Energy Fuels 2010, 24, 6353–6358 Published on Web 11/10/2010
: DOI:10.1021/ef1008727
Numerical Analysis of the Dissociation Experiment of Naturally Occurring Gas Hydrate in Sediment Cores Obtained at the Eastern Nankai Trough, Japan Yoshihiro Konno,*,† Hiroyuki Oyama,† Jiro Nagao,*,† Yoshihiro Masuda,‡ and Masanori Kurihara§ † Production Technology Team, Methane Hydrate Research Center, National Institute of Advanced Industrial Science and Technology (AIST), 2-17-2-1 Tsukisamu-Higashi, Toyohira-ku, Sapporo 062-8517, Japan, ‡Frontier Research Center for Energy and Resources (FRCER), School of Engineering, The University of Tokyo, 7-3-1 Hongo, Bunkyo-ku, Tokyo 113-8656, Japan, and § Petroleum Engineering & Consulting Department, Japan Oil Engineering Co. Ltd., Kachidoki Sun-Square, 1-7-3 Kachidoki, Chuo-ku, Tokyo 104-0054, Japan
Received July 8, 2010. Revised Manuscript Received October 19, 2010
Oceanic gas hydrate deposits at high saturations have been found within continuous thick sands in areas such as the Eastern Nankai Trough and the Gulf of Mexico. The recent discovery of these deposits has stimulated research and development programs exploring the use of gas hydrates as energy resources. Because the permeability of hydrate-bearing sediments is a crucial factor for successful gas production from oceanic hydrate reservoirs, the permeability of these sediments and the dissociation process of hydrates should be investigated using hydrate cores obtained at these oceanic hydrate reservoirs. In this study, to investigate the permeability of actual hydrate-bearing sediments and the dissociation process of hydrates by a depressurization method, a numerical simulation was conducted using a state-of-the-art hydrate reservoir simulator. A dissociation experiment of hydrate-bearing sandy cores obtained from turbidite sediments at the Eastern Nankai Trough was analyzed. By choosing appropriate model parameters, the simulator precisely reproduces the dissociation behavior such as cumulative gas production, cumulative water production, and pressure change. The model parameters associated with permeability indicate a pore-filling tendency rather than a coating tendency of the hydrate in the pore space. Although the permeability of the hydrate-bearing cores obtained at hydrate reservoirs in nature was relatively low, the effective water permeability obtained in this study seems promising for achieving depressurization-induced hydrate dissociation. It has been found that the pressure reduction propagates deeply into the hydrate-bearing zone and the hydrate is spatially dissociated. Also, the permeability is beyond the lower limit of threshold permeability, which is absolutely necessary for successful gas production by depressurization. This study confirms the advantage of employing depressurization as a gas production method, using the hydrate in sandy turbidite sediments at the Eastern Nankai Trough as our test sample. The numerical analysis method used is effective to analyze the dissociation behavior of hydrate-bearing cores obtained at natural hydrate reservoirs, and it enables evaluation of gas productivity in those reservoirs.
(3) inhibitor (such as methanol) injection.3 Depressurization is a method used to dissociate gas hydrates by lowering the wellbore pressure below the hydrate stability pressure; this is considered to be the most promising production method because of its ability to provide the highest energy profit ratio. Experimental studies on depressurization-induced gas production are being conducted using artificial hydrate-bearing cores,4 and numerical simulations have been conducted to predict gas production behavior by using hypothetical reservoir models or models roughly mimicking actual reservoirs, or both.5,6 For the success of depressurization-induced gas production, it is crucial that hydrate-bearing sediments should have effective permeability higher than the threshold value, such that the reduced pressure propagates deeply into the hydrate-bearing zone.7 Although the permeability of
1. Introduction Gas hydrates are crystalline solids in which gas molecules are trapped inside a cage of water molecules.1 Large quantities of natural gas are trapped within natural gas hydrates in the oceanic and permafrost environments. Over the last few decades, much attention has been directed toward natural gas hydrates as energy resources and for environmental issues.2 In the 2000s, the potential for using gas hydrates as energy resources has stimulated national research and development programs in several countries such as Japan, United States, Canada, India, China, and South Korea. Following are the proposed three major methods of hydrate recovery: (1) depressurization, (2) thermal stimulation, and *To whom correspondence should be addressed. Telephone: þ81-11857-8949. Fax: þ81-11-857-8417. E-mail:
[email protected] (Y.K.); Telephone: þ81-11-857-8948. Fax: þ81-11-857-8417. E-mail:
[email protected] (J.N.). (1) Sloan, E. D.; Koh, C. A. Chemical Industries Series 119; CRC Press: Boca Raton, FL, 2008. (2) Kvenvolden, K. A. Proc. Natl. Acad. Sci. U. S. A. 1999, 96, 3420– 3426. (3) Makogon, Y. F. Hydrates of Hydrocarbons; Penn Well Publishing Co.: Tulsa, OK, 1997. r 2010 American Chemical Society
(4) Oyama, H.; Konno, Y.; Masuda, Y.; Narita, H. Energy Fuels 2009, 23 (10), 4995–5002. (5) Moridis, G. J.; Sloan, E. D. Energy Convers. Manage. 2007, 48, 1834–1849. (6) Kurihara, M.; Sato, A.; Ouchi, H.; Natrita, H.; Masuda, Y.; Saeki, T.; Fujii, T. SPE Reserv. Eval. Eng. 2009, 12 (3), 477–499. (7) Konno, Y.; Masuda, Y.; Hariguchi, Y.; Kurihara, M.; Ouchi, H. Energy Fuels 2010, 24 (3), 1736–1744.
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: DOI:10.1021/ef1008727
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Figure 1. Sampling location at the Eastern Nankai Trough.
hydrate-bearing sediments at actual reservoirs is a key geophysical property for successful depressurization, it is poorly understood. Currently, large hydrate deposits at high saturations have been found within continuous thick sands from oceanic environments such as the Eastern Nankai Trough offshore Japan and the Gulf of Mexico. In the Eastern Nankai Trough, the high saturation of gas hydrate in sandy layers has been confirmed by the well logging and coring operations.8 On the other hand, in the Gulf of Mexico, the gas hydrate at high saturation in sandy layers has been confirmed by the well logging.9 In 2012, the world’s first offshore gas production test by the depressurization method is scheduled to be conducted at the Eastern Nankai Trough.10 The fluid flow properties of hydrate-bearing sediments in this area should be investigated to ensure the success of the depressurization process. Using a hydrate-bearing sandy core obtained from turbidite sediments at the Eastern Nankai Trough and a state-of-the-art hydrate reservoir simulator, we investigate how the permeability of hydrate-bearing sediments changes under depressurization, causing the hydrates to dissociate. It will also demonstrate the feasibility of depressurization-induced gas production from a hydrate reservoir in this area. This study is the first study to analyze the dissociation behavior of the hydrate-bearing cores obtained at actual hydrate reservoirs by an experimental method combined with a numerical simulation.
Figure 2. Schematic of the experimental apparatus.
sampling location is shown in Figure 1. Exploratory wells were drilled during the drilling program of the Ministry of Economy, Trade and Industry (METI) Tokai-oki to Kumano-nada in 2004, under Japan’s National Methane Hydrate R&D Program, aboard the RV JOIDES Resolution, the details of which are summarized elsewhere.11 The core sample was obtained at a depth of 886.14-886.25 m (162.14-162.25 m below seafloor) by using the pressure temperature core sampler (PTCS). To prevent the hydrate from dissociating during core sampling, PTCS maintained the pressure and temperature of the core sample under in situ conditions. The recovered core sample was then stored and transported at liquid N2 temperature to minimize hydrate dissociation. Core properties, such as molecular composition of hydrocarbons and hydration number, were estimated for the core samples obtained at the same well.12 The molecular composition of the hydrocarbon in the released gas was measured as 99.9% methane by gas chromatography. The hydration number was estimated to be 6.1-6.2 by 13C NMR and Raman measurements. Prior to conducting the dissociation experiment, the structure of the core sample was identified using an X-ray CT scanner,13 and the sediment type of the core sample was characterized as a fine-grained sandy turbidite. According to the Bouma Sequence,14 the sediment type of the core sample was characterized as Ta. The mean diameter of the sediment grain was measured as 135 μm by a laser diffraction scattering method using a particle size distribution analyzer. A hydrate saturation of 52%, water saturation of 40%, and gas saturation of 8% were calculated using the material balance of the dissociation experiment. The host sediment porosity was estimated to be 45.2% by
2. Experimental and Numerical Analyses Hydrate Core Samples. The hydrate core samples used in this study were recovered from the Eastern Nankai Trough; this (8) Fujii, T.; Saeki, T.; Kobayashi, T.; Inamori, T.; Hayashi, M.; Takano, O.; Takayama, T.; Kawasaki, T.; Nagakubo, S.; Nakamizu, M.; Yokoi, K. Proceedings of Offshore Technology Conference, 2008; No. 19310. (9) Boswell, R.; Collett, T.; Frye, M.; McConnell, D.; Shedd, W.; Dufrene, R.; Godfriaux, P.; Mrozewski, S.; Guerin, G.; Cook, A. Gulf of Mexico Gas Hydrate Joint Industry Project Leg 2: Technical Summary of NETL, 2009. (10) Masuda, Y.; Yamamoto, K.; Tadaaki, S.; Ebinuma, T.; Nagakubo, S. Fire in the Ice Methane Hydrate Newsletter of NETL 2009, 9 (4), 1–6.
(11) Takahashi, H.; Tsuji, Y. Proceedings of Offshore Technology Conference, 2005; No. 17162. (12) Kida, M.; Suzuki, K.; Kawamura, T.; Oyama, H.; Nagao, J.; Ebinuma, T.; Narita, H.; Suzuki, H.; Sakagami, H.; Takahashi, N. Energy Fuels 2009, 23 (11), 5580–5586. (13) Suzuki, K.; Ebinuma, T.; Narita, H. J. Geogr. 2009, 118(5), 899-912 (in Japanese). (14) Bouma, A. H. Sedimentology of Some Flysch Deposits: A Graphic Approach to Facies Interpretation; Elsevier: Amsterdam, 1962.
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measuring the bulk volume, the sand grain density, and the sand weight of the core. Experimental Setup and Procedure. Figure 2 shows a schematic of the experimental apparatus used for the experiment, and a detailed description of the experimental apparatus is referred to in the published literature.4 A cylindrical core was maintained at constant pressure and temperature in the core holder. Triaxial confining pressure was applied to the core by using a rubber sleeve and end plugs, and the temperature of the core holder was controlled by circulating a brine solution through the surrounding jacket. The core sample was pressurized using pure methane gas to eliminate air/N2 contamination during the core handling. This pressurization was conducted under equilibrium conditions to avoid the reformation of hydrate. After this treatment, most of the pore space was saturated by water under equilibrium conditions. The pore pressure and confining pressure were 10.0 and 11.5 MPa, respectively, and the temperature was set to 12.5 °C. The pressure at the production line was maintained using a back pressure regulator valve (BPR) set to a production pressure of 5 MPa, and a stop valve on the production line was then opened to depressurize the core. The volume of gas and water produced and the pressure and temperature at both end surfaces of the core were measured and recorded. The effective water permeability was measured prior and subsequent to the experiment. Lateral sensor taps were not used in this study. Numerical Simulation. Numerical studies were conducted using the state-of-the-art hydrate reservoir simulator, MH21HYDRES, developed by the University of Tokyo, Japan Oil Engineering Co., Ltd., and National Institute of Advanced Industrial Science and Technology.15,16 The MH21-HYDRES is capable of solving four-phase (gas, water, ice, and hydrate) and five-component (methane, nitrogen, water, methanol, and salt) problems. Various models are incorporated in this code to describe the phenomena related to hydrate dissociation and formation and flow of fluids in sediments, including the heat transfer by conduction and convection. Fluid flows are modeled on the basis of Darcy’s law, and hydrate dissociation/formation and ice formation/melting are modeled using kinetic equations. Energy and mass balance equations are solved by the Newton-Raphson method. The MH21-HYDRES has been validated by comparing the predictions obtained using this code with the experimental data, as well as through a comparative study of several hydrate reservoir simulators.16,17 Detailed theories, on which the models are based, are mentioned in the previous study.7 The input data and model parameters used in this study are listed in Table 1. Grid System. The cylindrical coordinate system was used for the simulation of the core experiment. The core section was divided into 10 44 discrete grids in (r, z). The diameter and the length of the core were 50.0 mm and 110.9 mm, respectively, and the core was uniformly divided along the r-z axis. The rubber sleeve (4 46 grids) was placed at the periphery of the core to simulate accurate heat flow from the surroundings. In addition, the pipe of the production line (1 12 grids), the end plug of the core holder (13 1 grids), and the porous filter at the end surface of the core (10 2 grids) were modeled to simulate accurate fluid/heat flow. The pipe of the production line and the porous filter was saturated by water at the initial condition. Gas and water were produced from the pipe of the production line, and the other end surface and the periphery of the rubber sleeve were
Table 1. Input Data and Model Parameters initial temperature (°C) initial pressure (MPa) production pressure (MPa) core radius (mm) core length (mm) saturation porosity thermal conductivity (W/m/K) specific heat (J/kg/K) sand grain density (kg/m3) initial effective water permeability (10-3 μm2 = md) absolute permeability (10-3 μm2 = md)a permeability reduction index, Na end-point relative permeability to water and gas: krw0, krg0a irreducible saturation to water and gas: Siw, Siga relative permeability index to water: Nwa relative permeability index to gas: Nga capillary entry pressure: Pe (Pa) a pore size distribution index: nca hydration number a
12.5 10.0 5.0 25.0 110.9 hydrate: 0.52; water: 0.40; gas: 0.08. 0.452 sand particle: 4.0; gas: 0.0335; water: 0.5564; hydrate: 0.49. sand: 800; hydrate: 2010. 2650 3.9 100 4.4 each 1 each 0.1 2 4 12000 0.50 6.1
History matching parameter.
set as a no-flow boundary. A heat-transfer coefficient was applied as the thermal boundary condition to all the boundary grid blocks. The pressure measured at the production line was used as the boundary pressure condition. The measured values are time-series data as shown in Figure 3 (Production Pres). The temperature of the circulating brine solution was used as the boundary temperature condition.
3. Results Simulation. Figure 3 shows the pressure history at the end surface opposite to the production line (bottom end surface, P1 in Figure 2) obtained by the experiment and the simulation. The production pressure (P2 in Figure 2) is also shown in Figure 3. The first ten minutes are detailed in the bottom panel. The pressure at the bottom end surface gradually decreases toward the production pressure, even though the pressure of the production line is depressurized to the production pressure immediately. This time lag in decreasing toward the production pressure strongly depends on the permeability of hydrate-bearing sediments. The initial effective water permeability in the presence of the hydrate was measured as 3.0-4.8 md. The permeability change due to hydrate formation/dissociation is given by kD ¼ kD0 ð1 - SH ÞN
ð1Þ
where kD is the permeability of hydrate-bearing sediments, kD0 is the absolute permeability of host sediments, SH is the hydrate saturation, and N is the permeability reduction index.15 The value of N depends on the structure of the flow channel in hydrate-bearing sediments, which is related to the hydrate occurrence in the pore space and the pore structure of the host sediments. Its theoretical estimate for the capillary hydrate-coating model is N = 2 and for the grain hydrate-coating model is N = 2.5.18 As the hydrate fills at high saturation and shows the pore-filling tendency rather
(15) Masuda, Y.; Naganawa, S.; Ando, S.; Sato, K. Proceedings of SPE Asia Pacific Oil & Gas Conference and Exhibition, 1997; No. 38291. (16) Masuda, Y.; Konno, Y.; Kurihara, M.; Ouchi, H.; Kamata, Y.; Ebinuma, T.; Narita, H. Proceedings of the 5th International Conference on Gas Hydrates, 2005; pp 1076-1085. (17) Wilder, J. W.; Moridis, G. J.; Willson, S. J.; Kurihara, M.; White, M. D.; Masuda, Y.; Anderson, B. J.; Collett, T. S.; Hunter, R. B.; Narita, H.; Pooladi-Darvish, M.; Rose, K.; Boswell, R. Proceedings of the 6th International Conference on Gas Hydrates, 2008; No. 5727.
(18) Kleinberg, R. L., Flaum, C.; Griffin, D. D.; Brewer, P. G.; Malby, G. E.; Peltzer, E. T.; Yesinowski, J. P. J. Geophys. Res., [Solid Earth] 2003, 108 (B10), 2508.
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Figure 4. Cumulative gas and water production. Figure 3. Pressure at the bottom end surface and production pressure.
more active, because the dissociation depended on the heat supply from the outer boundary. The results indicate that the fluid flow properties of the hydrate-bearing core were such that the pressure wave caused by the reduced pressure at the production line propagated deeply into the hydrate-bearing zone.
than the coating tendency, the value of N increases. In this study, the combination of N and kD0 was investigated to reproduce the pressure behavior. By history-matching simulations, the values of N = 4.4 and kD0 = 100 md matched the simulation results and the measured data when the initial effective water permeability was 3.9 md. On the other hand, in the experiment, the effective water permeability after hydrate dissociation was measured as 1.2 md. Figure 4 shows the history of cumulative gas volume and water volume produced. The first ten minutes are also detailed in the bottom panel. Shortly after the depressurization, water was produced in the pipe of the production line. Subsequently, gas and water were produced continuously during hydrate dissociation. Model parameters associated with relative permeability and capillary pressure were intimately related to the gas/water ratio of the fluids produced. These parameters were adjusted to reproduce the history of cumulative gas volume and water volume produced. Every kink in the pressure and every jump of gas production can be reproduced by using time-series pressure and temperature data as the boundary conditions. The simulator precisely reproduced the measured data when the appropriate model parameters were chosen. Pressure and Hydrate Saturation. Figure 5 shows the simulation results of pressure and hydrate saturation at 5 min, 30 min, and 60 min elapsed. The pressure reduction propagated deeply into the core, with the pressure of core reaching the production pressure at 5 min, indicating that the hydrate started dissociating throughout the core. Hydrate dissociation at the zone near the periphery of the core was
4. Discussion Permeability Reduction and Hydrate Occurrence in Pore Space. Through the simulation of the hydrate dissociation, the value of permeability reduction index was estimated as N = 4.4 at SH = 52.0%. The value of N determined in this study is larger than the value derived from a capillary coating model, N = 2, and it is consistent with the recent results reported by Kumar et al.19 A larger value of permeability reduction index means that the permeability rapidly decreases with hydrate saturation. Kumar et al. conducted the permeability measurements at various hydrate saturations in a glass-bead-packed core. They reported a value of N = 3 at a hydrate saturation less than 35%, which was equal to the value derived from the Kozeny’s model by Kumar et al., assuming that the hydrate forms as a coating on the pore wall.19 However, as the hydrate saturation exceeded 35%, the value of N tended to increase. For example, N = 4 and 5 at SH = 42% and 49%, respectively.19 They concluded that the result shows a pore-filling tendency of hydrate formation for hydrate saturation above 35%.19 Our results also show that the value of N is larger than 2 or 3 and close to the values provided by Kumar et al. The value of not 2 or 3 but 4.4 (19) Kumar, A.; Maini, B.; Bishnoi, P. R.; Clarke, M.; Zatsepina, O.; Srinivasan, S. J. Pet. Sci. Eng. 2010, 70, 114–122.
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suggests that the hydrate occurrence in fine-grained sandy sediments also shows the pore-filling tendency. In the Nankai Trough, Uchida et al. reported that pore-space hydrate was recognized mostly filling intergranular pores of sandy sediments.20 And the hydrate occurrences in the Nankai Trough have been characterized as pore filling by Murray et al.21 Our result is consistent with these studies. Previously, the value of N for hydrate reservoirs in nature was poorly understood. The value of N obtained from this study will be a valuable geophysical parameter for hydrate reservoir simulations used to predict gas productivity from fine-grained sandy turbidite sediments in this area. Absolute Permeability of Host Sediments. Although the absolute permeability of host sediments under the initial condition was estimated to be around 100 md by the simulation, the effective water permeability after hydrate dissociation was measured as 1.2 md by the experiment. This permeability was less than the initial effective water permeability of 3.9 md. Several reasons can be given for this large discrepancy. The most probable cause for the permeability reduction is residual gas remained in the pore space. In general, vacuum
resaturation with water is conducted before attempting a water permeability measurement. However, we did not conduct this technique for fear that the unconsolidated host sediment would be disturbed. As a result, failure to saturate the core with water will result in the large discrepancy between measured and simulated absolute permeability. The second possible reason is the migration of fine-grained clay particles caused by the flow of water. The sediment cores at the Eastern Nankai Trough consist of quartz sands mixed with a small amount of clay particles such as kaolin. These fine-grained clay particles could flow with water and block the flow path of the host sediments, reducing the permeability to some extent. The effect of the migration of the finegrained clay particles on the permeability is currently under investigation.22 Dissociation Characteristics and Prospect of Gas Production. The simulation results showed that the pressure reduction is transmitted deep into the core and the hydrate is dissociated throughout the core. Theoretically, if the hydrate-bearing sediments have some permeability and a mobile fluid phase, the pressure reduction is transmitted deep into hydrate-bearing sediments. In that situation, dissociation of the hydrate occurs over a large volume of hydrate-bearing sediments (a spatial dissociation). On the other hand, if the hydrate-bearing sediments have very small permeability, dissociation of the hydrate occurs only at the sharp front between the mobile fluid zone and hydrate-bearing zone.7,19 Our preliminary numerical analysis for the experiment has shown that a hydrate dissociation regime transits from a sharp front dissociation to a spatial dissociation when the initial permeability in the presence of hydrate is over 0.5 md. As previously described, the initial effective permeability of the core is above 0.5 md, which meets the requirement of a spatial dissociation regime. In terms of gas production, a spatial dissociation regime is desirable, because a high gas production rate is expected from a larger dissociation volume when the pressure reduction is propagated deeply into the hydrate-bearing sediments. In addition, our previous study of field-scale simulations indicates that the initial effective permeability of the hydrate reservoir is a crucial factor, and an effective permeability higher than the threshold value is absolutely necessary for successful gas production by depressurization.7 The threshold permeability is estimated to be around 1-10 md for production using a vertical well from hypothetical oceanic reservoirs.7 The initial effective permeability of the core is beyond the lower limit of threshold permeability. Therefore, the permeability condition of the core seems promising for the depressurization process, indicating that it is feasible to employ depressurization as a gas production method for the hydrate in sandy turbidite sediments at the Eastern Nankai Trough. Potential Effects of Core Handling. Subsequent to coring using PTCS, the recovered core samples were stored and transported to the laboratory at liquid N2 temperature to minimize hydrate dissociation. However, the use of liquid N2 for storage and transportation may have had an impact on the core properties, because the inevitable freezing of the pore water may have resulted in fracturing of the hydrate-bearing sediments. Thus, we carefully selected an undisturbed core
(20) Uchida, T.; Lu, H.; Tomaru, H. The MITI Nankai Trough Shipboard Scientists. Resour. Geol. 2004, 54 (1), 35–44. (21) Murray, D. R.; Kleinberg, R. L.; Sinha, B. K.; Fukuhara, M.; Osawa, O.; Endo, T.; Namikawa, T. Petrophysics 2006, 47 (2), 129–137.
(22) Mitsuhori, K.; Sato, T.; Hirabayashi, S.; Brumby, P.; Norimatsu, Y.; Nagao, J.; Jin, Y.; Konno, Y.; Ebinuma, T.; Narita, H. Proceedings of The Twentieth (2010) International Offshore and Polar Engineering Conference, 2010; 1, 161-164.
Figure 5. Pressure and hydrate saturation at 5 min, 30 min, and 60 min subsequent to depressurization. Grid blocks surrounded by a black line represent the hydrate-bearing core.
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sample for the analysis and concluded that the core handling had no significant impact on the structure of the core used in this study, for the following reasons. First, in the chosen core sample, any obvious cracking was not observed by an X-ray CT scan prior to the dissociation experiment. Second, the consolidation of the core during the dissociation experiment was comparable to that of homogeneous artificial cores. In this experiment, triaxial confining pressure was applied to the core by using a syringe pump, and the volume of water injected to the core holder was measured during the dissociation experiment. The volumetric change of the core, which can be estimated from the volume of water injected by the syringe pump, was 1.47%. On the other hand, in our previous experiments using artificial cores that were made of Toyoura standard sand,4 the volumetric change was estimated to be about 1% under similar conditions. These values are in the same range and indicate that the core sample had no obvious cracking. Obvious cracking or void space was observed by an X-ray CT scan in a part of the core samples, implying that the properties in these disturbed cores would be different from those in the undisturbed cores. Currently, novel core analysis tools, such as the Pressure Core Analysis & Transfer System (PCATS) by GEOTEK, are being developed for gas hydrate research. PCATS will provide infrastructure to handle and conduct nondestructive testing of recovered cores under in situ temperature and pressure.23 An analysis under completely in situ conditions is a future work.
tion, a process of permeability change due to hydrate dissociation was investigated. The conclusions of this study are as follows: (1) The initial effective water permeability in the presence of the hydrate was measured as 3-4.8 md at hydrate saturation of 52.0%. The absolute permeability of host sediments under the initial condition was estimated to be around 100 md by the simulation. (2) The permeability reduction index N of Masuda’s model about permeability reduction with hydrate saturation was estimated as N = 4.4. The value of permeability reduction index indicates a pore-filling tendency rather than a coating tendency of the hydrate in the pore space. (3) The permeability condition of the hydrate-bearing sandy core obtained from turbidite sediments at the Eastern Nankai Trough seems promising for achieving depressurization-induced hydrate dissociation. The initial effective permeability of the core met the requirement of a spatial hydrate dissociation regime and was beyond the lower limit of threshold permeability absolutely necessary for successful gas production by depressurization. (4) The simulator developed by us, MH21-HYDRES, precisely reproduces the dissociation behavior such as cumulative gas production, cumulative water production, and pressure change when appropriate model parameters are chosen. An experimentally validated simulator will be a powerful tool for predicting gas productivity of actual hydrate reservoirs.
5. Conclusions Acknowledgment. This study was financially supported by the Research Consortium for Methane Hydrate Resources in Japan (MH21 Research Consortium) to carry out Japan’s Methane Hydrate R&D Program conducted by the METI. We acknowledge our financial support and permission to present this paper. Y.K. thanks Drs. K. Suzuki, M. Kida, and Y. Jin of AIST for the fruitful discussions.
The permeability of hydrate-bearing sediments is a crucial factor for successful gas production from oceanic hydrate reservoirs. To verify the fluid flow ability of hydrate-bearing sediments in oceanic hydrate reservoirs, we analyzed the dissociation behavior of hydrate-bearing sandy cores obtained from turbidite sediments at the Eastern Nankai Trough using a state-of-the-art hydrate reservoir simulator. Through the simulation of dissociation behavior during depressuriza-
Note Added after ASAP Publication. The second author, Hiroyuki Oyama, first name was spelled incorrectly in the version of this paper published November 10, 2010. The correct version published November 12, 2010.
(23) Schultheiss, P. J.; Aumann, J. T.; Humphrey, G. D. Proceedings of Offshore Technology Conference, 2010; No. 20827.
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