condition, and it is accepted as the most promising strategy for gas production because of its high energy efficiency and productivity (Moridis et al., 2011; Wang et al., 2013). To date, a large number of numerical and experimental studies around gas production from reservoir-scale hydrate by depressurization method have been carried out for the purpose of future commercial production. Among these studies, some have physically incorporated production wells with vertical or horizontal arrangement. In 2008, an onshore production test was conducted by depressurization on the Mackenzie Delta. Continuous gas production was achieved with a vertical well, and the cumulative gas produced reached 13,000 m3 during 6 days (Yamamoto and Dallimore, 2008). In 2013, the world's first offshore methane hydrate production test was conducted with a vertical well at the Eastern Nankai Trough (Konno et al., 2017). A cumulative
Corresponding author.Institute of Fluid Science, Tohoku University, Katahira 2-1-1, Aoba-ku, Sendai, Japan. E-mail addresses: [email protected], [email protected] (Y. Feng).
https://doi.org/10.1016/j.marpetgeo.2019.01.041 Received 21 September 2018; Received in revised form 4 December 2018; Accepted 29 January 2019 Available online 30 January 2019 0264-8172/ © 2019 Elsevier Ltd. All rights reserved.
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gas volume of 119,500 m3 (2.0 × 104 m3/d) was achieved in 6 continuous days. In a recent test in June of 2017, it was reported that a total gas amount around 2.0 × 105 m3 (8.33 × 103 m3/d) was produced in 24 continuous days (Chen et al., 2018). In addition, Chen et al. (2018) numerically predicted the gas production potential of a multilayers methane hydrate model based on the production test at the eastern Nankai Trough, and reported the similar results with real test. Su et al. (2012) assessed the production potential of the laminar hydrate deposit at drilling site SH3 in the Shenhu area by means of numerical simulation. It was shown that the production of hydrate-originating gas decreases at the beginning of the production and the average gas production rate is 211 m3/d. The above reservoirs-scale research by vertical production well made significant progress towards future exploration and exploitation of methane hydrate. However, the gas production rate in most cases is too low to reach the commercial production rate (ST 3.0 × 105 m3/d, Moridis and Reagan, 2011). In addition, horizontal well has also been considered in the research of gas production from MH reservoirs (Feng et al., 2015, 2017; Jin et al., 2018; Moridis et al., 2011; Yang et al., 2014). Moridis et al. (2011) investigated the production responses from a single vertical and a horizontal well in permafrost-associated hydrate reservoir using depressurization. It was found that the gas production by the horizontal well was almost two orders of magnitude higher than the case by the vertical well. Yang et al. (2014) numerically studied gas production from Class 3 hydrate reservoirs of Shenhu area by depressurization with horizontal well, and the results indicated that the gas production performance could reached the industry level. From the above analysis, the horizontal well is more favorable for gas extraction. However, these studies focused mainly on the homogeneous methane hydrate model. For natural methane hydrate reservoirs, the permeability distribution is not homogeneous due to several factors, such as irregular-shape particles, stress-induced effects and aligned crack (Bhade and Phirani, 2015; Fujii et al., 2015; Han et al., 2017; Lai et al., 2016; Myshakin et al., 2016). Therefore, it is important to consider the effect of permeability anisotropy in the design and analysis of reservoir-scale and long-term gas production from methane hydrate. Dai et al. (2018) used a customized flow anisotropy cell to investigate the permeability anisotropy of core samples recovered from the National Gas Hydrate Program Expedition 02, and found that the permeability anisotropy (ratio of horizontal permeability to vertical permeability) is approximately 4.24 for the core sample with hydrate saturation SH = 0.8. Han et al. (2017) numerically investigated the effects of reservoir permeability anisotropy on gas production by depressurization with a vertical well. Their research showed that permeability anisotropy could impede fluid flow in vertical direction, significantly changing temperature and pressure evolution. However, it remains unclear how permeability
anisotropy affects the hydrate dissociation behavior when using horizontal well. The objective of this study is to investigate the effect of permeability anisotropy on gas production behaviors from reservoir-scale methane hydrate by depressurization with a horizontal well. Simulation runs are conducted on a hypothetical sand-dominated MH reservoir model, in which the hydrate-bearing layer (HBL) is connected to a water-bearing zone. The evolutions of gas and water production, and the temperature and saturation fields during the hydrate dissociation process are analysed in detail at different degrees of permeability anisotropy. In addition, the gas production performance by using horizontal well and vertical well is compared and discussed. It is hoped that such study could achieve a clearer understanding of the reservoir-scale methane hydrate dissociation behavior, thus contributing to practical utilization and exploitation of this natural energy resource. 2. Permeability of natural methane hydrate sediments 2.1. Permeability anisotropy Reservoir-scale hydrate dissociation and gas production behaviors by depressurization is highly controlled by the permeability of sediments, which is strongly correlated with the lithology of sediments (Huang et al., 2015; Konno et al., 2015). Thus, lithology and permeability are very critical for constructing hydrate reservoir model in simulation. On the other hand, as mentioned in the introduction, the permeability of natural hydrate-bearing sediments is anisotropic due to several factors (Han et al., 2017), meaning that the permeability of sediment varies in different directions. However, for most cases the permeability anisotropy of hydrate-bearing sediment is not clear because of absence of field measurement and core sample data. On the other hand, it is difficult to accurately measure a reservoir's permeability anisotropy due to the limitation of measurement techniques and methods (Dai et al., 2018). Research in recent studies (Lai et al., 2016; Zhao et al., 2013) suggested that the ratio of horizontal permeability to vertical permeability for most layered reservoir rocks typically varies from 2 to 10. Therefore, we can assume a parameter Rhv = kh/kv (kh and kv are the reservoir permeability in horizontal and vertical directions, respectively) for the MH sediment with continuous layered structure to approximately represent the permeability anisotropy. 2.2. Hydrate in the Eastern Nankai Trough The Eastern Nankai Trough (as shown in Fig. 1(a)) is considered as one of the most potentially resource-rich areas of methane hydrate in Japan. Since 1996, more than ten prospective MH-concentrated zones
Fig. 1. Sketch map of (a) the Eastern Nankai Trough (modified from William, 2004) and (b) MH zones at the AT1 site (based on the explanation of Chen et al., 2018; Fujii et al., 2015). 818
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the Eastern Nankai Trough, and it is different from traditional Class 3 deposit, in which the hydrate-bearing layer (HBL) is confined by an impermeable overburden (muddy zone) and a permeable underburden (water-bearing zone). Based on the previous studies (Moridis et al., 2007, 2011), both the overburden and the underburden are set as 30 mthick, which is sufficient enough to provide accurate estimation of heat and pressure transfer during gas recovery from hydrate reservoir. The rectangular coordinate system is adopted to conduct the reservoir simulation. The horizontal dimension of this reservoir in X and Z are 200 m and 92 m, respectively. A single horizontal well (length is 500 m–1000 m) with radius rw = 0.1 m is arranged along Y direction and placed at the top of the HBL, in consideration of the gas buoyancy and accumulation at this location and minimizing water production effectively. Assuming uniformity along the well length (Y direction), only a single slice of unit thickness on the X-Z plane is considered in this study. On the other hand, the X-Z plane is symmetrical along the vertical direction. Therefore, only half of the slice (0 < x < 100) on the X-Z plane was considered in the numerical simulation, as shown in Fig. 2. Most of the reservoir properties and initial conditions are obtained from the AT1 test data (Fujii et al., 2015; Konno et al., 2015, 2017; Sun et al., 2016). The porosity of the system is 0.42, the hydrate saturation in the HBL is 0.5, and the permeability anisotropy in the HBL (described by the ratio Rhv of horizontal permeability to vertical permeability) is assumed to be in the range of 1–10. The overburden and underburden are fully saturated with water, and their absolute permeabilities are 0.0 mD and 840 mD, respectively. In this study, we assume the pressure in the hydrate reservoir follows the hydrostatic distribution. The hydrostatic pressure gradient and geothermal gradient are set to be 0.01 MPa/m and 0.03 °C/m, respectively. The initial pressure and temperature distributions can be determined based on the distribution gradients together with the know pressure and temperature at the base of HBL. During numerical simulation, the production well is represented as pseudo-porous media (Moridis et al., 2011) with porosity ϕ = 1.0, permeability k = 10−8 D, and capillary pressure pcap = 0 Pa. All other reservoir parameters in this simulation are summarized in Table 2. In this study, the wellbore pressure is the same to that of field test in Nankai Trough (Konno et al., 2017) within the first 6 days, and then maintained at 3.0 MPa in the following gas production. The total area of the simulated region is discretized into 51 (in X direction) × 136 (in Z direction) grid blocks. Finer discretization is applied in the vicinity of production well because of the importance of heat and mass transfer in this region. Each grid size of the HBL is 0.5 m
Table 1 The permeability of hydrate samples from the AT1 site (Konno et al., 2015). Types
Clay (%)
Silt (%)
Sand (%)
Mean diameter d (μm)
Measurement k (mD)
clay Silt Sand
35.9 5.3 2.8
61.6 38.2 24.9
2.4 56.5 72.3
5.2 84.7 133.2
0.027 83 840
(MHCZ) have been identified in this area (Saeki et al., 2008). The β MHCZ located on the northwestern slope of the Daini Atsumi Knoll is one of the MHCZs in the Eastern Nankai Trough. This MHCZ has an area of approximately 12 km2 with the water depth ranging from 857 m to 1405 m. The thickness of β - MHCZ is several tens of meters (Fujii et al., 2009). In 2013, the world's first offshore production test was conducted at AT1 site within the β - MHCZ, as shown in Fig. 1(a). The well-log data (Fujii et al., 2015) at the AT1 site indicates that the MHCZ has a thin turbidite assemblage with 60 m of gross thickness, and is composed of two MH zones, as shown in Fig. 1(b). The upper MH zone is composed of thin alternations of sand and silt layers, and the lower MH zone also contains sand and silt alternations, however, the sand layers have great thickness (several tens of cm to 2 m). In addition, the analysis of core samples from the AT1 site indicates that the absolute permeability is estimated to be tens of μD for clayey sediments, tens of mD for silty sediments, and up to 1.5 D for sandy sediments (Konno et al., 2015). Table 1 shows the permeability measurements and estimations for three types of sample cores at the AT1 site: Clay-dominant sediment, siltdominant sediment and sand-dominated sediment. In this study, we only focused on the lower MH zone at the AT1 site, considering the high exploitation value for sand-dominated hydrae reservoir, and the effect of permeability anisotropy on gas production behaviors is investigated by means of numerical simulations.
3. Numerical model and simulation approach 3.1. Model construction The schematic of hydrate reservoir model in this study is shown in Fig. 2. This assumptive reservoir-scale model was constructed based on the data of the lower MH zone (sand-dominated layer) at the AT1 site of
Table 2 Main properties of hydrate reservoir model.
Fig. 2. Schematic of the hydrate reservoir model. 819
Parameter
Value
Hydrate zone thickness Overburden thickness Underburden thickness Initial pressure at base of HBL Initial temperature at base of HBL Porosity in HBL Absolute permeability kh in HBL Permeability anisotropy Rhv in HBL Initial saturation in HBL Grain density Dry thermal conductivity Wet thermal conductivity Relative permeability model n SirA SirG Capillary pressure model SirA λ P0
32 m 30 m 30 m 13.33 MPa 14.59 °C 0.42 840 mD 1.0–10.0 SA = 0.4, SH = 0.6 2650 kg/m3 0.5 W/m/K 3.1 W/m/K 3.572 0.20 0.02 0.20 0.45 0.1 MPa
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in the vertical direction. Whereas for the overburden and underburden, a coarse and non-uniform discretization is applied at the distant grid of the hydrate layer. The uppermost and lowermost grids are set to be inactive, and the corresponding temperature and pressure remain constant during the computational process. 3.2. Simulation approach Methane hydrate dissociation is a complex process involving heat transfer, multi-phase fluid flow, and intrinsic dissociation or formation reaction. Thus, in order to model gas production from methane hydrate by dissociation, the mass balance equations, energy balance equations, and Darcy flux equations for possible components and phases should be considered in mathematical model and be solved in a coupled way. These governing equations and details can be found in our previous study (Chen et al., 2018). In this study, a numerical code Tough + Hydrate (T + H) is used to solve the governing equations. T + H code is a member of TOUGH + family from the Lawrence Berkeley National Laboratory and has been proved to be valid with a reasonable capacity in the simulation of methane hydrate dissociation and formation in complex geologic through comparative studies and history-matching simulations (Gupta et al., 2009; Li et al., 2015; Moridis et al., 2004). Thus, it is widely used in analysis and prediction of hydrate dissociation behavior from laboratory experiments to field tests. This code can simulate the hydrate dissociation process under the three main hydrate dissociation methods (depressurization, thermal stimulation and inhibitor injection) by using either an equilibrium or a kinetic model. In this study, the equilibrium reaction model is used, considering the high computing efficiency. The detailed theories related to the T + H code are described in Moridis (2012).
Fig. 3. Evolution of volumetric rate of the CH4 released from hydrate dissociation (QR) for the different Rhv cases.
in decline of QR in the late period. In addition, it is found that the maximum QR occurs at the end of Stage 1 with the value of 1.75 × 103 ST m3/d, which is slightly higher than that during Stage 2. The QR evolutions for the four different Rhv (1.0, 2.0, 5.0 and 10.0) cases follow the same trend in the process of hydrate dissociation. During Stage 1 and Stage 2, QR drops with the increase of Rhv. This is associated with the lower vertical permeability, which limits the expansion of the dissociation zone and fluids flow in the vertical direction, resulting in a lower CH4 release rate. However, the pattern reverses during Stage 3, and the high Rhv cases appear to have a favorable CH4 release rate. In addition, the period of Stage 2 becomes longer for the high Rhv cases. This can be explained by the fact that the low permeability in the vertical direction delays the time of complete decomposition of the hydrate between the production well and the permeable underburden, ensuring the depressurization effect on the hydrate dissociation zone in a long period. The slight fluctuation appearing in the QR curves may be attributed to the instantaneous change of temperature and pressure on the dissociation front because of the endothermic reaction and the complex multiphase flow in the hydrate dissociation zone. This phenomenon also occurs in the simulations of reservoir-scale hydrate dissociation by Sun et al. (2016) and Huang et al. (2015). Fig. 4 shows the evolution of the total CH4 production rate (QPT) and of the CH4 production rate in gas phase (QPG) per meter well length for the four different Rhv (1.0, 2.0, 5.0 and 10.0) cases. Note that the total CH4 produced from the well includes the gas CH4 in gaseous phase and the dissolved CH4 in aqueous phase. From the review of Figs. 3 and 4, it is found that QPT is very close to the corresponding QR in magnitude, indicating that most of the CH4 released from hydrate dissociation is produced at the well. For all the cases in Fig. 4, both QPT and the corresponding QPG curves show nearly the same pattern in the early production stage. This can be attributed to the small dissociation area around the production well and the high driving force for released gas, which leads to that all of the released gas from dissociation directly flows into the production well. While it is opposite in the following stage, the difference between QPG and QPT increase gradually with time. Especially for the cases of Rhv = 1.0, 2.0 and 5.0, no free gas is produced at the well after 302 days, 452 days and 811 days, respectively. In addition, the comparison for the different cases indicates that the increase of Rhv can slow down the peak production rate, and the high Rhv leads to a high CH4 production rate during Stage 3, which is consistent with the evolution of QR indicated by Fig. 3.
4. Results and discussions In this section, numerical simulation is conducted to investigate the gas production behaviors based on the constructed sand-dominated reservoir model. The effect of permeability anisotropy (Rhv = 1.0, 2.0, 5.0 and 10.0) on the evolution of gas and water production, and the distribution of characteristic parameters is discussed and analysed in detail. In addition, for the convenience of comparison and analysis, all the quantitative data described in Section 4.1 represents (unless otherwise noted) the result per meter length of the horizontal well (ΔY = 1 m). 4.1. Evolution of gas and water production 4.1.1. CH4 production rate Fig. 3 shows the evolution of CH4 release rate from hydrate dissociation (QR) per meter well length for the four different Rhv (1.0, 2.0, 5.0 and 10.0) cases. It can be observed for the Rhv = 1.0 case that the evolution of QR is characterized by an initial short period (Stage 1, to t = 11 days) of rapid increase, is succeeded by a period (Stage 2) of relatively constant release rate that lasts until t = 25 days, and is followed by a long period (Stage 3) of continuous decline. Among these stages, Stage 1 is associated with the severe hydrate dissociation around the production well. As the production progresses, the hydrate dissociation zone around the production well continuously and radially expands. On the other hand, the driving force (pressure gradient between the production well and the hydrate dissociation front) for hydrate dissociation gradually decreases. Thus, QR tends to remain a stable value during Stage 2. Stage 3 is strongly related to the decomposition of the hydrate between the production well and the permeable underburden, which serves as the water blocking layer (which hinders the aqueous phase in the underburden from flowing into the well). When this happens, the pressure gradient between the production well and the hydrate dissociation front further decreases, which significantly weakens the depressurization effect on hydrate dissociation and results 820
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Fig. 6. Evolution of free CH4 (VF) remaining in the reservoir for the different Rhv cases. Fig. 4. Evolution of volumetric rate of the total CH4 production at the well (QPT) and of the CH4 production in gas phase (QPG) for the different Rhv cases.
because that the hydrate release rate is relatively higher, and more and more released gas cannot flow into the production well in a timely manner, and remains and accumulates in the reservoir. However, after that stage, VF decreases with time, indicating that the remaining free CH4 gradually flows into the production well. In addition, by comparing Figs. 6 and 5, it can be found that VF is far less in comparison to VPT and VPG for each case. This further confirms that most of the CH4 released from hydrate dissociation is produced at the production well. Moreover, the comparison for the different Rhv (1.0, 2.0, 5.0 and 10.0) cases indicates that the high Rhv leads to more free gas accumulated in the reservoir. This can be attributed to the low permeability in the vertical direction. And for these cases, VF peaks on the 24th day, the 41st day, the 97th day and the 200th day, which exactly correspond to the later part of Stage 2 (as shown in Fig. 3).
4.1.2. Cumulative volume of CH4 production Fig. 5 shows the evolution of the total CH4 production (VPT) and of the CH4 production in gas phase (VPG) per meter well length for the four different Rhv (1.0, 2.0, 5.0 and 10.0) cases. For all the cases, VPG is greatly lower in comparison to the corresponding VPT in the late production stage, i.e., VPG at the end of the production periods reaches 6.08 × 104 ST m3, 7.64 × 104 ST m3, 1.07 × 105 ST m3, and 1.37 × 105 ST m3, accounting for 41.7%, 46.1%, 51.9%, and 64.6% of each VPT. In addition, the high Rhv case appears to have lower VPT and VPG than those of low Rhv case in the early production stage, but the trend reverses in the later stage. This could be attributed to the high CH4 production rate for high Rhv case in Stage 3. The above results indicate that the permeability anisotropy (high Rhv) has a positive effect on long-term gas production. And this is consistent with the study of the effect of permeability anisotropy on gas production from a cold, stratigraphically-bounded gas hydrate deposit with horizontal well (Moridis et al., 2011), in which the low-temperature hydrate-bearing layer is confined by impermeable overburden and underburden. Fig. 6 shows the evolution of cumulative volume of the free CH4 remaining in the reservoir (VF) per meter well length for the four different Rhv (1.0, 2.0, 5.0 and 10.0) cases. It is found for all cases that VF appears to increase rapidly in the early production stage. This is
4.1.3. Water production and gas-to-water ratio Fig. 7 shows the evolution of water production (VW) per meter well length for the four different Rhv (1.0, 2.0, 5.0 and 10.0) cases. For all the cases, VW increases slowly in the early production stage. However, as the production processes, VW increase linearly with a high and stable production rate. The reason is that a large amount of water from the underburden flows into the production well due to the decomposition of water blocking layer. The comparison for the different Rhv (1.0, 2.0, 5.0 and 10.0) cases indicates that VW decreases with an increasing Rhv.
Fig. 5. Evolution of cumulative volumes of the total CH4 production at the well (VPT) and of the CH4 production in gas phase (VPG) for the different Rhv cases.
Fig. 7. Evolution of water production (VW) at the well for the different Rhv cases. 821
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resulting in a high cost of lifting the water to the sea level. Thus, water management is an important aspect in the design and analysis of longterm gas production from such Nankai Trough reservoirs. Fig. 8 shows the evolution of gas-to-water ratio (RGW) for the four different Rhv (1.0, 2.0, 5.0 and 10.0) cases. RGW is regarded as a relative criterion to evaluate the production performance, and is computed as RGW = VPT/VW (the volume of CH4 produced from the well per unit volume of produced water). It is clear that a high RGW means better economy in CH4 production from methane hydrate reservoirs. As shown in Fig. 8, RGW increases rapidly during the early production stage because of high CH4 production rate and low water production rate. And for these (Rhv = 1.0, 2.0, 5.0 and 10.0) cases, RGW reaches its maximum value at the 9th day, the 10th day, the 11th day, and the 14th day, respectively. Beyond that time, RGW shows a sharp decline and then maintains a relatively stable value in the later production stage. In addition, the comparison for the different Rhv (1.0, 2.0, 5.0 and 10.0) cases indicates that the high Rhv case has a high gas-to-water ratio during the entire production stage, especially in the early stage. This suggests that the high Rhv case has a better production performance over the low Rhv case in the relative criterion. The findings of these observations in the evolution of water and gas production clearly demonstrate that permeability anisotropy has complex effects on the gas production. The permeability anisotropy can initially negatively influence hydrate dissociation and CH4 production,
Fig. 8. Evolution of gas-to-water ratio (RGW) for the different Rhv cases.
This is associated with the decreasing of permeability in the vertical direction, which hinders the water from the underburden flowing into the HBL. The above results indicate that a large amount of water will be produced for the hydrate reservoirs with high vertical permeability,
Fig. 9. Evolution of the pressure (P) distribution for (a) Rhv = 1.0 and (b) Rhv = 10.0 cases. 822
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Fig. 10. Evolution of the temperature (T) distribution for (a) Rhv = 1.0 and (b) Rhv = 10.0 cases.
processes. Therefore, the QR and QPT show a decline trend in the long run (as shown in Figs. 3 and 4). Moreover, it can be observed at t = 90 days that the low-pressure front has reached the underburden, meaning that hydrate dissociation can occur in the region between the production well and the underburden. After that, the evolution of the pressure distribution is not very noticeable. This can be explained by the fact that the hydrate between the production well and the permeable underburden completely dissociates, leading to large amount of water flowing into the production well, and thus the low-pressure front can not further advance in the HBL. When increasing Rhv to 10.0, as shown in Fig. 9(b), the low-pressure front seems to advance horizontally and preferentially along the top part of the HBL. This is associated with the relatively high permeability in the horizontal direction. After t = 270 days, the pressure distribution barely changes, which may be attributed to the destruction of the water blocking layer (hydrate between the production well and the permeable underburden). In addition, the comparison of Fig. 9 (a) and Fig. 9 (b) indicates that the HBL in the high Rhv case can keep a lower pressure for a long time, meaning that higher Rhv is beneficial for keeping the depressurization effect during production.
but later promote the process. Meanwhile, permeability anisotropy can lead to high ratio of gas phase to total production and gas-to-water ratio. Therefore, it is important to consider the permeability anisotropy effect in the prediction of long-term gas production from such Nankai Trough reservoirs. 4.2. Evolution of characteristic parameters From the above analysis, when increasing Rhv from 1.0 to 2.0, 5.0 and 10.0, the changes of the gas production behaviors follow the similar trend, although the changes are different in absolute terms. Therefore, for simplify the analysis, only the evolutions of characteristic parameters in the Rhv = 1.0 and 10.0 cases are discussed in this section. Figs. 9–12 show the evolution of pressure (P), temperature (T), hydrate saturation (SH), and gas saturation (SG) distributions within the first 360 days. Dashed lines in these figures indicate the initial positions of the top and bottom of HBL, respectively. 4.2.1. Spatial distribution of pressure P Fig. 9 shows the evolution of pressure distribution during hydrate dissociation process for the Rhv = 1.0 and 10.0 cases. For the Rhv = 1.0 case, the low-pressure front expands radically in the early production stage (Fig. 9(a), t = 10, 30, and 90 days), and the pressure in HBL decreases gradually with time, which suggests that the driving force for hydrate dissociation and gas production decreases as production
4.2.2. Spatial distribution of temperature T Fig. 10 shows the evolution of temperature distribution during hydrate dissociation process for the Rhv = 1.0 and 10.0 cases. The comparison of Fig. 10(a) and (b) indicates that the temperature distribution 823
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Fig. 11. Evolution of the hydrate saturation (SH) distribution for (a) Rhv = 1.0 and (b) Rhv = 10.0 cases.
geothermal gradient in the overburden. In addition, it is clear that the high-temperature fluid from the underburden flows into the production well after t = 270 days, which occurs later than that of Rhv = 1.0 case. The above results provide the confirmation that the high Rhv can delay the onset time of high-temperature water (which comes from the underburden) flowing into the HBL.
of HBL is strongly affected by the degree of permeability anisotropy and shows different characteristics. For the Rhv = 1.0 case, a low-temperature zone can be observed around the production well in the early production stage (Fig. 10(a), t = 10 days), which can be attributed to the significant endothermic dissociation reaction under the condition of high pressure gradient. Meanwhile, another slightly low-temperature zone appears along the bottom of the HBL, indicating hydrate dissociation reaction in this region. This is caused by the continuing geothermal heat inflows from the underburden. However, during t = 30–360 days, these low-temperature zones gradually disappear, and a large amount of high-temperature water from the underburden flows into the HBL, resulting in a high temperature in the region where hydrate completely dissociates. When increasing Rhv to 10.0, as shown in Fig. 10(b), the low-temperature zone continues to expand horizontally along the top half of the HBL for a very long period (Fig. 10(b), t = 10–180 days), which indicates that hydrate dissociates preferentially along the top part of the HBL, which can be attributed to the strong depressurization effect in this region (as shown in Fig. 9(b)). In addition, an inversion of the geothermal gradient can be observed in the overburden after t = 90 days. This phenomenon can be explained by the fact that intense hydrate dissociation consumes a large amount of sensible heat and leads to temperature decline in the top of the HBL, and thus heat will transfer from the overburden to the HBL, resulting in the reversal of the
4.2.3. Spatial distribution of hydrate saturation SH Fig. 11 shows the evolution of the hydrate saturation distribution during dissociation process for the Rhv = 1.0 and 10.0 cases. For the Rhv = 1.0 case, there is a hydrate-free zone around the production well and the hydrate dissociation zone advances with an expanding radius in the early production stage (Fig. 11(a), t = 10 days), which is consistent with the temperature change in Fig. 10(a). After that time, the dissociation front reaches the interface between the HBL and the underburden, and the hydrate begins to dissociate mainly along the base of the HBL, accompanying with a slow-moving dissociation front that is clearly identifiable. This is due to the fact that the depressurization effect is weakened after the decomposition of the hydrates between the production well and the permeable underburden, and thereafter the dissociation is mainly controlled by the heat transfer with the hightemperature inflows from the underburden. When increasing Rhv to 10.0, as shown in Fig. 11(b), it can be observed that the dissociation zone in the early production stage 824
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Fig. 12. Evolution of the gas saturation (SG) distribution for (a) Rhv = 1.0 and (b) Rhv = 10.0 cases.
Fig. 14. Comparison of the gas production rates QPT between the horizontal well production and vertical well production within the first 360 days.
Fig. 13. Evolution of the gas production rates QPT within the first 6 days.
(Fig. 11(b), t = 10 days) is much smaller than that of Rhv = 1.0 case, which is caused by the low permeability in the vertical direction. But thereafter, the dissociation zone expands horizontally along the top half of the HBL for a very long period (Fig. 11(b), t = 30, 90 and 180 days). Meanwhile, the bottom of the HBL shows a horizontal hydrate-free zone (Fig. 11(b), t = 180 days), indicating the hydrate dissociation reaction in this region. And the hydrate between the production well and the permeable underburden decomposes completely after t = 270 days. In addition, it is clear that the dissociation zone can move far away from the production well in the horizontal direction compared with that of
Rhv = 10.0 case. The above results provide further confirmation that high Rhv is benefit for enhancing the horizontal flow, facilitating the dissociation and keeping the depressurization effect for a long period.
4.2.4. Spatial distribution of gas saturation SG Fig. 12 shows the evolution of the gas saturation distribution during hydrate dissociation process for the Rhv = 1.0 and 10.0 cases. For the Rhv = 1.0 case, in the early production stage (Fig. 12, t = 10 days), the free CH4 mainly accumulates in the dissociation zone around the 825
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corresponds to the rectangular reservoir model with a 628 m-long horizontal well. A vertical production interval (12 m), located along the axis of the cylindrical model, is placed in the upper part of the HBL, which is the same as that applied in the field test (the length of the production interval is 40 m, and only a 12 m-long production interval is applied in the lower MH zone) of the Eastern Nankai Trough in 2013. And the wellbore pressure is the same as that of horizontal well production. Fig. 13 shows the evolution of gas production rates QPT by using the vertical well within the first 6 days. Meanwhile, the field data (Konno et al., 2017) at the Eastern Nankai Trough in 2013 is presented in Fig. 13. It can be observed from Fig. 13 that the gas production rate from the vertical well is close to that in field observation, which greatly proves the reasonability and reliability of the numerical code and the constructed model in this study. It should be noted that the hydrate concentrated interval in the field production test is nearly 60 m, which is composed of thin alternations of sand and mud layers in the upper part and relatively thick sand-dominant sequences in the lower part. While in this study, only the thick sand-dominant sequences in the lower part is considered in the numerical simulation. Therefore, the simulated results for the vertical well are slightly lower than that in field observation. Fig. 14 shows the evolution of QPT during a long-term gas production for 360 days by using the vertical well and the horizontal well. An interesting observation from the vertical well case is that the permeability anisotropy seems to have less effect on gas production in the initial short stage (t < 60 days), but in the late long stage, the QPT for Rhv = 10.0 case keeps a higher value compared with that of Rhv = 1.0 case. This indicates that the gas production process in the early stage are less influenced by the vertical permeability, and highly depends on the horizontal dissociation and flow when using the vertical well. In addition, it is found that the use of horizontal well (the length is 628 m) appears to increase the gas production rate by one order of magnitude. This greatly proves the higher performance of horizontal well. Fig. 15 shows the comparison of the total CH4 production VPT between the horizontal well production and vertical well production within the first 360 days. For the horizontal well production, the VPT of Rhv = 10.0 case is less than that of Rhv = 1.0 case for a very long time, and both VPT curves converges at the end of 360-day-long production period. However for the vertical well production, the VPT of Rhv = 10.0 case outpaces that of Rhv = 1.0 case after t = 120 days, which is associated with the high QPT for Rhv = 10.0 case (as shown in Fig. 14). Other than these, more information of gas production performance by using the vertical well and horizontal well is listed in Table 3. It is observed that the use of horizontal well shows high average gas production rate, which are 2.41 × 105 ST m3/d for Rhv = 1.0 and 2.50 × 105 m3/d for Rhv = 10.0, respectively. In addition, for both the horizontal well production and vertical well production, the gas-towater ratio is dramatically improved when increasing Rhv from 1.0 to 10.0. Moreover, the gas-to-water ratio for the horizontal well production is lower than that for the vertical well production. This can be attributed to the longer production well for the horizontal well case, which contributes more to water production than CH4 production after the decomposition of the hydrates between the production well and the permeable underburden, and thus leads to a lower gas-to-water ratio in comparison to that in the vertical well case. It is clear from the above comparison that the use of horizontal well appears to be very effective for gas production from such Nankai Trough reservoirs, and the permeability anisotropy plays an especially important role in the hydrate dissociation process by depressurization no matter which type of production well (horizontal well and vertical well) is employed. While the average gas production rate from the horizontal well is still lower than the requirement of commercial production (3.0 × 105 m3/d), it is possible that the gas production performance can be further enhanced with longer horizontal well, different well configurations and more complex production strategies. The
Fig. 15. Comparison of the total CH4 production VPT between the horizontal well production and vertical well production within the first 360 days. Table 3 Comparison of the gas production performance within the first 360 days. Simulated result
Horizontal well Rhv = 1.0
Total gas production (ST m3) Average gas production rate (ST m3/d) Average gas-to-water ratio (ST m3/m3)
7
Vertical well
Rhv = 10.0 7
Rhv = 1.0 6
Rhv = 10.0 6.4 × 106
9.0 × 10
4.3 × 10
2.41 × 105
2.50 × 105
1.20 × 104
1.78 × 104
0.47
6.9
2.4
8.9
8.7 × 10
production well. But thereafter, the gas accumulation zone shrinks and the corresponding gas saturation gradually decreases (Fig. 12, t ≥ 30 days). This is consistent with the declining trend of VF during production stage (as shown in Fig. 6). This phenomenon is caused by the water flow from the underburden and the weakening dissociation reaction. In addition, combined with the corresponding temperature distribution in Fig. 10(a) and hydrate saturation distribution in Fig. 11(a), it is clear that no free CH4 exists in the hydrate-free zone (Fig. 12, t ≥ 30 days) that is occupied by the higher-temperature water. When increasing Rhv to 10.0, as shown in Fig. 12(b), it can be observed that more and more free CH4 accumulates in the half top of the HBL for a long production period (Fig. 12(b), t = 30, 90 and 180 days), which is consistent with the evolution of VF in Fig. 6. This can be attributed to the low permeability in the vertical direction, which inhibits the fluid flow and pressure transfer, resulting in large amount of accumulated free CH4 in the dissociation zone. As time passes (Fig. 12(b), t = 270 and 360 days), the gas saturation pattern shows the same tend as that of Rhv = 1.0 case, the gas accumulation zone shrinks and the corresponding gas saturation gradually decreases. The above results further indicate that the high Rhv can lead to the increment of free CH4 remained in the reservoir during the production period. 4.3. Comparison of the productions using a horizontal well and a vertical well In this section, the effect of permeability anisotropy on gas production is compared between horizontal well production and vertical well production. Firstly, we construct a cylindrical reservoir model, which has the same hydrate volume, initial conditions and production pressure with the above-mentioned rectangular reservoir model. The radius of the cylindrical reservoir model is 200 m, which exactly 826
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findings of this study provide a reference for the analysis and future commercial production targeting such Nankai Trough reservoirs.
S SirA SirG T T VF
phase saturation irreducible water saturation irreducible gas saturation time (day) temperature (°C) cumulative volume of free gas CH4 remaining in reservoir (ST m3) VPG cumulative volume of produced CH4 in gas phase (ST m3) VPT cumulative volume of total produced CH4 (ST m3) VW cumulative volume of produced water (ST m3) Greek symbols
5. Conclusions In this study, a reservoir-scale model was constructed to investigate the effect of permeability anisotropy on gas production behavior by depressurization with a horizontal well. The evolutions of gas and water production, and the temperature and saturation fields during the hydrate dissociation process were analysed in detail at different degrees of permeability anisotropy. In addition, the gas production performance by using horizontal well and vertical well is compared and discussed. The main results obtained in this study are summarized as follows:
ϕ porosity λ van Genuchten exponent Superscripts and subscripts
a Permeability anisotropy has complex effects on the production performance when using the horizontal well. The permeability anisotropy can initially negatively influence the hydrate dissociation and gas production, but later promote the process. Meanwhile, permeability anisotropy can lead to an increase of ratio of gas phase to total production and gas-to-water ratio. b Permeability anisotropy can enhance the horizontal flow, facilitate the dissociation, and keep the depressurization effect in the top part of the HBL for a long period. However, it also leads to an increase of the free gas in the reservoir during the production period. c A large amount of water is produced from the well during the late production stage, due to the decomposition of hydrate between the production well and the permeable underburden. Thus, water management is an important aspect in the design and analysis of long-term gas production from such hydrate reservoirs. d The use of horizontal well appears to be very effective for gas production from such sand-dominated hydrae reservoirs in the Eastern Nankai Trough. During a production period of 360 days, the horizontal well can increase the gas production by one order of magnitude than that of vertical well. e Permeability anisotropy has less effect on was production in the initial short stage when using the vertical well.
A H G
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Acknowledgments This work was supported by the JST-CREST Project (No. JPMJCR13C4: Breakthrough on Multi-Scale Interfacial Transport Phenomena in Oceanic Methane Hydrate Reservoir and Application to Large-Scale Methane Production). Appendix A. Supplementary data Supplementary data to this article can be found online at https:// doi.org/10.1016/j.marpetgeo.2019.01.041. Nomenclature d k kh kv L N P P0 QPG QPT QR RGW Rhv
aqueous phase hydrate phase gas phase
grain diameter (μm) absolute permeability (mD, 1 Darcy = 10−12 m2) absolute permeability in horizontal direction (mD) absolute permeability in vertical direction (mD) length of production well (m) relative permeability index pressure (MPa) atmospheric pressure (MPa) volumetric rate of produced CH4 in gas phase (ST m3/day) volumetric rate of total produced CH4 at well (ST m3/day) volumetric rate of CH4 released from hydrate dissociation (ST m3/day) ratio of gas to water production (ST m3 of CH4/m3 of H2O) ratio of horizontal permeability (kh) to vertical permeability (kv) 827
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from class-1 hydrate deposits. SPE Reservoir Eval. Eng. 10, 458–481. Moridis, G.J., Reagan, M.T., 2011. Estimating the upper limit of gas production from Class 2 hydrate accumulations in the permafrost: 1. Concepts, system description, and the production base case. J. Petrol. Sci. Eng. 76, 194–204. Moridis, G.J., Silpngarmlert, S., Reagan, M.T., Collett, T., Zhang, K., 2011. Gas production from a cold, stratigraphically-bounded gas hydrate deposit at the mount elbert gas hydrate stratigraphic test well, Alaska north slope: implications of uncertainties. Mar. Petrol. Geol. 28, 517–534. Myshakin, E.M., Ajayi, T., Anderson, B.J., Seol, Y., Boswell, R., 2016. Numerical simulations of depressurization-induced gas production from gas hydrates using 3-D heterogeneous models of L-Pad, Prudhoe Bay Unit, North Slope Alaska. J. Nat. Gas Sci. Eng. 35, 1336–1352. Saeki, T., Fujii, T., Inamori, T., Kobayashi, T., Hayashi, M., Nagakubo, S., Takano, O., 2008. Extraction of methane hydrate concentrated zone for resource assessment in the Eastern Nankai trough. In: Japan, Offshore Technology Conference. Offshore Technology Conference, Houston, Texas, USA. Su, Z., He, Y., Wu, N., Zhang, K., Moridis, G.J., 2012. Evaluation on gas production potential from laminar hydrate deposits in Shenhu Area of South China Sea through
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Research paper
Numerical analysis of gas production from reservoir-scale methane hydrate by depressurization with a horizontal well: The effect of permeability anisotropy
T
Yongchang Fenga,∗, Lin Chenb, Anna Suzukia, Takuma Kogawac, Junnosuke Okajimaa, Atsuki Komiyaa, Shigenao Maruyamaa,c a b c
Institute of Fluid Science, Tohoku University, Sendai, 980-8577, Japan Institute of Engineering Thermophysics, Chinese Academy of Sciences, Beijing, 100190, China National Institute of Technology, Hachinohe College, Tamonoki, 039-1192, Japan
A R T I C LE I N FO
A B S T R A C T
Keywords: Methane hydrate Permeability anisotropy Depressurization Horizontal well Gas production
Methane hydrate (MH) is regarded as one of the potential and substantial energy resources. The permeability of hydrate-bearing layer (HBL) can potentially influence heat and mass transfer during hydrate dissociation by depressurization. In this study, a reservoir-scale MH model was constructed to investigate the effect of permeability anisotropy on gas production behaviors by depressurization with a horizontal well. The numerical results indicate that permeability anisotropy can initially negatively influence the hydrate dissociation and gas production, but later promote the process. Meanwhile, permeability anisotropy can lead to an increase of ratio of gas phase to total production and gas-to-water ratio during long-term gas production. Moreover, permeability anisotropy can enhance the horizontal flow and the dissociation reaction in the top part of the HBL for a long period, but also leads to an increase of accumulated free gas in the reservoir. Furthermore, the comparison of horizontal well production and vertical well production indicates that the horizontal well can increase the gas production by one order of magnitude than that of vertical well during a production period of 360 days, and permeability anisotropy appears to have less effect on gas production in the initial short stage when using the vertical well.
1. Introduction Gas hydrate in Nature, most are methane hydrate (MH), is considered as one of the most promising alternative energy resources to address the world's energy demand because of its high-energy density, huge resource potential, and cleanliness (Boswell and Collett, 2011; Milkov, 2004). Over the last few decades, much attention has been focused on the problems of extracting gas from methane hydrate, and it is expected that MH reservoirs could be efficiently explored and economically exploited in the near future. In general, methane hydrate is in a solid state under the condition of low-temperature and high-pressure. The natural gas extraction from methane hydrate is a process of dissociating solid-state hydrate into the fluid phase, involving the complex multiphase (gas, liquid, ice and hydrate) flow and endothermic reaction. According to the phase-equilibrium curve of methane hydrate, the gas production from hydrate deposits include three basic techniques: Depressurization, thermal
∗
stimulation and inhibitor injection. Among these production methods, depressurization is conducted by drawing water from methane hydrate to decrease the pressure to a level below the equilibrium condition, and it is accepted as the most promising strategy for gas production because of its high energy efficiency and productivity (Moridis et al., 2011; Wang et al., 2013). To date, a large number of numerical and experimental studies around gas production from reservoir-scale hydrate by depressurization method have been carried out for the purpose of future commercial production. Among these studies, some have physically incorporated production wells with vertical or horizontal arrangement. In 2008, an onshore production test was conducted by depressurization on the Mackenzie Delta. Continuous gas production was achieved with a vertical well, and the cumulative gas produced reached 13,000 m3 during 6 days (Yamamoto and Dallimore, 2008). In 2013, the world's first offshore methane hydrate production test was conducted with a vertical well at the Eastern Nankai Trough (Konno et al., 2017). A cumulative
Corresponding author.Institute of Fluid Science, Tohoku University, Katahira 2-1-1, Aoba-ku, Sendai, Japan. E-mail addresses: [email protected], [email protected] (Y. Feng).
https://doi.org/10.1016/j.marpetgeo.2019.01.041 Received 21 September 2018; Received in revised form 4 December 2018; Accepted 29 January 2019 Available online 30 January 2019 0264-8172/ © 2019 Elsevier Ltd. All rights reserved.
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gas volume of 119,500 m3 (2.0 × 104 m3/d) was achieved in 6 continuous days. In a recent test in June of 2017, it was reported that a total gas amount around 2.0 × 105 m3 (8.33 × 103 m3/d) was produced in 24 continuous days (Chen et al., 2018). In addition, Chen et al. (2018) numerically predicted the gas production potential of a multilayers methane hydrate model based on the production test at the eastern Nankai Trough, and reported the similar results with real test. Su et al. (2012) assessed the production potential of the laminar hydrate deposit at drilling site SH3 in the Shenhu area by means of numerical simulation. It was shown that the production of hydrate-originating gas decreases at the beginning of the production and the average gas production rate is 211 m3/d. The above reservoirs-scale research by vertical production well made significant progress towards future exploration and exploitation of methane hydrate. However, the gas production rate in most cases is too low to reach the commercial production rate (ST 3.0 × 105 m3/d, Moridis and Reagan, 2011). In addition, horizontal well has also been considered in the research of gas production from MH reservoirs (Feng et al., 2015, 2017; Jin et al., 2018; Moridis et al., 2011; Yang et al., 2014). Moridis et al. (2011) investigated the production responses from a single vertical and a horizontal well in permafrost-associated hydrate reservoir using depressurization. It was found that the gas production by the horizontal well was almost two orders of magnitude higher than the case by the vertical well. Yang et al. (2014) numerically studied gas production from Class 3 hydrate reservoirs of Shenhu area by depressurization with horizontal well, and the results indicated that the gas production performance could reached the industry level. From the above analysis, the horizontal well is more favorable for gas extraction. However, these studies focused mainly on the homogeneous methane hydrate model. For natural methane hydrate reservoirs, the permeability distribution is not homogeneous due to several factors, such as irregular-shape particles, stress-induced effects and aligned crack (Bhade and Phirani, 2015; Fujii et al., 2015; Han et al., 2017; Lai et al., 2016; Myshakin et al., 2016). Therefore, it is important to consider the effect of permeability anisotropy in the design and analysis of reservoir-scale and long-term gas production from methane hydrate. Dai et al. (2018) used a customized flow anisotropy cell to investigate the permeability anisotropy of core samples recovered from the National Gas Hydrate Program Expedition 02, and found that the permeability anisotropy (ratio of horizontal permeability to vertical permeability) is approximately 4.24 for the core sample with hydrate saturation SH = 0.8. Han et al. (2017) numerically investigated the effects of reservoir permeability anisotropy on gas production by depressurization with a vertical well. Their research showed that permeability anisotropy could impede fluid flow in vertical direction, significantly changing temperature and pressure evolution. However, it remains unclear how permeability
anisotropy affects the hydrate dissociation behavior when using horizontal well. The objective of this study is to investigate the effect of permeability anisotropy on gas production behaviors from reservoir-scale methane hydrate by depressurization with a horizontal well. Simulation runs are conducted on a hypothetical sand-dominated MH reservoir model, in which the hydrate-bearing layer (HBL) is connected to a water-bearing zone. The evolutions of gas and water production, and the temperature and saturation fields during the hydrate dissociation process are analysed in detail at different degrees of permeability anisotropy. In addition, the gas production performance by using horizontal well and vertical well is compared and discussed. It is hoped that such study could achieve a clearer understanding of the reservoir-scale methane hydrate dissociation behavior, thus contributing to practical utilization and exploitation of this natural energy resource. 2. Permeability of natural methane hydrate sediments 2.1. Permeability anisotropy Reservoir-scale hydrate dissociation and gas production behaviors by depressurization is highly controlled by the permeability of sediments, which is strongly correlated with the lithology of sediments (Huang et al., 2015; Konno et al., 2015). Thus, lithology and permeability are very critical for constructing hydrate reservoir model in simulation. On the other hand, as mentioned in the introduction, the permeability of natural hydrate-bearing sediments is anisotropic due to several factors (Han et al., 2017), meaning that the permeability of sediment varies in different directions. However, for most cases the permeability anisotropy of hydrate-bearing sediment is not clear because of absence of field measurement and core sample data. On the other hand, it is difficult to accurately measure a reservoir's permeability anisotropy due to the limitation of measurement techniques and methods (Dai et al., 2018). Research in recent studies (Lai et al., 2016; Zhao et al., 2013) suggested that the ratio of horizontal permeability to vertical permeability for most layered reservoir rocks typically varies from 2 to 10. Therefore, we can assume a parameter Rhv = kh/kv (kh and kv are the reservoir permeability in horizontal and vertical directions, respectively) for the MH sediment with continuous layered structure to approximately represent the permeability anisotropy. 2.2. Hydrate in the Eastern Nankai Trough The Eastern Nankai Trough (as shown in Fig. 1(a)) is considered as one of the most potentially resource-rich areas of methane hydrate in Japan. Since 1996, more than ten prospective MH-concentrated zones
Fig. 1. Sketch map of (a) the Eastern Nankai Trough (modified from William, 2004) and (b) MH zones at the AT1 site (based on the explanation of Chen et al., 2018; Fujii et al., 2015). 818
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the Eastern Nankai Trough, and it is different from traditional Class 3 deposit, in which the hydrate-bearing layer (HBL) is confined by an impermeable overburden (muddy zone) and a permeable underburden (water-bearing zone). Based on the previous studies (Moridis et al., 2007, 2011), both the overburden and the underburden are set as 30 mthick, which is sufficient enough to provide accurate estimation of heat and pressure transfer during gas recovery from hydrate reservoir. The rectangular coordinate system is adopted to conduct the reservoir simulation. The horizontal dimension of this reservoir in X and Z are 200 m and 92 m, respectively. A single horizontal well (length is 500 m–1000 m) with radius rw = 0.1 m is arranged along Y direction and placed at the top of the HBL, in consideration of the gas buoyancy and accumulation at this location and minimizing water production effectively. Assuming uniformity along the well length (Y direction), only a single slice of unit thickness on the X-Z plane is considered in this study. On the other hand, the X-Z plane is symmetrical along the vertical direction. Therefore, only half of the slice (0 < x < 100) on the X-Z plane was considered in the numerical simulation, as shown in Fig. 2. Most of the reservoir properties and initial conditions are obtained from the AT1 test data (Fujii et al., 2015; Konno et al., 2015, 2017; Sun et al., 2016). The porosity of the system is 0.42, the hydrate saturation in the HBL is 0.5, and the permeability anisotropy in the HBL (described by the ratio Rhv of horizontal permeability to vertical permeability) is assumed to be in the range of 1–10. The overburden and underburden are fully saturated with water, and their absolute permeabilities are 0.0 mD and 840 mD, respectively. In this study, we assume the pressure in the hydrate reservoir follows the hydrostatic distribution. The hydrostatic pressure gradient and geothermal gradient are set to be 0.01 MPa/m and 0.03 °C/m, respectively. The initial pressure and temperature distributions can be determined based on the distribution gradients together with the know pressure and temperature at the base of HBL. During numerical simulation, the production well is represented as pseudo-porous media (Moridis et al., 2011) with porosity ϕ = 1.0, permeability k = 10−8 D, and capillary pressure pcap = 0 Pa. All other reservoir parameters in this simulation are summarized in Table 2. In this study, the wellbore pressure is the same to that of field test in Nankai Trough (Konno et al., 2017) within the first 6 days, and then maintained at 3.0 MPa in the following gas production. The total area of the simulated region is discretized into 51 (in X direction) × 136 (in Z direction) grid blocks. Finer discretization is applied in the vicinity of production well because of the importance of heat and mass transfer in this region. Each grid size of the HBL is 0.5 m
Table 1 The permeability of hydrate samples from the AT1 site (Konno et al., 2015). Types
Clay (%)
Silt (%)
Sand (%)
Mean diameter d (μm)
Measurement k (mD)
clay Silt Sand
35.9 5.3 2.8
61.6 38.2 24.9
2.4 56.5 72.3
5.2 84.7 133.2
0.027 83 840
(MHCZ) have been identified in this area (Saeki et al., 2008). The β MHCZ located on the northwestern slope of the Daini Atsumi Knoll is one of the MHCZs in the Eastern Nankai Trough. This MHCZ has an area of approximately 12 km2 with the water depth ranging from 857 m to 1405 m. The thickness of β - MHCZ is several tens of meters (Fujii et al., 2009). In 2013, the world's first offshore production test was conducted at AT1 site within the β - MHCZ, as shown in Fig. 1(a). The well-log data (Fujii et al., 2015) at the AT1 site indicates that the MHCZ has a thin turbidite assemblage with 60 m of gross thickness, and is composed of two MH zones, as shown in Fig. 1(b). The upper MH zone is composed of thin alternations of sand and silt layers, and the lower MH zone also contains sand and silt alternations, however, the sand layers have great thickness (several tens of cm to 2 m). In addition, the analysis of core samples from the AT1 site indicates that the absolute permeability is estimated to be tens of μD for clayey sediments, tens of mD for silty sediments, and up to 1.5 D for sandy sediments (Konno et al., 2015). Table 1 shows the permeability measurements and estimations for three types of sample cores at the AT1 site: Clay-dominant sediment, siltdominant sediment and sand-dominated sediment. In this study, we only focused on the lower MH zone at the AT1 site, considering the high exploitation value for sand-dominated hydrae reservoir, and the effect of permeability anisotropy on gas production behaviors is investigated by means of numerical simulations.
3. Numerical model and simulation approach 3.1. Model construction The schematic of hydrate reservoir model in this study is shown in Fig. 2. This assumptive reservoir-scale model was constructed based on the data of the lower MH zone (sand-dominated layer) at the AT1 site of
Table 2 Main properties of hydrate reservoir model.
Fig. 2. Schematic of the hydrate reservoir model. 819
Parameter
Value
Hydrate zone thickness Overburden thickness Underburden thickness Initial pressure at base of HBL Initial temperature at base of HBL Porosity in HBL Absolute permeability kh in HBL Permeability anisotropy Rhv in HBL Initial saturation in HBL Grain density Dry thermal conductivity Wet thermal conductivity Relative permeability model n SirA SirG Capillary pressure model SirA λ P0
32 m 30 m 30 m 13.33 MPa 14.59 °C 0.42 840 mD 1.0–10.0 SA = 0.4, SH = 0.6 2650 kg/m3 0.5 W/m/K 3.1 W/m/K 3.572 0.20 0.02 0.20 0.45 0.1 MPa
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in the vertical direction. Whereas for the overburden and underburden, a coarse and non-uniform discretization is applied at the distant grid of the hydrate layer. The uppermost and lowermost grids are set to be inactive, and the corresponding temperature and pressure remain constant during the computational process. 3.2. Simulation approach Methane hydrate dissociation is a complex process involving heat transfer, multi-phase fluid flow, and intrinsic dissociation or formation reaction. Thus, in order to model gas production from methane hydrate by dissociation, the mass balance equations, energy balance equations, and Darcy flux equations for possible components and phases should be considered in mathematical model and be solved in a coupled way. These governing equations and details can be found in our previous study (Chen et al., 2018). In this study, a numerical code Tough + Hydrate (T + H) is used to solve the governing equations. T + H code is a member of TOUGH + family from the Lawrence Berkeley National Laboratory and has been proved to be valid with a reasonable capacity in the simulation of methane hydrate dissociation and formation in complex geologic through comparative studies and history-matching simulations (Gupta et al., 2009; Li et al., 2015; Moridis et al., 2004). Thus, it is widely used in analysis and prediction of hydrate dissociation behavior from laboratory experiments to field tests. This code can simulate the hydrate dissociation process under the three main hydrate dissociation methods (depressurization, thermal stimulation and inhibitor injection) by using either an equilibrium or a kinetic model. In this study, the equilibrium reaction model is used, considering the high computing efficiency. The detailed theories related to the T + H code are described in Moridis (2012).
Fig. 3. Evolution of volumetric rate of the CH4 released from hydrate dissociation (QR) for the different Rhv cases.
in decline of QR in the late period. In addition, it is found that the maximum QR occurs at the end of Stage 1 with the value of 1.75 × 103 ST m3/d, which is slightly higher than that during Stage 2. The QR evolutions for the four different Rhv (1.0, 2.0, 5.0 and 10.0) cases follow the same trend in the process of hydrate dissociation. During Stage 1 and Stage 2, QR drops with the increase of Rhv. This is associated with the lower vertical permeability, which limits the expansion of the dissociation zone and fluids flow in the vertical direction, resulting in a lower CH4 release rate. However, the pattern reverses during Stage 3, and the high Rhv cases appear to have a favorable CH4 release rate. In addition, the period of Stage 2 becomes longer for the high Rhv cases. This can be explained by the fact that the low permeability in the vertical direction delays the time of complete decomposition of the hydrate between the production well and the permeable underburden, ensuring the depressurization effect on the hydrate dissociation zone in a long period. The slight fluctuation appearing in the QR curves may be attributed to the instantaneous change of temperature and pressure on the dissociation front because of the endothermic reaction and the complex multiphase flow in the hydrate dissociation zone. This phenomenon also occurs in the simulations of reservoir-scale hydrate dissociation by Sun et al. (2016) and Huang et al. (2015). Fig. 4 shows the evolution of the total CH4 production rate (QPT) and of the CH4 production rate in gas phase (QPG) per meter well length for the four different Rhv (1.0, 2.0, 5.0 and 10.0) cases. Note that the total CH4 produced from the well includes the gas CH4 in gaseous phase and the dissolved CH4 in aqueous phase. From the review of Figs. 3 and 4, it is found that QPT is very close to the corresponding QR in magnitude, indicating that most of the CH4 released from hydrate dissociation is produced at the well. For all the cases in Fig. 4, both QPT and the corresponding QPG curves show nearly the same pattern in the early production stage. This can be attributed to the small dissociation area around the production well and the high driving force for released gas, which leads to that all of the released gas from dissociation directly flows into the production well. While it is opposite in the following stage, the difference between QPG and QPT increase gradually with time. Especially for the cases of Rhv = 1.0, 2.0 and 5.0, no free gas is produced at the well after 302 days, 452 days and 811 days, respectively. In addition, the comparison for the different cases indicates that the increase of Rhv can slow down the peak production rate, and the high Rhv leads to a high CH4 production rate during Stage 3, which is consistent with the evolution of QR indicated by Fig. 3.
4. Results and discussions In this section, numerical simulation is conducted to investigate the gas production behaviors based on the constructed sand-dominated reservoir model. The effect of permeability anisotropy (Rhv = 1.0, 2.0, 5.0 and 10.0) on the evolution of gas and water production, and the distribution of characteristic parameters is discussed and analysed in detail. In addition, for the convenience of comparison and analysis, all the quantitative data described in Section 4.1 represents (unless otherwise noted) the result per meter length of the horizontal well (ΔY = 1 m). 4.1. Evolution of gas and water production 4.1.1. CH4 production rate Fig. 3 shows the evolution of CH4 release rate from hydrate dissociation (QR) per meter well length for the four different Rhv (1.0, 2.0, 5.0 and 10.0) cases. It can be observed for the Rhv = 1.0 case that the evolution of QR is characterized by an initial short period (Stage 1, to t = 11 days) of rapid increase, is succeeded by a period (Stage 2) of relatively constant release rate that lasts until t = 25 days, and is followed by a long period (Stage 3) of continuous decline. Among these stages, Stage 1 is associated with the severe hydrate dissociation around the production well. As the production progresses, the hydrate dissociation zone around the production well continuously and radially expands. On the other hand, the driving force (pressure gradient between the production well and the hydrate dissociation front) for hydrate dissociation gradually decreases. Thus, QR tends to remain a stable value during Stage 2. Stage 3 is strongly related to the decomposition of the hydrate between the production well and the permeable underburden, which serves as the water blocking layer (which hinders the aqueous phase in the underburden from flowing into the well). When this happens, the pressure gradient between the production well and the hydrate dissociation front further decreases, which significantly weakens the depressurization effect on hydrate dissociation and results 820
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Fig. 6. Evolution of free CH4 (VF) remaining in the reservoir for the different Rhv cases. Fig. 4. Evolution of volumetric rate of the total CH4 production at the well (QPT) and of the CH4 production in gas phase (QPG) for the different Rhv cases.
because that the hydrate release rate is relatively higher, and more and more released gas cannot flow into the production well in a timely manner, and remains and accumulates in the reservoir. However, after that stage, VF decreases with time, indicating that the remaining free CH4 gradually flows into the production well. In addition, by comparing Figs. 6 and 5, it can be found that VF is far less in comparison to VPT and VPG for each case. This further confirms that most of the CH4 released from hydrate dissociation is produced at the production well. Moreover, the comparison for the different Rhv (1.0, 2.0, 5.0 and 10.0) cases indicates that the high Rhv leads to more free gas accumulated in the reservoir. This can be attributed to the low permeability in the vertical direction. And for these cases, VF peaks on the 24th day, the 41st day, the 97th day and the 200th day, which exactly correspond to the later part of Stage 2 (as shown in Fig. 3).
4.1.2. Cumulative volume of CH4 production Fig. 5 shows the evolution of the total CH4 production (VPT) and of the CH4 production in gas phase (VPG) per meter well length for the four different Rhv (1.0, 2.0, 5.0 and 10.0) cases. For all the cases, VPG is greatly lower in comparison to the corresponding VPT in the late production stage, i.e., VPG at the end of the production periods reaches 6.08 × 104 ST m3, 7.64 × 104 ST m3, 1.07 × 105 ST m3, and 1.37 × 105 ST m3, accounting for 41.7%, 46.1%, 51.9%, and 64.6% of each VPT. In addition, the high Rhv case appears to have lower VPT and VPG than those of low Rhv case in the early production stage, but the trend reverses in the later stage. This could be attributed to the high CH4 production rate for high Rhv case in Stage 3. The above results indicate that the permeability anisotropy (high Rhv) has a positive effect on long-term gas production. And this is consistent with the study of the effect of permeability anisotropy on gas production from a cold, stratigraphically-bounded gas hydrate deposit with horizontal well (Moridis et al., 2011), in which the low-temperature hydrate-bearing layer is confined by impermeable overburden and underburden. Fig. 6 shows the evolution of cumulative volume of the free CH4 remaining in the reservoir (VF) per meter well length for the four different Rhv (1.0, 2.0, 5.0 and 10.0) cases. It is found for all cases that VF appears to increase rapidly in the early production stage. This is
4.1.3. Water production and gas-to-water ratio Fig. 7 shows the evolution of water production (VW) per meter well length for the four different Rhv (1.0, 2.0, 5.0 and 10.0) cases. For all the cases, VW increases slowly in the early production stage. However, as the production processes, VW increase linearly with a high and stable production rate. The reason is that a large amount of water from the underburden flows into the production well due to the decomposition of water blocking layer. The comparison for the different Rhv (1.0, 2.0, 5.0 and 10.0) cases indicates that VW decreases with an increasing Rhv.
Fig. 5. Evolution of cumulative volumes of the total CH4 production at the well (VPT) and of the CH4 production in gas phase (VPG) for the different Rhv cases.
Fig. 7. Evolution of water production (VW) at the well for the different Rhv cases. 821
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resulting in a high cost of lifting the water to the sea level. Thus, water management is an important aspect in the design and analysis of longterm gas production from such Nankai Trough reservoirs. Fig. 8 shows the evolution of gas-to-water ratio (RGW) for the four different Rhv (1.0, 2.0, 5.0 and 10.0) cases. RGW is regarded as a relative criterion to evaluate the production performance, and is computed as RGW = VPT/VW (the volume of CH4 produced from the well per unit volume of produced water). It is clear that a high RGW means better economy in CH4 production from methane hydrate reservoirs. As shown in Fig. 8, RGW increases rapidly during the early production stage because of high CH4 production rate and low water production rate. And for these (Rhv = 1.0, 2.0, 5.0 and 10.0) cases, RGW reaches its maximum value at the 9th day, the 10th day, the 11th day, and the 14th day, respectively. Beyond that time, RGW shows a sharp decline and then maintains a relatively stable value in the later production stage. In addition, the comparison for the different Rhv (1.0, 2.0, 5.0 and 10.0) cases indicates that the high Rhv case has a high gas-to-water ratio during the entire production stage, especially in the early stage. This suggests that the high Rhv case has a better production performance over the low Rhv case in the relative criterion. The findings of these observations in the evolution of water and gas production clearly demonstrate that permeability anisotropy has complex effects on the gas production. The permeability anisotropy can initially negatively influence hydrate dissociation and CH4 production,
Fig. 8. Evolution of gas-to-water ratio (RGW) for the different Rhv cases.
This is associated with the decreasing of permeability in the vertical direction, which hinders the water from the underburden flowing into the HBL. The above results indicate that a large amount of water will be produced for the hydrate reservoirs with high vertical permeability,
Fig. 9. Evolution of the pressure (P) distribution for (a) Rhv = 1.0 and (b) Rhv = 10.0 cases. 822
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Fig. 10. Evolution of the temperature (T) distribution for (a) Rhv = 1.0 and (b) Rhv = 10.0 cases.
processes. Therefore, the QR and QPT show a decline trend in the long run (as shown in Figs. 3 and 4). Moreover, it can be observed at t = 90 days that the low-pressure front has reached the underburden, meaning that hydrate dissociation can occur in the region between the production well and the underburden. After that, the evolution of the pressure distribution is not very noticeable. This can be explained by the fact that the hydrate between the production well and the permeable underburden completely dissociates, leading to large amount of water flowing into the production well, and thus the low-pressure front can not further advance in the HBL. When increasing Rhv to 10.0, as shown in Fig. 9(b), the low-pressure front seems to advance horizontally and preferentially along the top part of the HBL. This is associated with the relatively high permeability in the horizontal direction. After t = 270 days, the pressure distribution barely changes, which may be attributed to the destruction of the water blocking layer (hydrate between the production well and the permeable underburden). In addition, the comparison of Fig. 9 (a) and Fig. 9 (b) indicates that the HBL in the high Rhv case can keep a lower pressure for a long time, meaning that higher Rhv is beneficial for keeping the depressurization effect during production.
but later promote the process. Meanwhile, permeability anisotropy can lead to high ratio of gas phase to total production and gas-to-water ratio. Therefore, it is important to consider the permeability anisotropy effect in the prediction of long-term gas production from such Nankai Trough reservoirs. 4.2. Evolution of characteristic parameters From the above analysis, when increasing Rhv from 1.0 to 2.0, 5.0 and 10.0, the changes of the gas production behaviors follow the similar trend, although the changes are different in absolute terms. Therefore, for simplify the analysis, only the evolutions of characteristic parameters in the Rhv = 1.0 and 10.0 cases are discussed in this section. Figs. 9–12 show the evolution of pressure (P), temperature (T), hydrate saturation (SH), and gas saturation (SG) distributions within the first 360 days. Dashed lines in these figures indicate the initial positions of the top and bottom of HBL, respectively. 4.2.1. Spatial distribution of pressure P Fig. 9 shows the evolution of pressure distribution during hydrate dissociation process for the Rhv = 1.0 and 10.0 cases. For the Rhv = 1.0 case, the low-pressure front expands radically in the early production stage (Fig. 9(a), t = 10, 30, and 90 days), and the pressure in HBL decreases gradually with time, which suggests that the driving force for hydrate dissociation and gas production decreases as production
4.2.2. Spatial distribution of temperature T Fig. 10 shows the evolution of temperature distribution during hydrate dissociation process for the Rhv = 1.0 and 10.0 cases. The comparison of Fig. 10(a) and (b) indicates that the temperature distribution 823
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Fig. 11. Evolution of the hydrate saturation (SH) distribution for (a) Rhv = 1.0 and (b) Rhv = 10.0 cases.
geothermal gradient in the overburden. In addition, it is clear that the high-temperature fluid from the underburden flows into the production well after t = 270 days, which occurs later than that of Rhv = 1.0 case. The above results provide the confirmation that the high Rhv can delay the onset time of high-temperature water (which comes from the underburden) flowing into the HBL.
of HBL is strongly affected by the degree of permeability anisotropy and shows different characteristics. For the Rhv = 1.0 case, a low-temperature zone can be observed around the production well in the early production stage (Fig. 10(a), t = 10 days), which can be attributed to the significant endothermic dissociation reaction under the condition of high pressure gradient. Meanwhile, another slightly low-temperature zone appears along the bottom of the HBL, indicating hydrate dissociation reaction in this region. This is caused by the continuing geothermal heat inflows from the underburden. However, during t = 30–360 days, these low-temperature zones gradually disappear, and a large amount of high-temperature water from the underburden flows into the HBL, resulting in a high temperature in the region where hydrate completely dissociates. When increasing Rhv to 10.0, as shown in Fig. 10(b), the low-temperature zone continues to expand horizontally along the top half of the HBL for a very long period (Fig. 10(b), t = 10–180 days), which indicates that hydrate dissociates preferentially along the top part of the HBL, which can be attributed to the strong depressurization effect in this region (as shown in Fig. 9(b)). In addition, an inversion of the geothermal gradient can be observed in the overburden after t = 90 days. This phenomenon can be explained by the fact that intense hydrate dissociation consumes a large amount of sensible heat and leads to temperature decline in the top of the HBL, and thus heat will transfer from the overburden to the HBL, resulting in the reversal of the
4.2.3. Spatial distribution of hydrate saturation SH Fig. 11 shows the evolution of the hydrate saturation distribution during dissociation process for the Rhv = 1.0 and 10.0 cases. For the Rhv = 1.0 case, there is a hydrate-free zone around the production well and the hydrate dissociation zone advances with an expanding radius in the early production stage (Fig. 11(a), t = 10 days), which is consistent with the temperature change in Fig. 10(a). After that time, the dissociation front reaches the interface between the HBL and the underburden, and the hydrate begins to dissociate mainly along the base of the HBL, accompanying with a slow-moving dissociation front that is clearly identifiable. This is due to the fact that the depressurization effect is weakened after the decomposition of the hydrates between the production well and the permeable underburden, and thereafter the dissociation is mainly controlled by the heat transfer with the hightemperature inflows from the underburden. When increasing Rhv to 10.0, as shown in Fig. 11(b), it can be observed that the dissociation zone in the early production stage 824
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Fig. 12. Evolution of the gas saturation (SG) distribution for (a) Rhv = 1.0 and (b) Rhv = 10.0 cases.
Fig. 14. Comparison of the gas production rates QPT between the horizontal well production and vertical well production within the first 360 days.
Fig. 13. Evolution of the gas production rates QPT within the first 6 days.
(Fig. 11(b), t = 10 days) is much smaller than that of Rhv = 1.0 case, which is caused by the low permeability in the vertical direction. But thereafter, the dissociation zone expands horizontally along the top half of the HBL for a very long period (Fig. 11(b), t = 30, 90 and 180 days). Meanwhile, the bottom of the HBL shows a horizontal hydrate-free zone (Fig. 11(b), t = 180 days), indicating the hydrate dissociation reaction in this region. And the hydrate between the production well and the permeable underburden decomposes completely after t = 270 days. In addition, it is clear that the dissociation zone can move far away from the production well in the horizontal direction compared with that of
Rhv = 10.0 case. The above results provide further confirmation that high Rhv is benefit for enhancing the horizontal flow, facilitating the dissociation and keeping the depressurization effect for a long period.
4.2.4. Spatial distribution of gas saturation SG Fig. 12 shows the evolution of the gas saturation distribution during hydrate dissociation process for the Rhv = 1.0 and 10.0 cases. For the Rhv = 1.0 case, in the early production stage (Fig. 12, t = 10 days), the free CH4 mainly accumulates in the dissociation zone around the 825
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corresponds to the rectangular reservoir model with a 628 m-long horizontal well. A vertical production interval (12 m), located along the axis of the cylindrical model, is placed in the upper part of the HBL, which is the same as that applied in the field test (the length of the production interval is 40 m, and only a 12 m-long production interval is applied in the lower MH zone) of the Eastern Nankai Trough in 2013. And the wellbore pressure is the same as that of horizontal well production. Fig. 13 shows the evolution of gas production rates QPT by using the vertical well within the first 6 days. Meanwhile, the field data (Konno et al., 2017) at the Eastern Nankai Trough in 2013 is presented in Fig. 13. It can be observed from Fig. 13 that the gas production rate from the vertical well is close to that in field observation, which greatly proves the reasonability and reliability of the numerical code and the constructed model in this study. It should be noted that the hydrate concentrated interval in the field production test is nearly 60 m, which is composed of thin alternations of sand and mud layers in the upper part and relatively thick sand-dominant sequences in the lower part. While in this study, only the thick sand-dominant sequences in the lower part is considered in the numerical simulation. Therefore, the simulated results for the vertical well are slightly lower than that in field observation. Fig. 14 shows the evolution of QPT during a long-term gas production for 360 days by using the vertical well and the horizontal well. An interesting observation from the vertical well case is that the permeability anisotropy seems to have less effect on gas production in the initial short stage (t < 60 days), but in the late long stage, the QPT for Rhv = 10.0 case keeps a higher value compared with that of Rhv = 1.0 case. This indicates that the gas production process in the early stage are less influenced by the vertical permeability, and highly depends on the horizontal dissociation and flow when using the vertical well. In addition, it is found that the use of horizontal well (the length is 628 m) appears to increase the gas production rate by one order of magnitude. This greatly proves the higher performance of horizontal well. Fig. 15 shows the comparison of the total CH4 production VPT between the horizontal well production and vertical well production within the first 360 days. For the horizontal well production, the VPT of Rhv = 10.0 case is less than that of Rhv = 1.0 case for a very long time, and both VPT curves converges at the end of 360-day-long production period. However for the vertical well production, the VPT of Rhv = 10.0 case outpaces that of Rhv = 1.0 case after t = 120 days, which is associated with the high QPT for Rhv = 10.0 case (as shown in Fig. 14). Other than these, more information of gas production performance by using the vertical well and horizontal well is listed in Table 3. It is observed that the use of horizontal well shows high average gas production rate, which are 2.41 × 105 ST m3/d for Rhv = 1.0 and 2.50 × 105 m3/d for Rhv = 10.0, respectively. In addition, for both the horizontal well production and vertical well production, the gas-towater ratio is dramatically improved when increasing Rhv from 1.0 to 10.0. Moreover, the gas-to-water ratio for the horizontal well production is lower than that for the vertical well production. This can be attributed to the longer production well for the horizontal well case, which contributes more to water production than CH4 production after the decomposition of the hydrates between the production well and the permeable underburden, and thus leads to a lower gas-to-water ratio in comparison to that in the vertical well case. It is clear from the above comparison that the use of horizontal well appears to be very effective for gas production from such Nankai Trough reservoirs, and the permeability anisotropy plays an especially important role in the hydrate dissociation process by depressurization no matter which type of production well (horizontal well and vertical well) is employed. While the average gas production rate from the horizontal well is still lower than the requirement of commercial production (3.0 × 105 m3/d), it is possible that the gas production performance can be further enhanced with longer horizontal well, different well configurations and more complex production strategies. The
Fig. 15. Comparison of the total CH4 production VPT between the horizontal well production and vertical well production within the first 360 days. Table 3 Comparison of the gas production performance within the first 360 days. Simulated result
Horizontal well Rhv = 1.0
Total gas production (ST m3) Average gas production rate (ST m3/d) Average gas-to-water ratio (ST m3/m3)
7
Vertical well
Rhv = 10.0 7
Rhv = 1.0 6
Rhv = 10.0 6.4 × 106
9.0 × 10
4.3 × 10
2.41 × 105
2.50 × 105
1.20 × 104
1.78 × 104
0.47
6.9
2.4
8.9
8.7 × 10
production well. But thereafter, the gas accumulation zone shrinks and the corresponding gas saturation gradually decreases (Fig. 12, t ≥ 30 days). This is consistent with the declining trend of VF during production stage (as shown in Fig. 6). This phenomenon is caused by the water flow from the underburden and the weakening dissociation reaction. In addition, combined with the corresponding temperature distribution in Fig. 10(a) and hydrate saturation distribution in Fig. 11(a), it is clear that no free CH4 exists in the hydrate-free zone (Fig. 12, t ≥ 30 days) that is occupied by the higher-temperature water. When increasing Rhv to 10.0, as shown in Fig. 12(b), it can be observed that more and more free CH4 accumulates in the half top of the HBL for a long production period (Fig. 12(b), t = 30, 90 and 180 days), which is consistent with the evolution of VF in Fig. 6. This can be attributed to the low permeability in the vertical direction, which inhibits the fluid flow and pressure transfer, resulting in large amount of accumulated free CH4 in the dissociation zone. As time passes (Fig. 12(b), t = 270 and 360 days), the gas saturation pattern shows the same tend as that of Rhv = 1.0 case, the gas accumulation zone shrinks and the corresponding gas saturation gradually decreases. The above results further indicate that the high Rhv can lead to the increment of free CH4 remained in the reservoir during the production period. 4.3. Comparison of the productions using a horizontal well and a vertical well In this section, the effect of permeability anisotropy on gas production is compared between horizontal well production and vertical well production. Firstly, we construct a cylindrical reservoir model, which has the same hydrate volume, initial conditions and production pressure with the above-mentioned rectangular reservoir model. The radius of the cylindrical reservoir model is 200 m, which exactly 826
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findings of this study provide a reference for the analysis and future commercial production targeting such Nankai Trough reservoirs.
S SirA SirG T T VF
phase saturation irreducible water saturation irreducible gas saturation time (day) temperature (°C) cumulative volume of free gas CH4 remaining in reservoir (ST m3) VPG cumulative volume of produced CH4 in gas phase (ST m3) VPT cumulative volume of total produced CH4 (ST m3) VW cumulative volume of produced water (ST m3) Greek symbols
5. Conclusions In this study, a reservoir-scale model was constructed to investigate the effect of permeability anisotropy on gas production behavior by depressurization with a horizontal well. The evolutions of gas and water production, and the temperature and saturation fields during the hydrate dissociation process were analysed in detail at different degrees of permeability anisotropy. In addition, the gas production performance by using horizontal well and vertical well is compared and discussed. The main results obtained in this study are summarized as follows:
ϕ porosity λ van Genuchten exponent Superscripts and subscripts
a Permeability anisotropy has complex effects on the production performance when using the horizontal well. The permeability anisotropy can initially negatively influence the hydrate dissociation and gas production, but later promote the process. Meanwhile, permeability anisotropy can lead to an increase of ratio of gas phase to total production and gas-to-water ratio. b Permeability anisotropy can enhance the horizontal flow, facilitate the dissociation, and keep the depressurization effect in the top part of the HBL for a long period. However, it also leads to an increase of the free gas in the reservoir during the production period. c A large amount of water is produced from the well during the late production stage, due to the decomposition of hydrate between the production well and the permeable underburden. Thus, water management is an important aspect in the design and analysis of long-term gas production from such hydrate reservoirs. d The use of horizontal well appears to be very effective for gas production from such sand-dominated hydrae reservoirs in the Eastern Nankai Trough. During a production period of 360 days, the horizontal well can increase the gas production by one order of magnitude than that of vertical well. e Permeability anisotropy has less effect on was production in the initial short stage when using the vertical well.
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Acknowledgments This work was supported by the JST-CREST Project (No. JPMJCR13C4: Breakthrough on Multi-Scale Interfacial Transport Phenomena in Oceanic Methane Hydrate Reservoir and Application to Large-Scale Methane Production). Appendix A. Supplementary data Supplementary data to this article can be found online at https:// doi.org/10.1016/j.marpetgeo.2019.01.041. Nomenclature d k kh kv L N P P0 QPG QPT QR RGW Rhv
aqueous phase hydrate phase gas phase
grain diameter (μm) absolute permeability (mD, 1 Darcy = 10−12 m2) absolute permeability in horizontal direction (mD) absolute permeability in vertical direction (mD) length of production well (m) relative permeability index pressure (MPa) atmospheric pressure (MPa) volumetric rate of produced CH4 in gas phase (ST m3/day) volumetric rate of total produced CH4 at well (ST m3/day) volumetric rate of CH4 released from hydrate dissociation (ST m3/day) ratio of gas to water production (ST m3 of CH4/m3 of H2O) ratio of horizontal permeability (kh) to vertical permeability (kv) 827
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