Key Factors for Depressurization-Induced Gas Production from

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Energy Fuels 2010, 24, 1736–1744 Published on Web 02/15/2010

: DOI:10.1021/ef901115h

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Key Factors for Depressurization-Induced Gas Production from Oceanic Methane Hydrates Yoshihiro Konno,*,† Yoshihiro Masuda,*,‡ Yosuke Hariguchi,§ Masanori Kurihara, and Hisanao Ouchi

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† Production Technology Team, Methane Hydrate Research Center, National Institute of Advanced Industrial Science and Technology (AIST), 2-17-2-1 Tsukisamu-Higashi, Toyohiraku, Sapporo 062-8517, Japan, ‡Frontier Research Center for Energy and Resources (FRCER), School of Engineering, University of Tokyo, §Department of Systems Innovation, School of Engineering, University of Tokyo, and Japan Oil Engineering Co. Ltd

Received October 1, 2009. Revised Manuscript Received January 22, 2010

Oceanic methane hydrate (MH) deposits have been found at high saturations within reservoir-quality sands in the Eastern Nankai Trough and the Gulf of Mexico. This study investigates the key factors for the success of depressurization-induced gas production from such oceanic MH deposits. A numerical simulator (MH21-HYDRES: MH21 Hydrate Reservoir Simulator) was used to study the performance of gas production from MH deposits. We calculated the hydrate dissociation behavior and gas/water production performance during depressurization for a hypothetical MH well. Simulation runs were conducted under various initial reservoir conditions of MH saturation, temperature, and absolute permeability. A productivity function (PF) was introduced as an indicator of gas productivity, which is a function of gas production rate, water production rate, and discount rate. The simulations showed that recovery factors over 36% and maximum gas production rates over 450 000 Sm3/d were expected for the most suitable conditions of a class 3 deposit (i.e., an isolated MH deposit that is not in contact with any hydrate-free zone of mobile fluids). However, gas productivity was affected by formation temperature and initial effective permeability. The values of PF increased with increasing formation temperature when the initial permeability of the deposit was higher than a threshold value (the threshold permeability); however, it decreased for the deposit below the threshold permeability. The threshold permeability was estimated to be between 1 and 10 mD in the class 3 deposit. These results suggest that key factors for the success of depressurization-induced gas production from oceanic MH are as follows: (1) The initial effective permeability of the MH deposit is higher than the threshold value, and (2) the temperature of the MH deposit is as high as possible.

pressure (FBHP) was reduced approximately from 10 to 4 MPa, and continuous gas production for six days was achieved in that test. That test proved the availability of the depressurization method for gas production from permafrost MH deposits. Meanwhile, oceanic MH accumulations have attracted much attention as a potential gas resource because the amount of methane in oceanic MH is greater than that in permafrost MH. The global estimate of methane in oceanic MH accumulations is in the range 1-5  1015 m3, which is approximately 2-10 times larger than the ultimate recoverable resources of conventional natural gas.3 Currently, MH deposits have been found at high saturations within reservoir-quality sands from oceanic environments such as the Eastern Nankai Trough offshore Japan and the Gulf of Mexico.4,5 At the Eastern Nankai Trough, the MH saturations in sand layers were estimated to be between 57 and 68% using PTCS (pressure temperature core sampler) coring within the high resistivity zone at exploration wells.4 Also, another estimates using logging and chloride concentration analysis showed the MH saturations to be between 20 and 80%.4,6 Moreover, the world’s first offshore gas production

1. Introduction Background. Gas hydrates are crystalline solids composed of gas and water. Methane hydrate (MH) is a natural gas hydrate found in the oceanic and permafrost environments. Vast quantities of methane are trapped within natural MH. Although MH is stable under highpressure and low-temperature conditions, methane gas can be produced from MH by depressurization, thermal stimulation, inhibitor injection, and a combination of these methods.1 Depressurization is a gas recovery method used to dissociate MH by lowering wellbore pressure below the hydrate stability pressure and is considered to be the most promising method because, among the proposed methods, it is using this method that the highest energy profit ratio could be achieved. In the winters of 2007 and 2008, a gas production test by means of the depressurization method was conducted by the Japan Oil, Gas and Metals National Corporation (JOGMEC), Natural Resources Canada (NRCan), and the Aurora Research Institute at a permafrost MH accumulation in the Mackenzie Delta, Northwest Territories, Canada.2 The flowing bottomhole

(3) Milkov, A. V. Earth-Sci. Rev. 2004, 66, 183–197. (4) 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, 2008, #19310. (5) National Energy Technology Laboratory (NETL). NETL SemiAnnual Progress Report No. 41330R16, October 2008 - March 2009; 2009. (6) Colwell, F.; Matsumoto, R.; Reed, D. Chem. Geol. 2004, 205, 391– 404.

*To whom correspondence should be addressed. E-mail: [email protected]. Telephone: þ81-11-857-8949. Fax: þ81-11-857-8943 (Y.K.); E-mail: [email protected]. Telephone: +81-3-58417063. Fax: +81-3-3818-7492 (Y.M.). (1) Sloan, E. D.; Koh, C. A. Chemical Industries Series 119; CRC Press: 2008; pp 583-584. (2) Research Consortium for Methane Hydrate Resources in Japan (MH21 Research Consortium). MH21 Research Consortium Press Release. 2008. r 2010 American Chemical Society

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test using the depressurization method is planned to take place at the Eastern Nankai Trough in 2012. The depressurization method is expected to be a promising method of gas production from not only permafrost MH but also oceanic MH. Classification of MH Deposits. MH deposits are usually divided into three main classes.7 Class 1 deposits have a hydrate layer underlain by a free-gas zone. MH deposits associated with conventional oil fields, such as the fields at the North Slope of Alaska, are examples of class 1 deposits. Class 2 deposits have a hydrate layer underlain by a water zone, and class 3 deposits have an isolated hydrate layer that is not in contact with any hydrate-free zone with mobile fluids. Several deposits in permafrost and oceanic MH accumulations are identified as class 2 or 3. The MH deposits in the Eastern Nankai Trough and the Gulf of Mexico are examples of classes 2 and 3. In addition to these main classes, a class 4 deposit is defined as a dispersed low-saturation MH accumulation that has no mobile-fluid zone. Class 4 deposits, unlike class 1-3 deposits, are not targets for gas production by means of the depressurization method.8 Objectives and Approach. As oceanic MH deposits show high saturation of MH in sandy sediments, evaluation of the efficiency of the depressurization method for such deposits is necessary. Therefore, this study aims at quantifying the gas productivity and investigating the key factors for depressurization-induced gas production from oceanic MH deposits. We conducted numerical simulations using hypothetical MH reservoir models to investigate gas production behavior from oceanic MH deposits. We here discuss the features of gas production from class 1-4 MH deposits under various permeability and temperature conditions. By calculating the productivity functions of class 1-3 deposits, we investigated the key factors for depressurization-induced gas production. We also discuss the commercial viability of naturally occurring MH deposits.

Figure 1. Methane hydrate reservoir model.

Figure 2. Grid structure.

simulators.9,10 Detailed theories on which the code is based are referred to in the published literature.11,12 Reservoir and Well Model. The cylindrical coordinate system was used to calculate the performance of a single vertical well producing from the MH layer (Figure 1). The top boundary of the MH layer was 159-326 m below the seafloor with a water depth of 492-863 m. The thickness of the MH layer was 50 m. Two 50 m thick mud layers were placed above and below the MH layer. In the simulations for class 1 and 2 deposits, a 10 m thick fluid layer was placed under the MH layer. The outer radius of the cylindrical section (drainage radius) was 250 m. The well had a radius of 0.1 m. The cylindrical section of Figure 2 was discretized into 95  158 grids in (r, z) for class 1 and 2 simulations and 95  138 grids for class 3 and 4 simulations. Discretization along the radial direction was nonuniform with grids increasing logarithmically from 0.02 m. The MH layer was uniformly divided along the z-axis into 100 grids. The two mud layers (overburden and underburden) were discretized into 10 grids in the first 5 m and 9 grids in the outer 45 m. An additional 20 grids of the mobile fluid zone were placed for the simulations of class 1 and 2 deposits. Prior to deciding the grid structure, we compared predictions using various grid blocks. Figure 3 compares the gas production histories for class 3 deposit (initial temperature 14 °C, absolute permeability 500 mD; details of initial conditions are included below). The prediction of peak gas rate using 95  40 grids in (r, z), in which

2. Numerical Models Numerical Simulator. Numerical studies were conducted using the MH21 Hydrate Reservoir Simulator (MH21HYDRES), which was developed by the University of Tokyo, Japan Oil Engineering Co., Ltd. and National Institute of Advanced Industrial Science and Technology. This code has the capability 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/ formation and the flow of fluids in sediments, including the heat transfer by conduction and convection. Fluid flows are modeled on the basis of Darcy’s law. Hydrate dissociation/formation and ice formation/melting are modeled as kinetic equations. Energy and mass-balance equations are solved by the NewtonRaphson method. This code has been validated by comparing predictions obtained using this code with experimental data and through a comparative study of several other MH (7) Moridis, G. J.; Kowalsky, M. B.; Pruess, K. SPE Reserv. Eval. Eng. 2007, 10 (5), 458–481. (8) Moridis, G. J.; Sloan, E. D. Energy Convers. Manage. 2007, 48, 1834–1849. (9) Masuda, Y.; Konno, Y.; Kurihara, M.; Ouchi, H.; Kamata, Y.; Ebinuma, T.; Narita, H. Proceedings of the 5th International Conference on Gas Hydrates 2005, 1076–1085. (10) 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, #5727.

(11) Masuda, Y.; Konno, Y.; Iwama, H.; Kawamura, T.; Kurihara, M.; Ouchi, H. Proceedings of Offshore Technology Conference 2008 2008, #19433. (12) Kurihara, M.; Sato, A.; Ouchi, H.; Natrita, H.; Masuda, Y.; Saeki, T.; Fujii, T. SPE Reserv. Eval. Eng. 2009, 12 (3), 477–499.

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Konno et al. Table 1. Calculation Conditions temperature at the middle depth of MH layer (°C) pressure at the middle depth of MH layer (MPa) well bottomhole pressure (MPa) well radius (m) domain radius (m) hydrate layer thickness (m) over/underburden thickness (m) mobile fluid-layer thickness (m) saturation at MH layer

Figure 3. Gas production histories for class 3 deposit using various grid blocks.

saturation at mobile fluids layer saturation at over/underburden porosity thermal conductivity (W/m/K)

each layer of the MH and the over/underburden was divided into 20 grids along the z-axis, was slightly lower than that using 95  138 grids. On the other hand, the prediction using 190  138 grids showed almost the same value as that using 95  138 grids. The discrepancy of ultimate cumulative gas produced was less than 1% among these models. We concluded from these results the model of 95  138 grids is sufficient to conduct accurate simulations. Various initial hydrate and fluid saturations were set according to the class. Class 1 deposits were assumed to have the MH layer bearing gas (hydrate saturation (SH) = 0.6 and gas saturation (Sg) = 0.4). Meanwhile, class 2 and 3 deposits were assumed to have the MH layer bearing water (SH = 0.6, water saturation (Sw)=0.4). The free-gas zone (Sg=0.9 and Sw=0.1) was placed below the MH layer for class 1 deposits, and the aqueous zone (Sw = 1.0) was placed below the MH layer for class 2 deposits. No fluid zone was placed for class 3 and 4 deposits. The MH layer for class 4 deposits was assumed to have low hydrate saturation (SH = 0.1 and Sw = 0.9). For all simulations, the mud layers of overburden and underburden were fully saturated by water. The initial hydrate saturation for class 1-3 deposits (SH = 0.6) was determined on the basis of the values of coring data at the Eastern Nankai Trough.4 Initial and Boundary Conditions. In each simulation run, the initial temperature at the middle depth of the MH layer (TR) was given as input data listed in Table 1 (9-14 °C). Initial temperatures and pressures of the grids were determined by the following steps. First, the boundary temperatures at the top and bottom of the MH layer were calculated by assuming a geothermal gradient of 0.03 °C/m. Temperature corresponding to depth was assigned to each grid. Next, the pressure of the grids aligned on the bottom boundary of the MH layer was determined by considering the hydrostatic pressure to satisfy the MH equilibrium pressure condition. Pressure corresponding to depth was assigned to each grid. A constant temperature of 3.47 °C was set at the seafloor. The depth below the seafloor of the top boundary of the MH layer was calculated using the same geothermal gradient. Table 1 lists the temperature and pressure set at the middle depth of MH layer. Thermal and Fluid Flow Properties. The effective thermal conductivity of sediment containing MH and fluids is expressed in the following model: ð1Þ λ ¼ ð1 - φÞλR þ φðSw λw þ Sg λg þ SH λH Þ

specific heat (J/kg/K) sand density (kg/m3) absolute permeability in MH and mobile fluids layer (10-3 μm2 = mD) permeability reduction index, N krw0, krg0 Siw, Sig Nw Ng Pe (Pa) nc hydrate number

9, 10, 11, 12, 13, 14 6.76, 7.56, 8.48, 9.53, 10.74, 12.13 4.00 in each class, 3.00 in class 3 0.1 250 50 in each class 50 in each class 10 in Classes 1 and 2 SH: 0.6, Sg: 0.4 in class 1 SH: 0.6, Sw: 0.4 in classes 2 and 3 SH: 0.1, Sw: 0.9 in class 4 Sw: 0.1, Sg: 0.9 in class 1 Sw: 1.0 in class 2 Sw: 1.0 in each class 0.4 λR: 4.0, λg: 0.0335, λw: 0.5564, λH: 0.49 sand: 800, MH: 2010 2650 10, 20, 30, 40, 50, 60, 70, 80, 90, 100, 300, 500 2 each 1 each 0.1 3 2 5000 0.250 6.0

respectively. φ is porosity and Sl is the saturation of the l phase. Subscripts g, H, R, and w refer to gas, MH, rock, and water phases, respectively. The values of thermal conductivity of each phase and porosity are shown in Table 1. The value of effective thermal conductivity at SH = 0.6, Sw = 0.4, and φ = 0.4 is 2.60 W/m/K, which is consistent with the values of naturally occurring MH sediments.13 The permeability of sediment containing MH is lower than the absolute permeability of original sediment because of the presence of MH in the pore space. The permeability of sediment containing MH is expressed as the following model proposed by Masuda et al.:14 kD ¼ kD0 ð1 - SH ÞN

ð2Þ

where kD and kD0 are the permeability of the MH layer and the original absolute permeability, respectively. N is the permeability reduction index; in this study, N = 2, which was derived theoretically. The relative permeability curves of water and gas are15 krw ¼ krw 0 ðSe ÞNw

ð3Þ

krg ¼ krg 0 ð1 - Se ÞNg

ð4Þ

where Se is the normalized water saturation expressed as Swm - Siw ð5Þ Se ¼ 1 -Sig - Siw krl and krl0 are relative permeability and end-point relative permeability to the l phase, respectively. Nl is the relative (13) Henninges, J.; Heunges, E.; Buirkhardt, H. Proceedings of the 5th International Conference on Gas Hydrates 2005, #3034. (14) Masuda, Y.; Naganawa, S.; Ando, S.; Sato, K. Proceedings of SPE Asia Pacific Oil & Gas Conference and Exhibition 1997, #38291. (15) Hirasaki, G. J. SPE J. 1975, 15 (1), 39–49.

where λ and λl are the effective thermal conductivity of sediment and thermal conductivity of the l phase (W/m/K), 1738

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permeability index to the l phase. Sil is the irreducible saturation of the l phase. To adjust this model for sediment containing MH, Swm is defined as the water saturation in the effective porosity: Sw ð6Þ Swm ¼ 1 - SH The capillary pressure curve is given by the Brooks-Corey model:16 Pc0 ¼ Pe Se -nc ð7Þ where Pc0 and Pe are capillary pressure of the original sediment and capillary entry pressure (Pa), respectively. nc is the pore-size distribution index. The presence of MH narrows the fluid path in pore space, leading to an increase in the capillary pressure. Equation 8 is introduced to express the influence of MH on capillary pressure: 1 ð8Þ PcH ¼ pffiffiffiffiffiffiffiffiffiffiffiffiffiffiPc0 1 - SH

Figure 4. Cumulative gas produced for different MH deposit classes.

where PcH is capillary pressure of sediment containing MH (in Pa). The values of corresponding parameters in fluid-flow models are listed in Table 1. These parameters were determined by history matching simulations on laboratory experiments of artificial MH core depressurization.17 Simulation Runs. The performance of a single vertical well producing from the MH layer was simulated for each class deposit. Simulation runs were conducted under various initial reservoir conditions of temperature and absolute permeability. During production, a constant FBHP of 4 MPa was assumed. The pressure of 4 MPa is equivalent to the FBHP achieved by the production test in the AuroraJOGMEC-NRCan Mallik Gas Hydrate Production Research Program 2008.2 To discuss the effects of FBHP, simulations using a lower FBHP (3 MPa) were also conducted for class 3 deposits. The FBHPs exceed the quadruple-point pressure of MH. When the well is depressurized at a pressure near the quadruple point of MH, ice is formed in the MH layer near the wellbore. The ice formation may decrease the permeability by blocking the fluid path and would reduce productivity. To eliminate this possibility, the FBHPs of 3 and 4 MPa were chosen. The production interval was set in the MH layer for class 2, 3, and 4 deposits and in the MH layer plus the fluid zone for class 1 deposits. To evaluate long-term production potential, the simulation period was set to 10 years.

Figure 5. Gas production rate for different MH deposit classes.

The total gas production volume from the class 1 deposit was about 240 million Sm3 larger than that of class 2 and 3 deposits. The free-gas zone under the MH layer and the gasbearing MH layer caused the high productivity of the class 1 deposit. In the class 1 deposit, the initial amount of free gas was about 343 million Sm3, and the amount of gas remaining after a 10 year production period was about 110 million Sm3. Thus, at least 233 million Sm3 of methane gas was produced from the free-gas zone. The production behaviors of class 2 and 3 deposits, which had no free-gas zone, were similar. Depressurization propagation and MH dissociation occur equally in these deposits. The existence of the aqueous layer in the class 2 deposit had little influence on gas productivity. The MH layer of these deposits had the same initial amount of methane gas in place (about 401 million Sm3). After a 10 year production period, the amount of gas remaining as a solid-hydrate state in the MH layer was about 235 million Sm3. About 41.4% of MH was dissociated due to depressurization. The low-saturation MH layer of the class 4 deposit had a small initial amount of methane gas in place (about 67 million Sm3). All hydrates in the MH layer were dissociated during the production period; however, the volume of cumulative gas produced was 38 million Sm3 and the remaining amount (29 million Sm3) was unrecovered. The primary reason for low gas productivity of the class 4 deposit was a shortage of in-place gas volume. Although the class 1 deposit had the largest gas productivity due to free gas, the class 2 and 3 deposits produced almost the same amount of gas from MH, which was not as low as we expected. A more detailed analysis evaluating the potential of these deposits is given in a later section. Characteristics of Gas Production Performance. Figure 6 shows a typical performance of gas production from the class

3. Results and Discussion Comparison of Production Performance among Classes. Figures 4 and 5 compare the gas production histories from class 1-4 deposits of TR =14 °C, kD0 =500 mD, and FBHP = 4 MPa. The class 1 deposit produced the largest amount of gas, followed by the class 2 and class 3 deposits. The class 4 deposit produced the smallest amount of gas. The gas production rate of the class 1 deposit exceeded the range of the y-axis after 50 days and reached >106 Sm3/D at the peak. The class 2 and 3 deposits showed similar gas production behaviors. The gas production of the class 4 deposit finished at 250 days. (16) Brooks, R. H.; Corey, A. T. Hydrology Paper No.3; Colorado State University: 1964. (17) Konno, Y. Doctoral thesis; the University of Tokyo: 2008. (in Japanese)

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Figure 9. Temperature distribution at peak: day 162 (14 °C, 500 mD, class 3).

Figure 6. Typical gas production curve.

Figure 7. Pressure distribution at day 43 (14 °C, 500 mD, class 3).

Figure 10. Temperature distribution at day 520 (14 °C, 500 mD, class 3).

Figure 8. Pressure distribution at peak: day 162 (14 °C, 500 mD, class 3).

Figure 11. Permeability influence on gas production (14 °C, class 3).

3 hydrate deposit (TR = 14 °C, kD0 = 500 mD, FBHP = 4 MPa). Depressurization-induced gas production from hydrate deposits was characterized by three stages: the early stage when the pressure reduction continued to the outer boundary of MH layer (the reservoir boundary), the middle stage when hydrate dissociated using the remaining sensible heat of the sediments, and the late stage when hydrate dissociated using the heat supply from the surrounding sediments. In the early stage, the gas production rate continued to increase with time and reached a peak. Figures 7 and 8 show the pressure distribution in the deposit after 43 days of production and at the peak production time (day 162), respectively. The peak production appears at a time when the pressure reduction was propagated to the reservoir boundary. As the MH layer had enough sensible heat to dissociate hydrate during this stage, hydrate dissociation was controlled by the speed of pressure reduction prevailing through the reservoir. In the middle stage, as the sensible heat of the MH layer was gradually spent by hydrate dissociation, the formation temperature decreased with time. Figures 9 and 10 show the

formation-temperature distribution at the peak production time of day 162 and day 520, respectively. At day 520, the MH layer had cooled down to the hydrate equilibrium temperature at 4 MPa. Because all the sensible heat in the reservoir was spent in previous stages, gas production stabilized at a very low rate in the later stage. In this stage, the heat conduction from the mud layers of overburden and underburden was the only driving force to dissociate hydrates. Influence of Permeability on Gas Production. Figure 11 compares the gas production histories from class 3 deposits calculated with different absolute permeabilities of the MH layer (TR=14 °C; kD0=500, 300, and 100 mD; FBHP= 4 MPa). In every case, the peak production rate was similar to that found in the typical gas production history of class 3 deposits, although the peak time and its peak rate were different. The peak rates were about 450 000, 300 000, and 100 000 Sm3/d for deposits with the kD0 values of 500, 300, and 100 mD, respectively. When the MH layer had a higher permeability, the peak production appeared earlier because reduced pressure reached faster to the reservoir boundary to dissociate hydrate. 1740

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Konno et al. Table 2. Parameters Used in Productivity Function production period (year) gas price (yen/m3) discount rate pump efficiency gas engine efficiency methane calorific value (MJ/m3)

10 30 0.10 0.5 0.7 39.7

Figure 12. Temperature influence on gas production (500 mD, class 3).

Moreover, the sensible heat of the MH layer was spent over a shorter period of time because the peak gas rate was greater than that for systems with lower permeability. As the permeability of the MH layer decreased, the propagation of pressure reduction slowed. This required a longer period for the peak time to appear. The peak production rate decreased because of slower hydrate dissociation before the pressure reduction reached the reservoir boundary. As discussed above, the permeability of the MH layer was a key factor in controlling the peak time and its peak production rate. Figure 11 also compares the histories of the gas recovery factor for class 3 deposits calculated with various permeabilities of the MH layer. The ultimate recovery factor had approximately the same value of 36% even though the production histories were very different. This is because the MH layers had the same amount of sensible heat at an initial temperature of 14 °C. When the MH layer had a lower permeability, large amounts of sensible heat were still remaining at the end of the early stage (the peak time) and available for hydrate dissociation during the middle stage. This led to the increase of the recovery factor during the middle stage and the same ultimate recovery factor. Influence of Temperature on Gas Production. Figure 12 compares the histories of gas production from class 3 deposits calculated with various formation temperatures (TR=14, 12, 10 °C; kD0 =500 mD; FBHP=4 MPa). The time necessary to reach the peak production was about the same but the peak production rate declined with decreasing temperature (450 000, 300 000, and 150 000 Sm3/d for TR = 14, 12, and 10 °C, respectively). Because the MH layer permeability was the same for these runs, pressure reduced in the same way. This is the reason for the appearance of the same peak production time. However, its peak rates were different. When the MH layer had a high permeability, the rate of gas production was limited by the heat supply available to dissociate hydrate. As the amount of sensible heat available for hydrate dissociation increased with increasing formation temperature, the peak production rate increased as well. Figure 12 also compares the histories of the gas recovery factor for class 3 deposits calculated with various formation temperatures. The final gas recovery factors declined with a decrease in formation temperature (32, 25, and 17% for TR =14, 12, and 10 °C, respectively). This is because of the same reason mentioned above;the amount of sensible heat available for hydrate dissociation increased with the increase in formation temperature. The temperature of the MH layer was a key factor affecting the peak production rate and recovery factor, although it only slightly influenced the time necessary to reach peak production.

Figure 13. Productivity function contour map of class 1 (FBHP: 4 MPa).

Productivity Evaluation by Productivity Function. Productivity function (PF) was introduced as an indicator of gas productivity, which is a function of annual gas production rate (qg, m3), annual water production rate (qw, m3), gas price (CG, yen/m3), discount rate (i), and production period (tP, year). MH deposits with higher values of PF were interpreted to have better potentials as an energy resource. PF is defined as tP X ðqg - qgc Þ  CG ð9Þ PF ¼ ð1þiÞn n ¼0 where qgc ¼

ΔP  qw ηP  ηE  HCH4

ð10Þ

qgc is the annual fuel gas consumption necessary for pumping operation (m3). ΔP is the pressure gain (MPa). ηE, ηP, and HCH4 are gas engine efficiency, pump efficiency, and methane calorific value (MJ/m3), respectively. We assumed that the well was equipped with an electric submersible pump (ESP) to lift water and decrease the bottomhole pressure for depressurization. ΔP is the pressure gained by the ESP, which is powered by a gas engine. A part of the methane gas produced from the well was consumed as fuel for the gas engine. The annual fluid production rate data (qg and qw) were taken from the simulation outputs. By considering qgc, MH deposits producing a high gas/water ratio show high PF values, that is, high productivity. PF is the net present value of produced gas and is a good indicator for the evaluation of the productivity of MH deposits. The use of discount rate gives an advantage to earlier gas production (earlier peak production time). For each class of MH deposit, a total of 72 PF values were calculated under the conditions of six initial formation temperatures and 12 absolute permeabilities. Table 2 shows the common parameters in the calculations. Figures 13-15 show the contour maps of PF values for class 1-3 MH deposits with an FBHP of 4 MPa, which were created from plots of the calculated PF values over the two variables (initial effective permeability and initial temperature). The x-axis is an initial effective permeability scale and the y-axis is an initial temperature scale. The color on the map shows the level of PF values. Yellow and blue colors correspond to high 1741

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Figure 17. Methane hydrate saturation distribution after 10 years (14 °C, 10 mD, class 3).

Figure 14. Productivity function contour map of class 2 (FBHP: 4 MPa).

Figure 18. Pressure distribution after 10 years (14 °C, 500 mD, class 3). Figure 15. Productivity function contour map of class 3 (FBHP: 4 MPa).

Figure 19. Methane hydrate saturation distribution after 10 years (14 °C, 500 mD, class 3).

Figure 16. Pressure distribution after 10 years (14 °C, 10 mD, class 3).

Figures 18 and 19 show the distributions of pressure and MH saturation after 10 years for a class 3 deposit of high permeability (TR=14 °C, kD0=500 mD, kD=80 mD). These figures indicate that the pressure reduction continued to the reservoir boundary and MH dissociated over the entire MH layer. In such a case, depressurization was effective in dissociating hydrates. As Figures 13-15 showed that the contour lines of PF were parallel to the x-axis in the high-permeability region, the initial effective permeability was not a factor in determining the gas productivity for the MH deposits that had higher permeability than the threshold permeability. The values of PF increased with increasing temperature and were basically proportional to the initial temperature when the initial permeability was higher than the threshold permeability. The formation temperature was a crucial factor in determining the gas productivity in the high-permeability MH deposits. Figure 20 shows the contour map of PF values for Class 3 MH deposits with an FBHP of 3 MPa. The PF value increased with decreasing FBHP. This is because the amount of sensible heat available for hydrate dissociation increased with decreasing FBHP. Thus, lower FBHPs had the same

and low PF values, respectively. From these figures, we observed that the interval between contour lines was much narrower and the PF value decreased sharply between 1 and 10 mD in class 2 and 3 deposits. This indicates the existence of threshold permeability. The PF value became remarkably low when the initial effective permeability of the MH layer was lower than a certain value (the threshold permeability) in class 2 and 3 deposits. Meanwhile, the threshold permeability was not clearly identified for class 1 deposits. This is because the gas production from the free-gas zone was dominant in this class. Figures 16 and 17 show the distributions of pressure and MH saturation after 10 years for a class 3 deposit of low permeability (TR=14 °C, kD0=10 mD, kD=1.6 mD). These figures indicate that the pressure reduction did not continue to the reservoir boundary and MH dissociated only in the region near the well. As seen in this example, the dissociation zone was limited to the well neighborhood when the MH deposit had a lower permeability than the threshold value. The gas productivity of such a deposit was very low. The gas production stage stagnated at the early stage and did not advance to the middle stage where the peak production rate appeared. 1742

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commercial production. Meanwhile, the PF value decreases gradually near the threshold permeability when the discount rate increases. Accordingly, initial effective permeability sufficient to exceed the threshold value (more than tens of mD) is another desirable factor for commercial production. The financial parameters used in this study were preliminary data. For example, the discount rate of approximately 10% was the value used for some preliminary economic evaluations of hydrate and unconventional gas resources.19,20 In order to use the PF value for the actual economic evaluation, the financial parameters should be adjusted for the demand-supply analysis of energy fuels and the risk of an individual project. In addition, commercial viability highly depends on not only the PF values but also the project costs, including tax, facility cost, and operating cost. Therefore, economic evaluation will be an issue in the future; however, it seems appropriate to remark that some oceanic deposits located in the Eastern Nankai Trough and the Gulf of Mexico, which have enough initial effective permeability to exceed the threshold value (more than tens of mD) and high initial temperature, could have potential commercial viability. Potential Effects of Varying Hydrate Saturation. Although hydrate saturation of 60% was assumed on the basis of the coring data in the Eastern Nankai Trough, hydrate saturation can have potential effects on the gas productivity for several reasons. First of all, hydrate saturation determines the amount of methane gas in place. As mentioned in the comparison of production performance among classes, class 4 deposits (SH = 0.1) showed low productivity due to a shortage of in-place gas volume. In general, high hydrate saturation is a desirable factor in an energy resource. On the other hand, the ultimate recovery factor for depressurizationinduced gas production is determined by the sensible heat of the MH layer. In this study, the ultimate recovery factor for class 3 deposits of 14 °C was 36% and about 41.4% of MH was dissociated when an FBHP of 4 MPa was assumed. This recovery factor is equivalent to 24.8% at hydrate saturation. These results indicate that hydrate saturation has only to exceed a certain value as long as the depressurization method is used. This is because the excess hydrate could not be produced at a high rate owing to a shortage of the sensible heat of the MH layer. Second, hydrate saturation determines the initial effective permeability. Conversely, in systems with the same initial effective permeability, the absolute permeability would be inversely related to hydrate saturation. Thus, the absolute permeability of the layer with high hydrate saturation would be higher than that with low hydrate saturation. However, this study indicates that it is not the absolute permeability but the initial effective permeability that is a crucial factor for successful gas production. It would appear that hydrate saturation is not necessarily an important factor in the same initial effective permeability systems.

Figure 20. Productivity function contour map of class 3 (FBHP: 3 MPa).

effects as those of higher formation temperatures. On the other hand, the PF value decreased sharply between 1 and 10 mD, which indicates that the range of threshold permeability is independent of FBHP. As discussed above, threshold permeability was a crucial factor in determining the gas productivity of class 2 and 3 MH deposits. The depressurization method was not effective when the MH layer had an initial effective permeability below the threshold value. In such a case, the in situ sensible heat had little role in dissociating hydrates even when the formation temperature was high. The simulation results suggest that promising gas production from class 2 and 3 deposits definitely requires higher permeability than the threshold value. It is not practical to produce gas from MH deposits with smaller permeability than the threshold value even if they exist under a high-temperature environment. Commercial Viability of Gas Production from Naturally Occurring Oceanic MH Deposits. In the evaluation of productivity by PF, it was found that higher effective permeability than the threshold value is essential for successful depressurization-induced gas production from class 2 and 3 deposits. Although not much is known about the initial effective permeability for MH layers of naturally occurring oceanic deposits, the initial effective permeability to water is estimated at approximately 0.001-100 mD for the MHconcentrated layers of class 3 deposits at exploration wells in the Eastern Nankai Trough.12 It indicates that some oceanic deposits have higher effective permeability than the threshold value. Meanwhile, the gas productivity is basically proportional to the initial temperature as long as the MH layer has a higher permeability than the threshold value. The initial temperature is related to the geothermal gradient and the MH deposit depth. Thus, the deep MH deposits are desirable targets for gas production. Some class 3 deposits in the Eastern Nankai Trough are relatively deep and the initial temperatures assumed at exploration wells are relatively high (12.67 °C at 1270 m, 13.85 °C at 1314 m).12 The class 2 deposit in the Tigershark area located in the Alaminos Canyon Block 818 of the Gulf of Mexico is a deeper and warmer system (21.00 °C at 2750 m).18 These deep and warm oceanic deposits would be promising targets for depressurization-induced gas production. The PF value depends on not only reservoir properties but also financial parameters such as the gas price and the discount rate. The PF value is proportional to the gas price when the initial effective permeability is higher than the threshold value. Thus, it would appear that a higher gas price is necessary for

4. Conclusions To investigate the key factors for depressurization-induced gas production from oceanic MH deposits, numerical simulations were conducted for hypothetical MH reservoir models. The conclusions of this study are as follows: (19) Walsh, M.; Hancock, S.; Wilson, S.; Patil, S.; Moridis, G.; Boswell, R.; Collett, T.; Koh, C.; Sloan, E. D. Energy Economics 2009, 31, 815–823. (20) Luo, D.; Dai, Y. Energy Policy 2009, 37, 3883–3889.

(18) Moridis, G; Reagan, M. Proceedings of Offshore Technology Conference 2007 2007, #18866.

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(1) The initial effective permeability of the MH layer is a crucial factor for successful gas production from oceanic MH deposits. A higher effective permeability than the threshold value between 1 and 10 mD is absolutely necessary for depressurization. (2) A higher temperature of the MH deposits is the second key factor. Gas productivity is basically proportional to the initial temperature as long as the MH layer has a higher permeability than the threshold value. (3) Some class 2 and 3 deposits in the Eastern Nankai Trough and the Gulf of Mexico have initial effective permeability exceeding the threshold value and high initial temperature. These MH deposits are suitable for depressurization-induced gas production and could have commercial viability.

(4) Although high hydrate saturation is a desirable factor in an energy resource, the excess hydrate could not be produced at a high rate owing to a shortage of the sensible heat of the MH layer. Hydrate saturation determines the initial effective permeability; however, it would appear that hydrate saturation is not necessarily an important factor in systems with the same initial effective permeability. Acknowledgment. This work was financially supported by the Research Consortium for Methane Hydrate Resources in Japan (MH21 Research Consortium) on the Japan’s Methane Hydrate R&D Program by the Ministry of Economy, Trade and Industry (METI). The authors gratefully acknowledge them for the financial support and permission to present this paper. Y. K. would like to thank Drs. J. Nagao, H. Oyama, Y. Jin, and M. Kida of AIST for valuable discussions.

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