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JUOGR 63 No of Pages 11, Model 5G September 2015 Journal of Unconventional Oil and Gas Resources xxx (2015) xxx–xxx Contents lists available at ScienceDirect Journal of Unconventional Oil and Gas Resources journal homepage: www.elsevier.com/locate/juogr 10 11 12 13 14 17 18 19 20 21 22 23 24 25 26 27 28 29 Numerical simulation of gas production from hydrate-bearing sediments in the Shenhu area by depressurising: The effect of burden permeability Jiaxin Sun a, Fulong Ning a,⇑, Shi Li b, Ke Zhang b, Tianle Liu a, Ling Zhang a, Guosheng Jiang a, Nengyou Wu c,d a Faculty of Engineering, China University of Geosciences, Wuhan 430074, China State Key Laboratory of Enhanced Oil Recovery, Research Institute of Petroleum Exploration and Development, Beijing 100083, China Guangzhou Institute of Energy Conversion, Chinese Academy of Sciences, Guangzhou 510640, China d Qingdao Institute of Marine Geology, Ministry of Land and Resources, China b c a r t i c l e i n f o Article history: Received 17 September 2014 Revised 19 July 2015 Accepted August 2015 Available online xxxx Keywords: Gas hydrate Depressurisation Overburden Underburden Permeability Numerical simulation a b s t r a c t Natural gas hydrates have been investigated as a potential resource for commercially producing gas since the 1990s Based on the latest available data for the Shenhu area of the South China Sea (SH7), a practical two-dimensional model has been constructed to investigate the gas production potential and the distributions of different physical properties in alternating formations by selecting a proper perforated interval favouring borehole stability and gas production The effects of overburden and underburden permeability on gas production are intensively discussed The simulation results indicate that the initial hydrate dissociation mainly occurs among the upper gas hydrate bearing-sediments (GHBS) with a high permeability but that in the later period, it is mainly distributed among the bottom low permeability GHBS In addition, an obvious hydrate re-formation can be observed in the middle GHBS, and the dilution effect in the bottom low permeability GHBS is stronger than that in the upper space with high permeability A comparative study showed that the GHBS in the Shenhu area with only one permeable burden (overburden or underburden) is not the most promising target for depressurisation Ó 2015 Published by Elsevier Ltd 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 Introduction 48 Gas hydrates are ice-like crystalline clathrates that are formed when small gas molecules (mainly hydrocarbon gases) come into contact with water (host molecules) under specific lowtemperature and high-pressure conditions They are widely distributed in the permafrost on land and in the ridges of active and passive continental margins in the seafloor (Sloan, 1998, 2003) Because of the significant associations with resources (Milkov, 2004), environment and climate change (Hesselbo et al., 2000; Maslin et al., 2003), submarine landslides (Maslin et al., 2004) and the evolution of geological history (Wang et al., 2010), gas hydrates have become a hot topic for current energy and earth science research The exhaustion of traditional oil and gas resources, combined with a continuous increase in consumption, means that unconventional energy sources, such as natural gas hydrates, are considered the most promising alternative energy Klauda and Sandler (2005) stated that 74,000 Gt of methane is 49 50 51 52 53 54 55 56 57 58 59 60 61 62 63 ⇑ Corresponding author trapped in gas hydrates within marine zones, which is three orders of magnitude greater than the current worldwide conventional natural gas reserves Consequently, the exploration and exploitation of marine gas hydrates has become an emphasis of current and future research Gas production from hydrate reservoirs at present mainly includes traditional depressurisation, thermal stimulation and inhibitor injection (Moridis et al., 2004; Sloan, 1998) as well as the new CO2 replacement (White et al., 2011) Depressurisation involves lowering the pressure below the hydrate phase equilibrium pressure at the initial temperature to cause hydrate dissociation, and thermal stimulation involves heating the reservoirs above the hydrate dissociation temperature to induce dissociation at the prevailing pressure Injecting inhibitors (such as salts and alcohols) shifts the hydration pressure and temperature equilibrium and results in hydrate dissociation The production mechanism of CO2 replacement is the exchange of CO2 in situ with methane molecules within a methane hydrate structure, releasing the methane Previous studies (Moridis and Reagan, 2007; Zhang et al., 2010) have shown that the pure thermal dissociation method and inhibitor method have relatively high costs and limited effectiveness E-mail address: nflzx@cug.edu.cn (F Ning) http://dx.doi.org/10.1016/j.juogr.2015.08.003 2213-3976/Ó 2015 Published by Elsevier Ltd Please cite this article in press as: Sun, J., et al Numerical simulation of gas production from hydrate-bearing sediments in the Shenhu area by depressurising: The effect of burden permeability J Unconventional Oil Gas Resourc (2015), http://dx.doi.org/10.1016/j.juogr.2015.08.003 64 65 66 67 68 69 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 JUOGR 63 No of Pages 11, Model 5G September 2015 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 100 101 102 103 104 105 106 107 108 109 110 111 112 113 114 115 116 117 118 119 120 121 122 123 124 125 126 127 128 129 130 131 132 133 134 135 136 137 138 139 140 141 142 143 144 145 146 147 148 149 J Sun et al / Journal of Unconventional Oil and Gas Resources xxx (2015) xxx–xxx Moreover, injecting inhibitors is likely to cause environmental pollution In addition, based on the field trials on the north slope of Alaska (the well named Ignik Sikumi #1) (David et al., 2013), the efficiency of CO2/CH4 exchange is relatively low, and the CO2 hydrate formed around the well can reduce the effective permeability, thereby decreasing gas production Therefore, depressurisation is still the most effective method for long-term gas production from hydrate reservoirs (Moridis et al., 2009a) Because natural gas hydrates occur primarily in polar regions, which are usually associated with onshore and offshore permafrost, and in sediments of outer continental and insular margins (Kvenvolden, 1993), conducting field trials carries a high cost Therefore, numerical simulation is usually employed to investigate gas production from hydrate reservoirs at this stage and to evaluate the production potential (Li et al., 2010a,b; Moridis et al., 2009a,b, 2011; Su et al., 2010; Zhang et al., 2010) Moridis et al (2009a, 2011) performed a numerical simulation of gas production from Ulleung Basin accumulations with impermeable confining boundaries using conventional technology in vertical wells and slao investigated the gas production potential from hydrate deposits in Mount Elbert by adopting horizontal wells and vertical wells In addition, based on historical data and property adjustment to match the numerical simulation, two-dimensional numerical models replicating the reservoirs of Mount Elbert were constructed by Kurihara et al (2011) They forecasted the long-term production performances of vertical wells in these reservoirs using the methods of depressurisation, a combination of depressurisation and wellbore heating, and hot water huff and puff According to the characteristics of gas hydrate bearing-sediments (GHBS) in the Shenhu area of the South China Sea, Zhang et al (2010) established a typical model of hydrate deposits to evaluate the production potential and efficiency by means of depressurisation and thermal stimulation using horizontal wells Based on the measurements of drilling and logging from sites SH2, SH3 and SH7, Li et al (2010a, 2010b, 2011) investigated gas production from the Shenhu hydrates by means of depressurisation and a combination of depressurisation and thermal stimulation using different well designs A single vertical well was simulated by Su et al (2010, 2012) to assess the potential of using the method of depressurisation and alternately producing fluid and injecting hot water (huff and puff) The above research has properly evaluated the exploitation potential of typical GHBS in the ocean and the permafrost; however, the hydrate deposits are taken as a single homogenous reservoir in their simulations, and the effects of the hydrate formation lithology distribution and saturation differences on practical gas production are not fully considered Myshakin et al (2012) indicated that interbedded gas hydrate accumulations might be preferable targets for gas production in comparison with massive deposits Therefore, the effects of sediment lithology and saturation differences should be considered Additionally, the hydrates that occurring in both marine deposits and permafrost are not homogeneous That is to say, an accurate prediction of the gas production potential should consider various petrophysical factors Here, we use available data from the in situ coring of site SH7 and hydrate saturation estimated from pore water freshening to construct a realistic two-dimensional model for hydrate reservoirs by selecting a proper perforated interval favouring borehole stability and gas production We then use this model to investigate the production potential and the distributions of different physical properties in alternating hydrate formations using the TOUGH + HYDRATE (Moridis et al., 2008) numerical simulation software that was developed by the Lawrence Berkeley National Laboratory The effects of the overburden and underburden permeabilities on gas production are also investigated in detail Simulation model 150 Background 151 The target zone is located in the southeast of the Shenhu Underwater Sandy Bench area in the central part of the north slope of the South China Sea, between the Xisha Trough and the Dongsha Archipelago (Fig 1) The north slope of the South China Sea is a passive continental margin in Cenozoic and rich of oil and gas bearing basins The first Chinese expedition to drill gas hydrates, GMGS-1, was undertaken in this area between April and June 2007 by Fugro and Geotek on behalf of the Guangzhou Marine Geological Survey (GMGS) and the Ministry of Land and Resources of the PR China A total of eight sites were drilled and well-logged during this project, with cores recovered at five of these sites, including three sites with recovered gas hydrate samples (SH2, SH3, and SH7) (Wu et al., 2007; Zhang et al., 2007) A core sample analysis indicates the presence of gas hydrates at depths of 153–229 m beneath the seafloor, with thicknesses of 10–43 m and porosities of 33–48%, in areas with water depths of 1108–1245 m (Nakai et al., 2007) These sI methane hydrates (i e., the structures of the hydrate molecules are type I) with 26–48% saturation are disseminated throughout the sediment, and the gas produced from these hydrates was originally derived from microorganisms and consists of 96.1–99.82% methane In situ measurements indicate a bottom-water temperature of 3.3–3.7 °C, with a geothermal gradient of 43–67.7 °C kmÀ1, corresponding to a sea-bottom heat flow of 74.0–78.0 mW mÀ2 (average of 76.2 mW mÀ2) 152 Model construction 177 The simulations presented here are based on the GHBS at site SH7, where the seafloor is at a water depth of 1108 m The GHBS in this area is located $155–177 m below the seafloor (mbsf) and has a pore water salinity (mass fraction) of 3.05% An axisymmetric cylinder with a radius of 200 m and a thickness of 82 m (i.e., the thickness of the GHBS is 22 m, and the thickness of both the overburden and underburden layers is 30 m) is adopted for the model domain Previous studies (Moridis and Reagan, 2007; Li et al., 178 Fig Location of site SH7 in the South China Sea (Wu et al., 2009) Please cite this article in press as: Sun, J., et al Numerical simulation of gas production from hydrate-bearing sediments in the Shenhu area by depressurising: The effect of burden permeability J Unconventional Oil Gas Resourc (2015), http://dx.doi.org/10.1016/j.juogr.2015.08.003 153 154 155 156 157 158 159 160 161 162 163 164 165 166 167 168 169 170 171 172 173 174 175 176 179 180 181 182 183 184 185 JUOGR 63 No of Pages 11, Model 5G September 2015 J Sun et al / Journal of Unconventional Oil and Gas Resources xxx (2015) xxx–xxx Fig Schematic of the simulated Shenhu area hydrate deposits The deep yellow area with a screen (155–159.4 mbsf) is the perforated interval (For interpretation of the references to color in this figure legend, the reader is referred to the web version of this article.) radius of 0.1 m is located in the centre of the cylinder (Fig 2) The top and bottom boundaries are designed as constant temperature and pressure boundaries The outer side of the model (rmax = 200 m) is treated as a no-flow boundary The drill core obtained from the field indicates that the lithology varies with depth and that this area contains clay, sand clay and silty clay (Fig 3a) Combining the hydrate saturation, which is estimated based on the pore water freshening variation, with depth (Fig 3b), the coexisting methane hydrates and water within the in situ hydrate sediment can be subdivided into three layers based on the lithology distribution from top to bottom, namely GHBS1-4.4 m, GHBS2-9.5 m, and GHBS3-8.1 m, which have mean hydrate saturation values of 0.38, 0.25, and 0.15, respectively The wet thermal conductivity ks of the GHBS is taken to be 3.1 W mÀ1 °CÀ1 Because of the difference in lithology, the dry thermal conductivity kHs1, kHs2 and kHs3 of the corresponding GHBS (GHBS1, GHBS2 and GHBS3) are taken to be 0.7, 0.8 and 1.0 W mÀ1 °CÀ1, respectively The density q of the GHBS is assumed to be 2600 kg mÀ3, and GHBS1, GHBS2, and GHBS3 are assigned porosities of 41%, 38%, and 45%, respectively, with corresponding intrinsic permeabilities (K1, K2 and K3) of 7.5 Â 10À14 (=75 mD), 2.0 Â 10À14 (=20 mD) and 1.0 Â 10À14 m2 (=10 mD) (Su et al., 2010; Li et al., 2011) Both the overburden and underburden are assigned the same properties as the adjacent hydrate deposits by considering the same formation lithology except hydrate saturation The main modelling parameters and physical properties are given in Table The simulation uses a relative permeability model as follows (Moridis et al., 2008): n SA À SirA krA ¼ ; À SirA nG SG À SirG ; krG ¼ À SirA (a) formation lithology (b) hydrate saturation Fig Formation lithology and hydrate saturation vs depth at site SH7 (Nakai et al., 2007) 186 187 188 2011) have indicated that the 30-m-thick overburden and underburden layers may be sufficient to simulate the boundary effects of heat exchange and pressure propagation The borehole with a 189 190 191 192 193 194 195 196 197 198 199 200 201 202 203 204 205 206 207 208 209 210 211 212 213 214 215 216 217 218 ð1Þ krH ¼ 0; 220 where SirA is 0.30, SirG is 0.05, and n and nG are 3.572 This modelling also uses the following capillary pressure model (Van Genuchten, 1980): 221 Pcap h i1Àk À1=k ¼ ÀPs ðSÃ Þ À1 ; SÃ ¼ ðSA À S0irA Þ ; ðSmxA —S0irA Þ 222 223 224 ð2Þ À Pmax Pcap 0; 226 where k is 0.45, S0irA is 0.29, SmxA is 1.0, and Pmax is 105 Pa The composite thermal conductivity model used in the modelling is as follows (Moridis et al., 2005): Table Main hydrate deposit properties and conditions at Site SH7 Parameter Value Parameter Value GHBS1 thickness GHBS2 thickness GHBS3 thickness Initial bottom temperature of GHBS3 (Ts) Initial bottom pressure of GHBS3 (Ps) Water salinity (Xi) Hydrate saturation in GHBS1 (SH1) Pore water saturation in GHBS1 (SA1) Hydrate saturation in GHBS2 (SH2) Pore water saturation in GHBS2 (SA2) Hydrate saturation in GHBS3 (SH3) Pore water saturation in GHBS3 (SA3) Porosity of GHBS1 (/1) 4.4 m 9.5 m 8.1 m 13.79 °C 13.15 MPa 3.05% 0.38 0.62 0.25 0.75 0.15 0.85 0.41 Porosity of GHBS2 (/2) Porosity of GHBS3 (/3) Compression coefficient a Grain density (q) Geothermal gradient Grain specific heat (Cs) Wet thermal conductivity (ks) Dry thermal conductivity (kHs1) Dry thermal conductivity (kHs2) Dry thermal conductivity (kHs3) Intrinsic permeability (K1) Intrinsic permeability (K2) Intrinsic permeability (K3) 0.38 0.45 1.00 Â 10À8 PaÀ1 2600 kg/m3 43.653 K/km 1000 J kgÀ1 °CÀ1 3.1 W mÀ1 °CÀ1 0.7 W mÀ1 °CÀ1 0.8 W mÀ1 °CÀ1 1.0 W mÀ1 °CÀ1 75 Â 10À15 m2 (=75 mD) 20 Â 10À15 m2 (=20 mD) 10 Â 10À15 m2 (=10 mD) Please cite this article in press as: Sun, J., et al Numerical simulation of gas production from hydrate-bearing sediments in the Shenhu area by depressurising: The effect of burden permeability J Unconventional Oil Gas Resourc (2015), http://dx.doi.org/10.1016/j.juogr.2015.08.003 227 228 229 230 JUOGR 63 No of Pages 11, Model 5G September 2015 232 J Sun et al / Journal of Unconventional Oil and Gas Resources xxx (2015) xxx–xxx pffiffiffiffiffi pffiffiffiffiffi kc ¼ kHs þ ð SA þ SH Þðks À kHs Þ þ uSI kI : ð3Þ depth, temperature, and salinity and can be assumed to be 1035 kg mÀ3 (Li et al., 2010) The water depth at site SH7 is 1108 m, then the pressure distribution of the entire system, including the pressure Ps (at Z = 177 m), can be determined The corresponding phase equilibrium temperature (approximately 13.80 °C) at the bottom of the hydrate reservoirs can de deduced by the hydrate pressure–temperature (P–T) equilibrium curve and then compared with in situ temperature measurements (Fig and 1416 °C) To ensure the stability of the gas hydrates, a slight adjustment of temperature at the bottom of GHBS3 is carried out (Table and 1379 °C) This adjustment, combined with the known geothermal gradient of the GHBS listed in Table 1, means that the initial temperatures at the top and bottom boundaries of the model can be determined In the practical process of initialisation, the temperature and pressure distributions of the entire model domain are calculated quickly using the self-balancing function of the software when obtaining the temperatures and pressures at the top and bottom boundaries 268 Well design and production method 286 287 where PPw is the hydrostatic pore water pressure in MPa, Patm is the standard atmospheric pressure of 0.101325 MPa, h is the water depth in m, z is the depth of the sediment from the seafloor in m, g is the acceleration due to gravity in m sÀ2, and qsw is the average sea water density in kg mÀ3; this last term is a function of water Although previous studies (Moridis, 2008; Moridis et al., 2011) suggest that using horizontal wells can greatly increase the gas production for Class and reservoirs, it is still low in absolute terms, and the use of a horizontal well substantially increases the cost of installation and operation Furthermore, the mechanical strength of the hydrate formation is relatively low and will continue to decrease with hydrate dissociation As a result, the instability of the borehole can lead to the subsidence and even the collapse of the production platform and will affect the exploitation under the condition of high pressure drawdown (Rutqvist et al., 2008, 2009) Therefore, gas production from hydrate reservoirs by traditional vertical wells is still the preferred alternative However, the borehole stability in drilling and producing must still be emphasised when the vertical well design is employed (Ning, 2012; Yamamoto et al., 2014) According to the sediment lithology (Fig 3a), the optimal perforated interval is set in sandy clay with a relatively high mechanical strength and good permeability, which is conducive to maintaining the borehole stability and the dissociated gas flowing into the production well, as shown in Fig To Fig Schematic of study area and meshing structure The rhombic-shaped grid in the borehole is the perforated interval (155–159.4 mbsf) Fig Temperature measured at site SH7 (Nakai et al., 2007) There is no ice present in the South China Sea, and, as such, SI is 233 234 235 Domain discretisation 236 Fig shows the schematic of meshes employed in simulating the gas production from the GHBS The model domain is discretised into 19,688 (107 Â 184) elements in a cylindrical coordinate system (r, Z) with 19,473 active elements, and the rest are assigned as boundary cells located on the top and bottom of the model The scale of discretisation varies from fine discretisation (DZ = 0.1–0.2 m) along the Z axis in areas close to the hydrate deposits and where the hydrate saturation changes to coarser (DZ = 0.5–3 m) in other domains far from reservoirs, which is adequate for accurate predictions (Moridis et al., 2007a) Considering that most of the heat and mass transport, and phase change occurs around the borehole, we increase the mesh grid density along the r direction, which yields the grids that include 77,892 (19,473 Â 4) coupled equations that are solved simultaneously when the equilibrium model of hydrate formation and dissociation is used in the simulation 237 238 239 240 241 242 243 244 245 246 247 248 249 250 251 252 Initial conditions 253 Because the natural gas hydrates in the Shenhu area of the South China Sea are distributed in poorly consolidated sediments near the seafloor, pore water in the sediments could be considered to exchange with the sea-bottom water, which means that the sediment pore water pressure is hydrostatic (Hyndman et al., 1992) Then, the following empirical formula can be used to calculate the initial hydrostatic pore water pressure (Song et al., 2002): 254 255 256 257 258 259 260 262 263 264 265 266 267 Ppw ¼ Patm þ qsw gðh þ zÞ Â 10 ; À6 ð4Þ Please cite this article in press as: Sun, J., et al Numerical simulation of gas production from hydrate-bearing sediments in the Shenhu area by depressurising: The effect of burden permeability J Unconventional Oil Gas Resourc (2015), http://dx.doi.org/10.1016/j.juogr.2015.08.003 269 270 271 272 273 274 275 276 277 278 279 280 281 282 283 284 285 288 289 290 291 292 293 294 295 296 297 298 299 300 301 302 303 304 305 JUOGR 63 No of Pages 11, Model 5G September 2015 J Sun et al / Journal of Unconventional Oil and Gas Resources xxx (2015) xxx–xxx 1000 800 QT QG 600 800 QR QT , QG and QR (m /d) 400 200 600 400 100 200 300 400 500 200 0 Fig Production well design for hydrate reservoirs in the Shenhu area 306 307 308 309 310 311 312 313 314 315 316 317 318 319 320 321 322 323 324 325 avoid the theoretically correct but computationally intensive solution of the Navier–Stokes equation, the borehole flow is assumed to be Darcian flow through a pseudo-medium describing the interior of the well (Moridis et al., 2007b) In the vertical well, the pseudo-medium has a porosity / = 1.0, a very high axial permeability kZ = 5.0 Â 10À9 m2 along the Z direction, a radial permeability kr = 1.0 Â 10À11 m2, and a capillary pressure Pc = As mentioned above, depressurisation is still the most promising method for hydrate exploitation Hence, a constant bottomhole pressure (3 MPa) is adopted for production in the simulation The pressure at the perforated interval is reduced by nearly 9.92 MPa, which is approximately 76% of the initial pressure (12.92 MPa) The constant bottomhole pressure production is applicable to most hydrate formations with different permeabilities and is uniquely suited to allow the gas production rate to increase to match the increasing permeability (Li et al., 2011) In addition, this method is beneficial to controlling the borehole pressure (for example, the well pressure is higher than the pressure at the quadruple point) to eliminate the possibility of secondary hydrate, and even ice formation due to the temperature decrease 326 Results and analysis 327 Gas and water production 328 Fig shows the evolution of the volumetric rates (a) QG of methane in the gas phase produced at the well, (b) QT of total methane produced, and (c) QR of methane released from hydrate reservoirs in the whole domain As Fig shows, both the total methane production rate (QT) and hydrate dissociation rate (QR) decrease sharply, and the former is less than the latter at the beginning of the production (approximately t = 0–500 days) However, both of them show a slight reduction in the later period (after 500 days) and tend to be consistent and stable According to the free methane rate (QG) variation with time, an obvious methane flow in the gas phase can be observed during the initial 50 days, but its production rate decreases rapidly until no free methane flows into the production well This phenomenon occurs mainly because the pressure difference between the production well and the formation is relatively large and because the pressure has not propagated completely at the beginning of depressurisation; this results in a higher pressure gradient between the production well and the formation Therefore, the hydrate dissociation rate is fast but is still far lower than the commercial production rate (3.0 Â 105 ST m3/d) (Li et al., 2011) Almost all of the gas released from the hydrate reservoirs at the beginning directly flows into the production well instead of the permeable overburden because 329 330 331 332 333 334 335 336 337 338 339 340 341 342 343 344 345 346 347 348 349 1000 2000 3000 4000 5000 6000 7000 8000 t (d) Fig Volumetric rate of the total gas production (QT) and methane production in the gas phase (QG) in the well and released from hydrate dissociation (QR) using the constant bottomhole pressure method the initial hydrate dissociation occurs mainly around the perforated interval and because the drive force caused by the differential pressure primarily influences this location Therefore, the total production rate (QT) is relatively high, and a notable amount of free gas is observed in the early production period The reasons why the hydrate dissociation rate (QR) is higher than the total methane production rate (QT) in the initial stage are likely that (1) hydrate dissociation is endothermic, which results in the increase of methane dissolving into the water; (2) hydrate deposits are not confined, which means that some methane released is dissolved into the free-methane water coming from the overburden and underburden However, the water due to the lag flow cannot run into the well immediately; and (3) some residual free methane released from the hydrate remains in the formation Because both the overburden and underburden are permeable in the model, the pressure gradient between the formation and the production well decreases with persistent hydrate dissociation and rapid pressure diffusion In addition, the hydrate dissociation itself is an endothermic process These two reasons cause the hydrate dissociation rate to decrease to a large extent, and the rate then presents a notable decline Certainly, the methane recovery rate (QT) in the well also decreases With the gradual decrease in the pressure gradient, the dissociation rate of the reservoir also reaches a lower level Some of the gas released dissolves in the formation water, and some dissociated gas far away from the production well may escape and flow into the permeable overburden because of buoyancy (the density of methane is lower than water) in the latter period This can explain why there is no free gas flowing into the production well after 50 days in the simulation In addition, this fact seems to indicate no continuous free gas can be produced at all in an open system, regardless of how good the quality of the hydrate formation is However, in the later period of production, the total trapped methane comes from dissolved methane instead of free gas and that dissolved in the connate formation water, which leads to the total methane production rate (QT) being slightly higher than the dissociation rate of hydrate formation (QR) in the later stage Figs and show the total gas produced (VP) at the well, the cumulative gas released (VD), the cumulative free gas (VR) remaining in the reservoirs, the evolution of the water production rate (QW) and the gas-to-water ratio (RGW) under the corresponding conditions Fig indicates that the total gas produced in the well and the cumulative gas released continuously increase over time A similar phenomenon that the cumulative gas released is higher Please cite this article in press as: Sun, J., et al Numerical simulation of gas production from hydrate-bearing sediments in the Shenhu area by depressurising: The effect of burden permeability J Unconventional Oil Gas Resourc (2015), http://dx.doi.org/10.1016/j.juogr.2015.08.003 350 351 352 353 354 355 356 357 358 359 360 361 362 363 364 365 366 367 368 369 370 371 372 373 374 375 376 377 378 379 380 381 382 383 384 385 386 387 388 389 390 391 392 393 JUOGR 63 No of Pages 11, Model 5G September 2015 J Sun et al / Journal of Unconventional Oil and Gas Resources xxx (2015) xxx–xxx VP , VD and VR 1.4x10 1.2x10 1.0x10 8.0x10 6.0x10 4.0x10 2.0x10 VP VD VR 0.0 1000 2000 3000 4000 5000 6000 7000 8000 t (d) Fig Volumes of total gas production (VP) at the well, methane released from hydrate dissociation (VD), and cumulative free gas (VR) remaining in the reservoirs using the constant bottomhole pressure method Fig 10 Evolution of spatial distribution of SH 4.5x10 5 4.0x10 QW RGW 2.5x10 QW (m /d) 3.0x10 RGW (ST m of CH4 / m of H2O) 3.5x10 2.0x10 1.5x10 1.0x10 5.0x10 0.0 0 1000 2000 3000 4000 5000 6000 7000 t (d) Fig Evolution of volumetric rate of water production (QW) and gas-to-water ratio (RGW) Fig 11 Evolution of spatial distribution of SG 410 than the total gas produced in the early stage (approximately t = 0– 1800 days) can be observed, whereas the trend reverses in the later stages However, the total gas trapped over 20 years is only approximately 1.3 Â 106 ST m3, which indicates very low gas recovery The free gas remaining in the reservoirs increases before starting to drop, but compared with the total methane released, the amount of gas trapped is also lower This fact again shows that the trapped gas comes primarily from the dissolved methane in the water in the later period of production The water production rate (QW) is shown in Fig 9; it increases quickly at the beginning until it reaches a relatively high rate (4.0 Â 105 m3/d) and then stays constant The gas-to-water ratio (RGW = VP/VW) is considered a relative criterion for evaluating the efficiency of production, which is mainly used to economically assess the production potential According to Fig 9, RGW drops sharply over time and is close to 0.5 ST m3 of CH4/m3 of H2O In conclusion, using this method is still not economically feasibile 411 Spatial distributions of SH and SG 412 The dynamic evolution of hydrate and gas during production can be determined by comparing the hydrate and gas spatial distributions at different times Figs 10 and 11 show the evolution of the SH and SG distributions, respectively, 155–177 m below the seafloor at different times (1 year, years, 10 years and 15 years) 394 395 396 397 398 399 400 401 402 403 404 405 406 407 408 409 413 414 415 416 According to Fig 10, the initial hydrate dissociation occurs preferentially around the perforated interval and then gradually moves forward in the GHBS Comparing the simulation results at different moments, we can find that the movement rate of the dissociation front in the upper high permeable GHBS (GHBS1) is relatively rapid in the early period (1 year) Subsequently, its movement rate slows down Then, the hydrate decomposition in the large-scale zone is mainly located in the bottom low permeability formation, especially the interface between the GHBS (GHBS3) and the underburden (177 m), resulting in the emergence of a lower dissociation interface Hydrate dissociation in the bottom low permeability formation is continuous, and the movement rate of the dissociation front is significantly faster than the upper high permeability formation with sustainable exploitation, which causes the mergence of the lower dissociation interface and the cylindrical interface around the perforated interval When the interfaces are completely melded, the methane produced at the well is inferred mainly from the bottom low permeability GHBS (GHBS2 and GHBS3) because the hydrate decomposition zone in the lower part with low permeability is significantly larger than in the upper part with high permeability in the later period (10 and 15 years) No obvious ‘‘secondary hydrate” is formed in the dissociation front before the mergence of the two dissociation interfaces, although it can be observed in the dissociation front of the middle GHBS2, Please cite this article in press as: Sun, J., et al Numerical simulation of gas production from hydrate-bearing sediments in the Shenhu area by depressurising: The effect of burden permeability J Unconventional Oil Gas Resourc (2015), http://dx.doi.org/10.1016/j.juogr.2015.08.003 417 418 419 420 421 422 423 424 425 426 427 428 429 430 431 432 433 434 435 436 437 438 439 440 JUOGR 63 No of Pages 11, Model 5G September 2015 J Sun et al / Journal of Unconventional Oil and Gas Resources xxx (2015) xxx–xxx 441 442 443 444 445 446 447 448 449 450 451 452 453 454 455 456 457 458 459 460 461 462 463 464 465 466 467 468 469 470 471 472 473 474 475 476 477 478 479 480 481 482 483 484 485 486 487 488 489 490 491 492 493 494 495 496 497 498 499 500 501 502 503 504 505 506 especially in the interface between the upper GHBS1 and the middle GHBS2 in the later production stages The phenomenon described above occurs because the upper hydrate formation with high permeability is closer to the perforated interval Consequently, the initial hydrate dissociation occurs primarily in the upper part However, because the permeability of the upper hydrate formation is better than that of the others and because the overburden is permeable, the fluid can move rapidly to balance the variation of the formation pressure at the later stage As a result, the pressure gradient between the production well and the upper hydrate formation decreases dramatically Furthermore, because of the high hydrate saturation in the upper formation, the effective permeability decreases to some extent and goes against the fluid flow in GHBS1, which causes the late decomposition zone to decrease significantly (because the pressure does not vary visibly if the fluid cannot flow rapidly) Because there is an obvious heat and mass transfer between the hydrate formation (GHBS3) and the underburden, i.e., the fluid with a higher temperature in the underburden will run into the hydrate formation, a second dissociation interface will arise The large-scale hydrate dissociation that can be observed in the bottom low permeability formation occurs mainly for the following reasons: (a) the pressure transmission is relatively slow because of the low permeability and the pressure in the bottom formation is originally higher than that at the top; thus, the pressure gradient between the formation and the production well is higher and causes significant hydrate dissociation; and (b) hydrate dissociation is endothermic, and the fluid with a high temperature below the hydrate formation is sufficient to provide the heat required for decomposition Because the hydrates in the bottom formation decompose rapidly, the corresponding free gas generation is also obvious In addition, hydrate dissociation can lead to the improvement of the formation effective permeability such that a gas flow channel is formed in the dissociation front of the hydrate Meanwhile, most of the heat carried in the fluid (the overburden and underburden) is consumed by the upper (GHBS1) and the lower (GHBS3) hydrate formation; thus, there is little heat obtained by the middle hydrate formation (GHBS2), adding absorption of heat in dissociation, which leads to a relatively low temperature in the front of GHBS2 When the gas released underneath flows through the region, an evident ‘‘secondary hydrate” can be formed because of the suitable pressure and temperature Furthermore, because the hydrate saturation in the upper formation is higher, the effective permeability is significantly low The migration gas accumulates here due to buoyancy and results in a local pressure increase, which contributes to form the ‘‘secondary hydrate” Fig 11 shows that gas saturation in the formation is relatively low, with the highest saturation reaching only approximately 0.1, which is similar to previous results (Li et al., 2011) In the early stage of exploitation, the free gas with a high saturation is mainly distributed in the vicinity of the production well, but the free gas around the well drops significantly, thereby reducing the gas saturation with the production process It can be observed that the gas in the dissociation front of the bottom low permeability hydrate formation continuously decreases in the later period This occurs because the hydrate dissociation is faster in the early stage and mainly gathers near the production well Because both the overburden and underburden are permeable, the pressure diffusion is quick, and the effect of depressurisation thus decreases significantly in the later stage Therefore, the amount of gas released in both dissociation fronts drops accordingly On the one hand, the decomposition zone in the bottom hydrate layer (GHBS3) is wider than that in the other two layers (GHBS1 and GHBS2) (Fig 10) However, the GHBS1 has relatively high hydrate saturation, even for the secondary hydrate formation at the top of the lower dissociation front This can greatly reduce the effective permeability, and prevent gas migration from moving to the perforated interval, resulting in free gas accumulation in the lower dissociation front On the other hand, hydrates have completely dissociated around the borehole (approximately 10 m), as shown in Fig 10, which can provide flowable channels for fluid (because the effective permeability of the formation increases after hydrate dissociation) Both the free gas and water from GHBS3 flow into the production well along these channels due to the driving force caused by the differential pressure Therefore, the free gas mainly accumulates in the lower dissociation front in GHBS2 under the influence of both the density difference and differential pressure When flowing into the perforated interval, the free gas that is accumulated in the lower dissociation front dissolves in the flowing water because of low saturation However, there is no barrier for the upper gas released, so it can migrate into the overburden and directly dissolve in the water because of buoyancy Therefore, free gas can be clearly observed in the dissociation front of the bottom formation, but not in the upper space 507 Spatial distribution of T 525 Fig 12 shows the evolution of the spatial temperature distribution over time for the simulated 20 years, which also indirectly reflects the decomposition of the hydrate formation Based on Fig 12, the temperature around the dissociation front decreases significantly because cooling occurs as the hydrate dissociation and production proceed in the early stage of the simulation An inversion of the geothermal gradient as a result of dissociation-induced cooling in the GHBS can be observed within 365 days, which is mainly the consequence of the rapid endothermic decomposition of the hydrate As production proceeds, the dissociation front is always accompanied by a low temperature However, the temperature ‘‘subsidence” is obvious in the upper dissociation front, but not at the bottom This is mainly attributed to the fluid in the underburden having a higher temperature, which can relieve the effect of the endothermic hydrate dissociation on the temperature distribution in the bottom hydrate layer when it gradually flows into the GHBS, as opposed to the fluid with a lower temperature in the upper layer This also explains why hydrate dissociation zone in the bottom is wider than that in the upper part In addition, these phenomena only appear near the production well is because the hydrates around the well have completely decomposed This significantly improves the effective permeability, and the fluid within the overburden and 526 Fig 12 Evolution of spatial distribution of T Please cite this article in press as: Sun, J., et al Numerical simulation of gas production from hydrate-bearing sediments in the Shenhu area by depressurising: The effect of burden permeability J Unconventional Oil Gas Resourc (2015), http://dx.doi.org/10.1016/j.juogr.2015.08.003 508 509 510 511 512 513 514 515 516 517 518 519 520 521 522 523 524 527 528 529 530 531 532 533 534 535 536 537 538 539 540 541 542 543 544 545 546 547 548 JUOGR 63 No of Pages 11, Model 5G September 2015 J Sun et al / Journal of Unconventional Oil and Gas Resources xxx (2015) xxx–xxx 554 Fig 13 shows the distribution of the salt concentration over time in the GHBS The dilution effect on the salinity in the dissociation front is obvious (Fig 13) because fresh water is released from hydrate dissociation and reduces the water salinity in situ Unlike the cases with impermeable boundaries, the variation of salinity is not significant because of the permeable overburden and underburden (Moridis et al., 2009a) This finding is consistent with the spatial distributions of the other physical properties The results shown in Fig 13 can verify that the bottom hydrate formation with low permeability decomposes more rapidly than the upper based on the spatial distribution of the salinity This may also be related to the formation permeability because salt water is produced continuously from the formation and because the bottom hydrate formation with low permeability will prevent water flow from other regions to significantly affect the salinity distribution The low salinity distribution is not obvious because it is opposite the upper hydrate formation 555 556 557 558 559 560 561 562 563 564 565 566 567 568 569 570 Conditions Case (GHBSP) Case (GHBSLP) Case (GHBSUP) Case (GHBSIP) Permeable overburden Permeable underburden Yes No Yes No Yes Yes No No The distribution of the hydrates in in situ reservoirs is actually very complicated, and both permeable and impermeable burdens may occur A previous field trial in the Nankai Trough (Yamamoto et al., 2014) indicated that a hydrate deposit with one permeable underburden is still the most promising target Therefore, four different cases are investigated in this study to evaluate the production potential, as shown in Table For the convenience of comparison, the absolute permeability of all permeable burdens is set to 10 mD, and the other physical properties of the formation remain unchanged The simulation results are shown in the following figures over 4000 days Fig 14 shows that for the Shenhu area in Case 4, the hydrate dissociation rate is the highest and it increases rapidly until it reaches its maximum in the first 400 days Then, it shows a slight decrease and slowly returns back to the former maximum in the later period When the hydrate formation only has an impermeable overburden (Case 2), the decomposition rate is far lower than that 3200 4000 3200 4000 10 10 10 10 10 -1 10 10 GHBSP GHBSUP GHBSLP GHBSIP 572 2400 10 10 QT (m /d) Effect of permeability in overburden and underburden 1600 10 571 800 Spatial distribution of Xi 551 Table Four different cases are investigated in the simulations QR (m /d) 553 550 552 underburden can flow fluently Most fluids of different sources and temperatures, including the original free water in the formation and the gas and water released from hydrate dissociation, converge toward the well, which causes the confluence of the isotherm 549 QG (m /d) 573 574 575 576 577 578 579 580 581 582 583 584 585 586 587 588 10 10 800 1600 2400 t (d) Fig 14 Volumetric rates of total gas production (QT) and methane production in the gas phase (QG) from the well and that released from hydrate dissociation (QR) under conditions of different permeable burdens Fig 15 Evolution of spatial distribution of SH at t = 1825 days Fig 13 Evolution of spatial distribution of Xi in Case 4, but it is significantly higher than the other two cases (i.e., Cases and 3) This can also be verified from the hydrate dissociation zones at t = 1825 days (Fig 15) In addition, the dissociation rate of the hydrate formation in Case is slightly higher than that with both permeable burdens (Case 1) at the beginning, but they tend to gradually become identical In short, for the Shenhu area if there is only one permeable burden, the dissociation rate, which Please cite this article in press as: Sun, J., et al Numerical simulation of gas production from hydrate-bearing sediments in the Shenhu area by depressurising: The effect of burden permeability J Unconventional Oil Gas Resourc (2015), http://dx.doi.org/10.1016/j.juogr.2015.08.003 589 590 591 592 593 594 595 JUOGR 63 No of Pages 11, Model 5G September 2015 J Sun et al / Journal of Unconventional Oil and Gas Resources xxx (2015) xxx–xxx 602 603 604 605 606 607 608 609 610 611 612 613 614 615 616 617 618 619 620 621 622 623 624 625 626 627 628 629 630 631 632 633 634 635 636 637 638 639 2000 3000 4000 VRE (m ) 10 10 10 10 601 VD (m ) 600 1000 10 10 10 10 10 599 VT (m ) 598 is still far lower than the commercial production rate, cannot be significantly increased This also verifies the previous research on the significance of impermeable burdens (Moridis et al., 2009b) The pressure can only be transferred in the GHBS when both burdens are impermeable Therefore, hydrate dissociation occurs in a large area (Figs 15 and 16), which causes the hydrate decomposition rate to increase The slight decline observed in the later period occurs because the pressure in the formation reduced accordingly when using the depressurisation method and because hydrate decomposition is an endothermic process, which results in the decrease of the formation temperature When the reservoir pressure is approximately equal to the equilibrium pressure at the corresponding temperature, the hydrate dissociation rate is significantly reduced With the later continuous heat transfer between the formations, the decomposition rate increases again and trends toward stability Presumably, the dissociation rate will gradually decrease at the end of production because little hydrate can decompose during the continuous depressurisation Thus, the production in Case is better than in the other two conditions (i.e., Cases and 3) because the pressure can only diffuse downward and the released gas cannot escape (Fig 16) That is the rising gas is trapped by the impermeable overburden and eventually flows into the well as a result of the pressure driving force In addition, both the fluid pressure and temperature in the underburden are higher than those of the overburden, which can accelerate the hydrate decomposition, thereby increasing the hydrate dissociation rate In contrast, the pressure cannot diffuse through the bottom impermeable formation in Case Thus, it will transfer radially along the GHBS, thereby advancing the hydrate dissociation For Case 1, on the one hand, the fluid temperature is relatively high in the underburden, which is conducive to heat conduction; on the other hand, the convective heat transfer is significant, which also accelerates hydrate dissociation From Fig 14, there is no difference between Cases and in promoting the dissociation rate of hydrate Because only a slight difference can be observed initially, the dissociation rates of the hydrate and the cumulative volumes of the dissociated hydrate tend to be the same (Figs 14 and 17) Therefore, both the cumulative volume of methane produced in the well and the amount of hydrate dissociation in Case are much higher than in the other three cases (Figs 15 and 17) The production curve also presents a slight increase in Case at the beginning because of the ‘‘barrier effect” of the overburden Once the upper and lower dissociation fronts merge together, the free gas released and fresh water can flow into the 10 10 10 GHBSP GHBSUP GHBSLP GHBSIP 10 800 1600 2400 3200 4000 t (d) Fig 17 Volumes of total gas production (VP) at the well, methane released from hydrate dissociation (VD) and cumulative free gas (VR) remaining in the reservoirs under conditions of different permeable burdens production well fluently (because hydrate dissociation will increase the effective formation permeability) This is why the production rate curve of methane, including free gas, initially increases and then starts to decrease (Fig 14) Meanwhile, the corresponding water production rate curve presents an obvious tendency to increase, which can also be observed in Case (Fig 18); this is similar to previous research results (Su et al., 2010) Based on the foregoing analysis, the hydrate formation in Case decomposes quickly and the dissociated gas cannot escape due to the ‘‘barrier effect” Therefore, more free gas flows into the production well than in the other situations, and it shows an increasing trend In comparison with the other three cases, we find that the free gas rate in Case is significantly lower than that in Case (this is mainly due to the barrier effect) but is slightly higher than that with only a permeable overburden (Case 3) In the later period, there is no free gas flowing into the production well (Fig 14) In addition, the total methane production rate shows almost the same rule mentioned above under the condition of both permeable 100 3.5x10 5 2.5x10 10 RGW (ST m of CH4 / m of H2O) 3.0x10 2.0x10 597 QW (m /d) 596 1.5x10 QW RGW 5.0x10 0.0 800 1600 2400 3200 GHBSP GHBSUP GHBSLP GHBSIP 1.0x10 0.1 4000 t (d) Fig 16 Evolution of spatial distribution of SG at t = 1825 days Fig 18 Evolution of the volumetric rate of water production (QW) and gas-to-water ratio (RGW) under conditions of different permeable burdens Please cite this article in press as: Sun, J., et al Numerical simulation of gas production from hydrate-bearing sediments in the Shenhu area by depressurising: The effect of burden permeability J Unconventional Oil Gas Resourc (2015), http://dx.doi.org/10.1016/j.juogr.2015.08.003 640 641 642 643 644 645 646 647 648 649 650 651 652 653 654 655 656 657 JUOGR 63 No of Pages 11, Model 5G September 2015 10 J Sun et al / Journal of Unconventional Oil and Gas Resources xxx (2015) xxx–xxx 692 burdens (Case 1) and is slightly lower than that of the formation in Case (Fig 14) The reason may be that the fluid temperature is relatively higher in the underburden, which is not conducive to free methane gas dissolution when flowing into the GHBS Furthermore, most free gas dissociated at the bottom will flow into the production well along the dissociation front instead of escaping (Fig 16) (the hydrate formation effective permeability has significantly improved after dissociation) However, most of the free gas will escape because of the long distance between the dissociation front and the production well with the increase of the hydrate dissociation area in Case Judging from the remaining free gas in the whole formation, the amount is still the largest in Case (Fig 16) The amount of free gas remaining in Case is larger than that in Case 2, followed by Case 1, where both the overburden and underburden are permeable (Figs 16 and 17) This can explain why more free gas is produced in the well in Case than in Case (because most of the free gas in Case remains in the hydrate layers) A relatively rapid dissociation can also be observed in Case (Fig 14), which is higher than that of the others (i.e., Cases and 3) With the combination of the water withdrawal and gas-to-water ratio over time, as shown in Fig 18, we find that a gas hydrate formation with only one permeable burden is conducive to reducing the yield of water but that the potential is still much larger than that of a formation without permeable burdens According to Fig 18, the water withdrawal rate only increases initially in Case before declining continuously to a lower value, whereas the gas production rate gradually increases This is why the gas-to-water ratio rapidly decreases at first and then gradually increases to far exceed 10 ST m3 of CH4/m3 of H2O However, the case in which the underburden is permeable is superior to that of the permeable overburden, but they are both much lower than the hydrate formation without permeable burdens When an impermeable burden exists on top of the hydrate formation, RGW can be improved to a certain extent, whereas it cannot be improved in the case of a permeable overburden 693 Conclusions 694 This study used drilling and pore water freshening data from site SH7 in the Shenhu area of the South China Sea to construct a two-dimensional model that are more similar to reality than other models (Li et al., 2010a, 2010b, 2011; Su et al., 2010, 2012; Zhang et al., 2010) The production potential and the physical property distributions in alternating hydrate formations during extraction are analysed by numerical simulation The effects of burden permeability on gas production are also investigated in detail and yield the following results: 658 659 660 661 662 663 664 665 666 667 668 669 670 671 672 673 674 675 676 677 678 679 680 681 682 683 684 685 686 687 688 689 690 691 695 696 697 698 699 700 701 702 703 704 705 706 707 708 709 710 711 712 713 714 715 716 717 718 719 720 (1) Under the condition of constant depressurisation, the total methane production rate is slightly lower than the gas release rate at first, but the situation reverses later as they both trending toward stability The free gas flowing into the production well is only evident at the beginning of production In other words, no continuous free gas can be produced at all in an open system, regardless of how good the quality of the hydrate formation is Because of the lack of impermeable burdens, the production rate is very low as a great amount of free water flows into the production well and is accompanied by gas escape Therefore, the investigated method is still not an effective way to exploit gas from hydrate reservoirs in the Shenhu area (2) The different physical property distributions in alternating hydrate formations at different times shows that the initial hydrate dissociation preferentially occurs around the perforated interval and then gradually spreads outward in the GHBS According to the simulation results, the upper high permeable GHBS (GHBS1) dissociates more rapidly in the early period However, later on, the trend reverses, and an obvious ‘‘secondary hydrate” can be observed in the dissociation front of the middle GHBS (GHBS2) In the early stage of exploitation, the free gas is mainly distributed in the vicinity of the production well, but in the later period, it can only be observed in the dissociation front of the bottom low permeability hydrate formation with decreasing saturation The corresponding temperature decreases and geothermal gradient reversion can occur in the dissociation front In addition, there is a significant dilution effect in the dissociation front, and that of the bottom hydrate formation with low permeability is obviously stronger than the upper high permeability hydrate formation (3) By comparing the effect of the different burden permeabilities on gas production, we find that when there is only one permeable burden (overburden or underburden) in the hydrate formation in the Shenhu area, the production rate still cannot be increased significantly by using a constant bottom hole pressure However, a hydrate reservoir with a permeable underburden is superior to that with only a permeable overburden or both permeable burdens based on the simulation results 721 722 723 724 725 726 727 728 729 730 731 732 733 734 735 736 737 738 739 740 741 742 743 744 Acknowledgements 745 The authors would like to think Dr Matthew Reagan for 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J., et al Numerical simulation of gas production from hydrate-bearing sediments in the Shenhu area by depressurising: The effect of burden permeability J Unconventional Oil Gas Resourc (2015), http://dx.doi.org/10.1016/j.juogr.2015.08.003 829 830 831 832 833 834 835 836 837 838 839 840 841 842 843 844 845 846 847 848 849 850 851 852 853 854 855 856 857 858 859 860 861 862 863 864 865 [...]... al., 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 Pet Geol 28, 517–534 Myshakin, E.M., Gaddipati, M., Rose, K., et al., 2012 Numerical simulations of depressurization-induced gas production from gas hydrate reservoirs at the Walker Ridge 313 site, northern Gulf... 2009a Evaluation of the gas production potential of marine hydrate deposits in the Ulleung Basin of the Korean East Sea Spe J 14, 759–781 Moridis, G.J., Reagan, M.T., Boyle, K.L., et al., 2009 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Gas Conference and Exhibition in China, Beijing, China Please cite this article in press as: Sun, J., et al Numerical simulation of gas production from hydrate-bearing sediments in the Shenhu area by depressurising: The effect of burden permeability J Unconventional Oil Gas Resourc (2015), http://dx.doi.org/10.1016/j.juogr.2015.08.003 829 830 831 832 833 834 835 836 837 838 839 840 841 842 843 844 845 ... total gas produced (VP) at the well, the cumulative gas released (VD), the cumulative free gas (VR) remaining in the reservoirs, the evolution of the water production rate (QW) and the gas- to-water... differences on practical gas production are not fully considered Myshakin et al (2012) indicated that interbedded gas hydrate accumulations might be preferable targets for gas production in comparison... decreasing gas production Therefore, depressurisation is still the most effective method for long-term gas production from hydrate reservoirs (Moridis et al., 2009a) Because natural gas hydrates