The use of huff and puff method in a single horizontal well in gas production from marine gas hydrate deposits in the Shenhu Area of South China Sea

Journal of Petroleum Science and Engineering 77 (2011) 49–68

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Journal of Petroleum Science and Engineering j o u r n a l h o m e p a g e : w w w. e l s ev i e r. c o m / l o c a t e / p e t r o l

The use of huff and puff method in a single horizontal well in gas production from marine gas hydrate deposits in the Shenhu Area of South China Sea Gang Li a, George J. Moridis b, Keni Zhang b, Xiao-sen Li a,⁎ a b

Key Laboratory of Renewable Energy and Gas Hydrate, Guangzhou Institute of Energy Conversion, Chinese Academy of Sciences, Guangzhou 510640, PR China Lawrence Berkeley National Laboratory, 1 Cyclotron Rd., MS 90-1116, Berkeley, CA, USA

a r t i c l e

i n f o

Article history: Received 28 July 2010 Accepted 11 February 2011 Available online 23 February 2011 Keywords: gas hydrate huff and puff cyclic steam stimulation horizontal well Shenhu area

a b s t r a c t The Shenhu Area is located in the Pearl River Mouth Basin, the northern continental slope of the South China Sea. It is expected that the Shenhu Area will become a strategic area of gas hydrate exploitation in China. Based on currently available data from site measurements, including water depth, thickness of the HydrateBearing Layer (HBL), sediment porosity, salinity and pressures and temperatures at key locations, it is possible to develop preliminarily estimates of the gas production potential by numerical modeling. We used measurements of ambient temperature in the sediments to determine the local geothermal gradient. Estimates of the hydrate saturation and the intrinsic permeabilities of the system formations were obtained from direct measurements. The hydrate accumulations in the Shenhu Area are similar to Class 3 deposits (involving only an HBL), and the overburden and underburden layers are assumed to be permeable. These unconfined deposits may represent a large challenge for gas production. In this modeling study, we estimated gas production from hydrates at the SH7 drilling site of the Shenhu Area by means of the stream huff and puff method using a single horizontal well in the middle of the HBL. The simulation results indicate that the hydrate dissociated zone expands around the well, and the hydrate formation occurs during the injection stage of the huff and puff process. The higher temperature of the injected brine appears to have a limited effect on gas production using the huff and puff method. Reasonable injection and production rates should be adopted to avoid the over pressurization and depressurization during each huff and puff cycle. Production is invariably lower than that attainable in a confined system, and thermal stimulation is shown to have an effect over a limited range around the well. The sensitivity analysis demonstrates the dependence of gas production on the level of the increment of the injection and production rates of the huff and puff process, the temperature of the injected brine and the existence of brine injection during the injection stage. © 2011 Elsevier B.V. All rights reserved.

1. Introduction 1.1. Background Natural gas hydrates (NGH) are crystalline solids composed of water and gas. The gas molecules (guests) are trapped in water cavities (host) that are composed of hydrogen-bonded water molecules. Typical natural gas molecules include methane, ethane, propane, and carbon dioxide. Natural gas hydrate deposits involve mainly CH4, and occur in the permafrost and in deep ocean sediment, where the necessary conditions of low temperature and high pressure exist for hydrate stability (Sloan and Koh, 2008). Estimates of world hydrate reserves are very high, and vary from 0.2 × 1015–120 × 1015 m3 of methane at STP — Standard Temperature and Pressure. However, even with the most conservative estimates, it is clear that the energy in these hydrate

⁎ Corresponding author. Tel.: +86 20 87057037; fax: +86 20 87057037. E-mail addresses: [email protected], [email protected] (X. Li). 0920-4105/$ – see front matter © 2011 Elsevier B.V. All rights reserved. doi:10.1016/j.petrol.2011.02.009

deposits is likely to be significant compared to all other fossil fuel deposits (Sloan and Koh, 2008), and was considered to be a potential strategic energy resource (Collett, 2004; Klauda and Sandler, 2005; Moridis et al., 2008). There are three main methods for gas production from hydrate deposit: 1) depressurization (Ahmadi et al., 2007; Li et al., 2010a; Moridis et al., 2007, 2009b), to decrease the deposit pressure below the hydrate dissociation pressure at a specified temperature; 2) Thermal stimulation (Kawamura et al., 2007; Li et al., 2006, 2008a,b; Yousif et al., 1991), to heat the deposit above hydrate dissociation temperature with hot water, hot brine or steam injection; 3) thermodynamic inhibitor injection (Kawamura et al., 2005; Li et al., 2007; Najibi et al., 2009), to inject chemicals, such as salts and alcohols to shift the hydrate pressure– temperature equilibrium conditions; and 4) a combination of these methods (Li et al., 2010b; Moridis et al., 2009c). Of the above single methods for hydrate dissociation for gas production, depressurization appears to be the most efficient (Kurihara et al., 2005; Moridis and Reagan, 2007b; Moridis et al., 2009a). The Mallik 2002 well demonstrated proof of concept that it is possible to recover energy from

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permafrost hydrates combining dissociation techniques of depressurization and thermal stimulation (Sloan and Koh, 2008). The huff and puff method, also known as cyclic steam stimulation (CSS), was accidentally discovered by Shell Oil Company in 1960 during a Venezuela recovery project, and is widely used in the oil industry to enhance oil recovery (Leaute and Carey, 2007; Sayegh and Maini, 1984; Vittoratos, 1991). The CSS tried in horizontal wells is known as horizontal cyclic steam or HCS (Gunadi, 1999). The hot water, hot brine or steam huff and puff method is a special form of the combination of depressurization and thermal stimulation methods for gas production from hydrate deposit. The numerical simulation of gas hydrate deposit is useful in predicting the dynamic properties of gas hydrate deposit undergoing different production modes. Recent studies (Kurihara et al., 2005; Moridis and Reagan, 2007a,b) have indicated that, under certain conditions, gas can be produced from natural hydrate deposits at high rates over long periods using vertical wells by means of depressurization and thermal stimulation. Simulation results from a horizontal well study (Kurihara et al., 2005; Moridis et al., 2008) show significant advantages over vertical wells in production from Class 2 and Class 3 deposits. In this modeling study, we estimated gas production from hydrates at the SH7 drilling site of the Shenhu Area by means of the hot brine or steam huff and puff method using a single horizontal well in the middle of the HBL. 1.2. Hydrates in the Shenhu Area The Shenhu Area is near the southeast of Shenhu Underwater Sandy Bench in the middle of the north slope of the South China Sea, between Xisha Trough and Dongsha Islands. Tectonically the research area is located in the Zhu II Depression, Pearl River Mouth Basin (Fig. 1). The Shenhu Area has deposited thick sediments of 1000– 7000 m (McDonnell et al., 2000). In May, 2007, gas hydrate samples have been collected at sites SH2, SH3 and SH7 during the scientific expedition conducted by the China Geological Survey in the Shenhu

Area of northern South China Sea. This is the first time in South China Sea that confirms that there is abundant hydrate in northern South China Sea, and the Shenhu is expected as a strategic area of gas hydrate exploitation in China. According to in situ measurement of the geothermal gradient and the thermal conductivity of 19 sites, the heat flow in the Shenhu Area is 74.0–78.0 mW/m2. The geothermal gradient is 43.0–67.7 °C/km from the in situ temperature measurements at 5 drilling sites (including the site SH7 in this work) in the research area. The bottom water temperature is to 4–5 °C when the water depth reaches more than 1000 m in the South China Sea (Wu et al., 2007). The drilling results of hydrate layer in the Shenhu Area measured via nonpressure and pressure Cores indicate that the hydrate layers with the thickness from 10 m to 43 m are located about 155–229 meter below seafloor (mbsf). And the water depths of the hydrate layers are from 1108 m to 1245 m. The sediment porosity and in situ salinity in the Shenhu Area measured via pressure cores are 33%–48% and 29.0– 31.5 ppt, respectively. The temperature and salinity of seafloor are 3.3–3.7 °C and 32.8–33.4 ppt, respectively. The geologic system in this work corresponds to the site SH7 at the Shenhu Area during the China Geological Survey in the Shenhu Area of northern South China Sea in 2007. At site SH7, the sea floor is at an elevation of z = − 1108 m, the hydrate layers with the thickness of 22 m are located about 155–177 meter below seafloor (mbsf), the geothermal gradient is 43.3 °C/km, and the sample is 99.2% CH4hydrate in clayey sediments. Natural hydrate accumulations are divided into four main classes (Moridis and Reagan, 2007a,b; Moridis et al., 2007). Class 1 accumulations are composed of two layers, including the Hydrate-Bearing Layer (HBL) and an underlying two-phase fluid (containing mobile gas and liquid water) zone. Class 2 deposits include an HBL underlain by a zone of mobile water. Class 3 accumulations involve only an HBL, without underlying mobile fluid zones (and usually bounded by low-permeability overburden and underburden). Class 4 deposits involve disperse

Fig. 1. Location of research area, Shenhu Area, north slope of South China Sea.

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low-saturation oceanic hydrate without confining boundaries, which are not likely to have production potential. The hydrate accumulations in Shenhu Area are variants of Class 3 deposits, involving permeable overburden and underburden layers. These unconfined deposits are considered “challenging” hydrates (CH) for gas production, as they are characterized by the absence of impermeable boundaries — type CH-B in the terminology of Moridis et al. (2009c) — in addition to incidence in fine-textured sediments of low-permeability (type CH-k) such as silts and clays (Wu et al., 2007). 2. Method of production and well design 2.1. Dissociation methods Earlier studies (Moridis and Reagan, 2007b; Moridis et al., 2009b,c) indicate that depressurization is one of the most promising hydrate dissociation methods in the majority of hydrate deposits because of its technical and economic effectiveness. Thermal stimulation by the circulating hot water in the well shows a limited effect on the promotion of gas production, while this method with no mass (including water, steam or gas) injection into the deposit is used as an auxiliary production method during depressurization (Moridis et al., 2009c; Li et al., 2010b). The reason for this is the narrow effect range of the heat around the well caused by the limited efficiency of conduction as the main heat transfer mechanism and the opposite direction of the heat flow from the well to the deposit and the fluid flow to the production well. Numerical studies have shown that thermal stimulation by hot water, hot brine or steam injection enhances gas production when used in conjunction with depressurization with the vertical well (Moridis and Reagan, 2007a,b), but tends to be ineffective when used as the main dissociation strategy (Moridis and Reagan, 2007b). Earlier studies (Moridis et al., 2008, 2009b;) indicate that the horizontal well are superior to vertical ones in production from Class 3 deposits and in the prevention of formation of secondary hydrates promoted by Joule– Thomson cooling effect during the endothermic hydrate dissociation reaction. 2.2. Huff and puff method Combining the advantages of the depressurization and thermal stimulation (by means of hot water, hot brine or steam injection) methods, the huff and puff method is used for gas production from marine hydrate deposit with a single horizontal well in this work. The typical huff and puff method, also known as cyclic steam stimulation (CSS), consists of 3 stages: injection, soaking and production. First, hot water, hot brine or steam (hot brine in this study) is injected into a well for a certain amount of time to heat the hydrate deposit around the well. Then, the well is allowed to sit for days to allow heat soak into the deposit; and, later, the fluid is pumped out of the same well for a period of time. Once the production rate falls off, the well is put through another cycle of injection, soak and production. This process is repeated until the cost of injecting brine becomes higher than the money made from producing gas. In this work, the CSS used in a horizontal well is known as horizontal cyclic steam (HCS). The special characteristics of the huff and puff method used in all the cases in this work include (i) the absence of the “soaking” stage after the injection of brine and before the production process within one cycle (in other words, the production stage begins immediately at the end of the brine injection) because of the low efficiency of conduction as the main heat transfer pattern in the HBL during the “soaking” stage; (ii) the constant brine injection and production periods, which lasts continuously for 2 days and 3 days respectively during one cycle (the period of one cycle is 5 days), and does not change with the performance of the production rate or any other system conditions; (iii) the usage of the constantpressure production method with the driving force of ΔPW = 0.2 P0 at

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the first 15 days of the whole production process in all the cases in this work, which creates a small cylindrical hydrate dissociated zone around the well (with the radius smaller than 0.6 m, Fig. 12a). It will be easier for the brine injection into a hydrate free zone than that of high hydrate saturation with low effective permeability keff, especially for the brine injection stage in the first huff and puff cycle. In all the cases in this work, after 15 days of the constant-pressure production, both the injection and production stages of a single huff and puff cycle follow the constant mass rate. During the production stage in each cycle, to eliminate the possibility of ice formation, reasonable production rate Q pro should be selected by ensuring the wellbore pressure PW N PQ (= P at the quadruple point). On the other hand, reasonable injection rates of each cycle Q inj should be chosen during the injection stage to avoid the overpressure of the deposit, and the maximum of the wellbore pressure Pmax follows Eq. (1). Pmax = ρw gΔZsf + f ρs gΔZwd

ð1Þ

where ρw and ρs are the typical densities of the ocean' water (1035 kg/ m3 at atmospheric pressure) and the deposit (2600 kg/m3) respectively, g is the gravity, ΔZsf and ΔZwd are the water depth of the seafloor and the well depth below the seafloor respectively and f is the safety factor. At site SH7 in the Shenhu Area, ΔZsf = 1108 m, ΔZwd = 166 m, and the safety factor f = 0.8, so the reasonable Pmax = 14.64 MPa in this work. 2.3. Well design A single horizontal well is used in this work because of its significant advantages over vertical wells in production from Class 3 deposits (Moridis et al., 2008; Reagan et al., 2008). Fig. 2 shows the well design used in the huff and puff method. There are 8 evenly distributed grooves along the circumference of the horizontal well. Both the injected brine and the produced gas and water from the reservoir flow from the same single horizontal well. A previous study (Moridis et al., 2009b) introduced a single well used as hot brine injection well and gas production well at the same time during the production period. A new well design involving a single well with hot water that circulates inside the wellbore was proposed by Moridis et al. (2009c) and used in a recent study (Li et al., 2010b). Comparing with these well designs, the well used in this study is much simpler and practically feasible. The source of the hot brine is assumed to be a deeper warmer deposit. The wellbore flow is assumed to be Darcian flow through a pseudoporous medium describing the interior of the well. In this horizontal wellbore, this pseudo-medium had a porosity ϕ = 1.0, a high permeability k = 10−12 m2 (1 Darcy), and a capillary pressure PC = 0. 3. Numerical models and simulation approach 3.1. The numerical simulation code For this numerical simulation study, we used both the serial and parallel versions of the TOUGH + HYDRATE code (Zhang et al., 2008; Moridis et al., 2009d). This code can model the nonisothermal hydration reaction, phase behavior, and flow of fluids and heat under conditions typical of natural CH4-hydrate deposits in complex geologic media. It includes both an equilibrium and a kinetic model of hydrate formation and dissociation. The model accounts for heat and up to four mass components (i.e., water, CH4, hydrate, and watersoluble inhibitors such as salts or alcohols) that are partitioned among four possible phases: gas, aqueous liquid, ice, and hydrate. A total of 15 states (phase combinations) can be described by the code, which can handle any combination of hydrate dissociation mechanisms and can describe the phase changes and steep solution surfaces that are typical of hydrate problems.

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G. Li et al. / Journal of Petroleum Science and Engineering 77 (2011) 49–68 Table 1 Hydrate deposit properties and conditions at site SH7 in the Shenhu Area, South China Sea. Parameter

Value

Overburden thickness ΔZO HBL thickness ΔZH Underburden thickness ΔZU Well position above the HBL base ΔZW Initial pressure PB (at base of HBL) Initial temperature TB (at base of HBL) Initial saturation in the HBL Gas composition Geothermal gradient Water salinity (mass fraction) Intrinsic permeability kx = ky = kz (all formations) Porosity ϕ (all formations) Grain density ρR (all formations) Dry thermal conductivity kΘRD (all formations) Wet thermal conductivity kΘRW (all formations) Composite thermal conductivity model (Moridis et al., 2005, 2009d)

30 m 20 m 30 m 11 m 13.83 MPa 287.31 K (14.15 °C) SH = 0.44, SA = 0.56 100% CH4 0.0433 K/m 0.0305 7.5 × 10–14m2 (= 0.075 D)

Capillary pressure model (van Genuchten, 1980) SirA λ P01 Relative permeability model (Moridis et al., 2009d)

n nG SirG SirA

Fig. 2. Well design used in the huff and puff method during gas production from methane hydrate deposit in this study.

3.2. Geometry and domain discretization In this work, the hydrate-forming gas is assumed to be 100% CH4. The system properties and initial conditions are shown in Table 1. The HBL is 22 m thick, and overlain by a 30 m-thick permeable overburden and underlain by a 30 m-thick permeable underburden, allowing fluid and heat flows through the boundaries. The geometry and configuration of the Class 3 system are shown in Fig. 3a. The well placed in the middle of the HBL had a radius rW = 0.1 m. The 30 m overburden and underburden are sufficient to provide accurate estimates of heat transfer with the hydrate deposit (Moridis and Reagan, 2007a,b; Moridis et al., 2007). Comparing with the 22 m thick HBL, 30 m top and bottom open boundaries are also sufficient to allow accurate pressure transfer in the deposit. The well is placed at the center of the HBL with x = 0 and z = 0 (Fig. 3b). Because of symmetry, we use 2-D grids (y = 1) and focus on the deposit with x ≥ 0. A no-flow boundary (i.e., no fluids flow and heat transfer) is applied at the deposit at x = 45 m, indicating a well spacing of 90 m. In the absence of field data from the site so far, some media properties were assumed in Table 1. The Cartesian coordinates were discretized into 11,259 elements, of which 11,034 were active (the remaining being boundary cells). The uppermost and lowermost layers which are inactive boundary cells corresponded to constant temperature and pressure. The discretization along the z axis is coarser in both the top of the overburden (z N 22 m) and the bottom of the underburden (z b −22 m), which is permissible in the region far from the HBL. The discretization along the z axis is fine with the

0.41 2600 kg/m3 1.0 W/m/K 3.1 W/m/K kΘC = kΘRD 1/2 +(S1/2 A + SH )(kΘRW − kΘRD) + ϕ SI kΘI Pcap = − P01 [(S⁎)−1/λ − 1]1 − λ S* = (SA − SirA)/(1 − SirA) 0.29 0.45 105 Pa krA = (SA⁎)n krG = (SG⁎)nG SA⁎ = (SA − SirA)/(1 − SirA) SG⁎ = (SG − SirG)/(1 − SirA) Original porous medium (OPM) 3.572 3.572 0.05 0.30

ΔZ ≤ 0.5 m including the HBL and the bottom of the overburden (z b 22 m) and the top of the underburden (− 22 m b z). Such a fine discretization is important and enough for accurate predictions (Moridis and Reagan, 2007a; Moridis et al., 2007). Because of the importance of the vicinity of the wellbore, a very fine discretization around the horizontal well is used, where there are circular discretization within r = 7.5 m (Fig. 3b). Assuming an equilibrium reaction of hydrate dissociation (Clarke and Bishnoi, 2000; Kowalsky and Moridis, 2007; Moridis et al., 2009d), this grid results in 11,034 (active cells) × 4 (number of equations per cell) = 44,136 coupled equations that are solved simultaneously. 3.3. Initial conditions Based on the results of the temperature equilibrium test by the in situ measurement, the temperatures of the sample SH7B-FPWS1 (137 mbsf), SH7B-FPWS2 (180 mbsf) and SH7B-FPWS3 (196 mbsf) at site SH7 were 12.49 °C, 14.39 °C and 15.04 °C, respectively, and the local geothermal gradient of the site SH7 was about 43.2 °C/km. The temperature distribution of the entire system including the temperature TB (at z = −1285 m, Fig. 3a) was determined. The initial temperature at the base of HBL is 14.15 °C (see Table 1). The hydrate Pressure–Temperature (P–T) equilibrium curve was then used to provide the lower limit of PB at the base of HBL (i.e., the equilibrium P) to maintain the stability of the initial HBL. In this work, PB that is slightly higher than the corresponding equilibrium pressure is initialized as the pressure at the base of the HBL, because such a system is easy to destabilize with mild depressurization or thermal stimulation. Assuming the pressures in the oceanic subsurface from the top to bottom of the entire system shown in Fig. 3a follow the hydrostatic distribution, we determine the initial P at the top and bottom boundaries (at z = − 1233 m and z = −1315 m, respectively, Fig. 2) using a P- and T-adjusted saline water density typical of ocean

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Fig. 3. (a) Schematic of the marine hydrate deposit at the SH7 site of the Shenhu Area, South China Sea and (b) grid used in the simulations.

water (1035 kg/m3 at atmospheric pressure), from which the remaining information on the pressure distribution was obtained by means of a short simulation. After the initialization of the P and T distribution in each gridblock (Fig. 3b), the other initial conditions including the SH and SA in the HBL, the salinity and the saturations of gas and water in the deposit are also obtained by another short simulation until the entire system maintains stable. In other words, the pressure, temperature, salinity and saturations of gas, water and hydrate in the system will never change until there is a disturbance from outside. In the HBL, the initial hydrate saturation SH is 0.438 and the aqueous saturation SA is 0.562, which means that there is no free gas in this layer. There is a single aqueous phase with dissolved gas in both the overburden and the underburden. 4. Production from marine Class 3 deposit at site SH7 in the Shenhu Area 4.1. The reference case The reference case is case (R) in all the figures in this work. The properties and conditions pertaining to the reference case are listed in Table 1. In the reference case, the initial pressure and temperature in the HBL at z = 0 (the position of the production well) is about P0 = 13.7 MPa and T0 = 13.7 °C. After 15 days of constant-pressure production with the driving force of ΔPW = 0.2 P0, the brine injection stage and the production stage last continuously for 2 days and 3 days with the constant injection rate Qinj = 4.32 t/d and production rate Qpro = 5.18 t/d respectively during each cycle of the huff and puff process. In the reference case, the temperature of the injected hot brine is 90 °C, and the salinity of the injected hot brine during the

injection stage in the huff and puff cycle is the same with the water salinity in the initial HBL (0.0305 mass fraction) shown in Table 1. 4.2. Gas and water production Fig. 4 shows the evolution of the cumulative volumes of (a) produced CH4 at the well (VP) and (b) hydrate-originating CH4 released in the reservoir (VR) using the huff and puff method with constant injection rates Q inj and production rates Q pro during gas production from methane hydrate deposit in this work. In each case, the injection rates and production rates maintain constant during the whole production process and the Q pro is larger than the corresponding Q inj. During each huff and puff cycle, the injection and production periods last continuously for 2 days and 3 days respectively. The performance of the VP and VR is investigated by the variation of the Q inj and Q pro through the following cases: (i) Q inj = 2.59 t/d, Q pro = 4.32 t/d, (ii) Q inj = 2.59 t/d, Q pro = 5.18 t/d, (iii) Q inj = 3.46 t/d, Q pro = 5.18 t/d, and (iv) Q inj = 4.32 t/d, Q pro = 5.18 t/d (the reference case). In all these cases, the unsmooth curves of VP and the zigzag (seesaw) appearances of the curves of VR are caused by the frequent injection and production behavior during the huff and puff cycle. The cumulative volume of the produced gas VP increases monotonically in the production stage, while it maintains constant during the injection of the brine (Fig. 4). In other words, VP increases step by step with the huff and puff cycle and never decreases during the whole gas production process. On the other hand, the cumulative volume of hydrate-originating CH4 released in the reservoir VR appears quite different (Fig. 4). During the production stage in each cycle, VR increases over time, which means that there is hydrate dissociating

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Fig. 4. Cumulative volumes of (a) produced CH4 at the well (VP) and (b) hydrateoriginating CH4 released in the reservoir (VR) using the huff and puff method with constant injection rates Q inj and production rates Q pro during gas production from methane hydrate deposit in this study (Q inj = 4.32 t/d, Q pro = 5.18 t/d in the reference case).

and gas releasing from hydrate. On the contrary, VR decreases during the injection stage in each cycle, and the hydrate formation occurs due to the pressurization caused by the mass (brine) injection. In general, VR shows uptrend over time during the whole gas production process. As shown in Fig. 4, the diminishing uptrend of VR indicates that the hydrate dissociation rate decreases over time during using the huff and puff method with constant injection rates Q inj and production rates Q pro, while the straight slope of VP suggests that the volumetric rate of gas production maintains almost stable during the entire simulation, and the majority of the gas produced from the well comes from CH4 dissolved in the water rather than from the hydrate dissociated gas, especially at the later times of the production process. As shown in Fig. 4, as expected, both VP and VR in case (i) are obviously and consistently lower than that in case (ii). The reason for this is that under the same Q inj in cases (i) and (ii), both the gas production rate and the hydrate dissociation rate increase with an increasing Q pro. However, as already discussed above, reasonable production rate Qpro should be selected by ensuring the wellbore pressure PW N PQ (= P at the quadruple point) and there is a limitation of the maximum of Q pro. In other words, the minimum of the wellbore pressure PW decreases with an increasing Q pro. In cases (ii) to (iv), Q pro = 5.18 t/d is selected as the common production rate Q pro, and there is no ice formation in these cases. In Fig. 4, in cases (ii) to (iv), VR increases with an increasing Q inj during the whole production process, which indicates that under the same Q pro during the production stage of the huff and puff process, the summation of the gas released from the hydrate deposit VR (the difference between the gas released from the hydrate dissociation during the production stage and the gas consumed in the hydrate formation during the mass injection process) is larger in the cases with higher Q inj. The reason for this is that the more brine injected into the deposit in a certain time (the injection stage lasts for 2 days in each cycle of the huff and puff process in all the cases in this work), the more quantity of heat is brought into the system and the more hydrate dissociated during this period, although the higher system pressure is reached at the same time. In other words, the effect of the thermal stimulation could easily overwhelm the disadvantages of the pressurization caused by brine injection. In Fig. 4, at the early times of the production process (approximately t b 100 days) in cases (ii) to (iv), VP increases with an increasing Q inj, which shows the similar profiles with the corresponding VR discussed above and the reason for this is still the same with that of VR. However, at

the later times of the production periods, under the same Q pro during the production stage, VP decreases with the increase of Q inj. The huff and puff process can be quite effective in the first few cycles, and the more brine injected into the deposit, the more gas released from the hydrate dissociation and the more gas produced from the well. In other words, higher Q inj leads to larger VR and VP during this period. In the huff and puff process with the constant injection and production rates in all the cycles, the hydrate dissociation efficiency decreases over time due to the limited range of the thermal diffusion from the injected brine, and depressurization rather than thermal stimulation is dominant for the gas production rate at the later cycles. The less mass injected into the deposit (the lower injection rates Q inj), the larger driving force is obtained and the more gas is produced from the well, leading to a higher VP shown in Fig. 4. In Fig. 4, case (ii) has the largest VP (approximately 4500 ST m3/m of well) after about 1 year production. The average gas production rate Qavg = VP/t is approximately 15.8 ST m3/day/m of well in case (ii). For a well spacing of 90 m and a 1000 m well in case (ii), Q avg = 3.16 × 104 ST m3/day (1.11 million scf/D), and about 9 times lower than the rule-of-thumb for commercially viable production rates from offshore gas wells. Fig. 5 shows the cumulative mass of (i) the sum of the produced and the injected mass, (ii) the difference of the produced and the injected mass and the gas-to-water ratio RGW using the huff and puff method with constant injection rates Q inj and production rates Q pro during gas production from methane hydrate deposit in this work. The sum of the produced and the injected mass “Pro + Inj” shown in Fig. 5 is the cumulative mass (including the brine injected into the deposit and the water and gas produced from the well) pumped during the whole huff and puff process, and provides a measure of the energy cost of the huff and puff method. The difference of the produced and the injected mass “Pro-Inj” indicates the cumulative outflow of the mass from the deposit. In all the cases in this work, “Pro-Inj” is positive, which leads to depressurization over time in the deposit, especially at the later cycles of the huff and puff process. In a word, under the condition of PQ b PW b Pmax, a smaller “Pro + Inj” and a larger “Pro-Inj” seems more effective for gas production using the huff and puff method, and in this point of view, case (ii) is the most efficient one. However, because of the limited VR and effective permeability keff in the HBL, PW is easy to decrease lower than PQ with the extreme large driving force under the constant production rate when the difference of the produced and the injected mass is too large.

Fig. 5. Cumulative mass of (i) the sum of the produced and the injected mass, (ii) the difference of the produced and the injected mass and the gas-to-water ratio RGW using the huff and puff method during gas production from methane hydrate deposit in this study (the reference case).

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The gas-to-water ratio RGW = VP/MW, where VP is the cumulative volume of the produced CH4 and MW is the cumulative mass of the produced water. RGW provides an additional measure of the effectiveness of hydrate dissociation as a gas-producing method and a relative criterion of gas production performance. Both VP and MW maintain constant during the injection stage and increase only during the production stage in each cycle. In other words, VP and MW increase step by step during the same period and result in a RGW only changing in the production stage. In cases (i) and (ii) with the same Q inj, a higher Q pro leads to a larger RGW. In cases (ii) to (iv) with the same Q pro, RGW is mainly up to VP, and it increases with an increasing Q inj at the early times and decreases with that at the later times of the production process. In a word, in the cases with the constant Q inj and Q pro, RGW is mostly decided by VP and shows the similar profiles with it. As shown in Fig. 5, RGW declines rapidly to a quite lower level in cases (i) to (iv) (approximately 4.0–10.0 ST m3 of CH4/m3 of H2O/m of well), which indicates that the gas production from the deposit in this work using the huff and puff method is uneconomically profitable from the relative criterion point of view. Considering the energy cost during the hot brine injection process, mainly the power used to pump the fluid into the well, the efficiency of gas production using the huff and puff method decreases and the production situation deteriorate. 5. Spatial distributions of the reference case in a huff and puff cycle In all the cases in this study, the periods of each huff and puff cycle is 5 days, including 2 days of injection stage and 3 days of production stage. We investigated the evolutions of spatial distributions of SH, SA, SG, P, T and XS over time from the end of the first injection day (101 days) in one cycle to that of the next cycle (106 days) using the huff and puff method in the reference case with constant injection rate (Q inj = 4.32 t/d) and production rate (Q pro = 5.18 t/d) during gas production from methane hydrate deposit in this study.

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5.1. Spatial distributions of SH, SA and SG Figs. 6 to 8 show the evolutions of the SH, SA, SG spatial distributions over time from 101 days to 106 days in the HBL (−11 m b z b 11 m) using the huff and puff method in the reference case during gas production from methane hydrate deposit in this study. The 101 days (Figs. 6a, 7a and 8a) are the end of the first injection day of a typical huff and puff cycle, while the 105 days (Figs. 6e, 7e and 8e) are the end of the third production day of the same cycle and simultaneously the start point of the next cycle. Fig. 6 shows the evolution of the SH spatial distribution over time in a huff and puff cycle in the HBL. The hydrate dissociation occurs mostly in the vicinity of the well, especially around a cylindrical interface shown in Fig. 6. This is the result of the synergistic effect of the heat stimulation by the hot brine injection and the depressurization during the production stage of the huff and puff cycle. In general, the SH spatial distribution above and below the well is not symmetry, and the SH in the area below the well is smaller than that above the well, which indicates that the hydrate dissociation is more intense in the area below the well because of higher temperature there (Fig. 10a and b). As shown in Fig. 6, the hydrate dissociated zone diminishes slightly and continuously with the hot brine injection due to the system pressurization and enlarges consistently during the production stage caused by hydrate dissociation. As the hot brine injected into the deposit from the well, the system is obviously pressurized, especially within and around the hydrate dissociated zone in the vicinity of the well (Fig. 9a and b). The consequent emergence of the secondary hydrate occurs at the positions above the well and beyond the hydrate dissociated zone near the top of the HBL, as shown in Fig. 6a and b, where the local deposit does not warm up with the hot brine injection from the well (Fig. 10). Comparing with that at the end of the first injection day (101 days) shown in Fig. 6a, as expected, there is obviously more secondary hydrate formed at the end of the second injection day (102 days, the end of the injection stage in the cycle). One of the reasons for this is the relative higher system

Fig. 6. Evolution of spatial distribution of SH over time from 101 days to 106 days using the huff and puff method during gas production from methane hydrate deposit in this study (the reference case).

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Fig. 7. Evolution of spatial distribution of SA over time from 101 days to 106 days using the huff and puff method during gas production from methane hydrate deposit in this study (the reference case).

pressure at the end of the injection stage due to the continuous hot brine injection. Furthermore, the temperature of the secondary hydrate formation zone does not increase obviously with the hot brine injection (Fig. 10a and b) due to the limited efficiency of conduction as the main heat transfer mechanism in the HBL, excluding the cylindrical area around the well within the moving front of the

injected hot brine (with the radius smaller than 2.0 m, Fig. 7b), and the rate of its propagation declines significantly over time as the volume around the well increases as a function of r2 (Moridis et al., 2009c). In this work, the injected hot brine from the well is assumed to have a cylindrical moving front around the well. In the 2-D system in this work, it is assumed that y = 1 m in each grid. With the constant

Fig. 8. Evolution of spatial distribution of SG over time from 101 days to 106 days using the huff and puff method during gas production from methane hydrate deposit in this study (the reference case).

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Fig. 9. Evolution of spatial distribution of P over time from 101 days to 106 days using the huff and puff method during gas production from methane hydrate deposit in this study (the reference case).

hot brine injection rate Q inj = 4.32 t/d during the injection stage, the calculated radius of the moving front of the injected hot brine at the end of the first and the second injection days during each huff and puff cycle is approximately 1.17 m and 1.66 m respectively, which is almost accordant to the cylindrical area with SA = 1.0 shown in Fig. 7a and b (101 days and 102 days) respectively. At the beginning of the production stage of the huff and puff cycle, the hot brine which was injected during the earlier injection stage and accumulated within the cylindrical area around the well is firstly and abundantly produced from the well. It is assumed that all the injected hot brine is produced before the gas and water production from the deposit. At the end of the first production day with the constant production rate Q pro = 5.18 t/d, there is still a cylindrical area of the injected hot brine and with SA = 1.0, and the calculated radius of this area is approximately 1.05 m, which generally accord with the cylindrical area with SA = 1.0 shown in Fig. 7c (103 days). While the production rate Q pro is higher than the hot brine injection rate Q inj, after 2 days of production (the same period with the injection process), all the injected hot brine is produced from the well and the corresponding cylindrical area with SA = 1.0 disappears, as shown in Fig. 7d and e. Comparing with the cases of Class 3 deposit with impermeable upper boundary (Moridis et al., 2009b) (with the maximum of SG N 0.5), there is no such upper permeability barrier and the SG in the deposit is much lower in this work (the maximum of SG is lower than 0.15, Fig. 8). The SG distributions in Fig. 7 indicate gas accumulation in

the vicinity of the well, leading to the highest SG observed in the deposit. During the production stage (103 days to 105 days, Fig. 7c to e), the gas released from the hydrate dissociation flows towards the well and accumulates there, and the maximum of the corresponding SG is reached around the well. In the hot brine injection stage (101 days and 102 days, Fig. 7a and b), some of the free gas accumulated around the well after the production stage was driven away from the well by the injected hot brine, and some of them takes part in the hydrate formation already discussed in Fig. 4 as the VR decreasing process, leaving some free gas with relative low SG around the cylindrical area with SA = 1.0. 5.2. Spatial distribution of P Fig. 9 shows the evolution of the P spatial distribution over time from 101 days to 106 days in the entire deposit (−41 m b z b 41 m) using the huff and puff method in the reference case during gas production from methane hydrate deposit in this study. The white lines in Fig. 9 indicate the initial position of the top and the base of the HBL at z = 11 m and z = −11 m, respectively. The P distribution in the deposit with the permeable overburden and underburden during the huff and puff production process shows some special features in the entire deposit. First, the evolution of the pressure gradient around the well over time in a huff and puff cycle is obviously shown in Fig. 9, including the continuously increasing pressure during

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Fig. 10. Evolution of spatial distribution of T over time from 101 days to 106 days using the huff and puff method during gas production from methane hydrate deposit in this study (the reference case).

the injection stage and the consequently decreasing pressure due to the depressurization in the production stage. Second, the pressurization and the depressurization in the entire deposit (including the HBL, the permeable overburden and underburden) are caused by the mass injection and production during the huff and puff process and the rapidly propagating pressure wave in the permeable deposit. Last, the inflections of the P distribution near the white lines of the initial position of the top and the base of the HBL are caused by the different effective permeability keff of the HBL and the upper and lower boundaries. In the Class 3 deposit in this work, the initial HBL involves both hydrate and aqueous, while there is only a single aqueous phase with dissolved gas in both the overburden and the underburden, which caused the difference of permeabilities in these layers. 5.3. Spatial distribution of T Fig. 10 shows the evolution of the T spatial distribution over time from 101 days to 106 days in the HBL (− 11 m b z b 11 m) using the huff and puff method in the reference case during gas production from methane hydrate deposit in this study. The T distributions in Fig. 10 indicate the limited thermal effect range of the huff and puff method around the well, leading to the highest T (approximately 90 °C, which is the temperature of the injected hot brine in the reference) observed in the deposit during the injection stage (101 days and 102 days shown in Fig. 10a and b). Most of the HBL does not warm up with the hot brine injection except a small cylindrical area around the well. As expected, the radius of the cylindrical area increases with the hot brine injection, and reaches the maximum of approximately 6.0 m at the end of the injection stage. The thermal effect range is larger than the radius of the moving front of the injected hot brine (smaller than 2.0 m, Fig. 7b) due to thermal conduction and convection in the deposit. As shown in Fig. 10a and b, the T distribution of the areas above and below the well is not symmetry, and obviously it is warmer in the area below the well, because of the gravity of the injected hot brine and the higher effective permeability keff there. As shown in Fig. 10e, after 3 days of gas production, the thermal effect range

reduces significantly and the temperature of the well decreases to lower than 40 °C. 5.4. Spatial distribution of XS Fig. 11 shows the evolution of the spatial distribution of the salt concentration (expressed as the mass fraction of salt XS in the aqueous phase) over time from 101 days to 106 days in the HBL (−11 m b z b 11 m) using the huff and puff method in the reference case during gas production from methane hydrate deposit in this study. In all the cases in this work, the salinity of the injected hot brine is the same with that of the water in the initial HBL. The concentration effect of the hydrate formation and the dilution effect of dissociation on salinity are obviously shown in Fig. 11. Because the salts cannot be included in the hydrate crystals, fresh water is released from hydrate dissociation and reduces the water salinity in situ. Thus, the locations of intense dissociation activity can be identified as the loci of low salinity (Moridis et al., 2009b). The effective permeability keff in the hydrate dissociated zone is higher than that in the undissociated zone in the HBL, so the liquid flows faster in the cylindrical hydrate dissociated zone around the well. The low salinity area during the production stage (Fig. 11c to 11e) indicates the locations of the fresh water released from hydrate dissociation and flowing towards the well. On the contrary, the local salinity increases during the fresh water consuming process of hydrate formation. During the hot brine injection stage, with the pressurization of the deposit, the areas of relative high salinity indicate the locations of hydrate formation. Obviously the salinity is higher in the area above the well than that below the well in Fig. 11a and b, because of the relative higher SH and lower T there. 6. Spatial distributions of the reference case of the production process We investigated the evolutions of spatial distributions of SH, SA, SG, P, T and XS over time using the huff and puff method in the reference

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Fig. 11. Evolution of spatial distribution of XS over time from 101 days to 106 days using the huff and puff method during gas production from methane hydrate deposit in this study (the reference case).

case with constant injection rate (Q inj = 4.32 t/d) and production rate (Q pro = 5.18 t/d) during gas production from methane hydrate deposit in this study. The time points in all of the figures that describe the spatial distribution of reservoir properties and conditions in Figs. 12 to 17 are 15 days, 60 days, 150 days, 240 days, 330 days and

420 days respectively. In these figures, 15 days is the end of the constant-pressure production process with the driving force of ΔPW = 0.2 P0, and it is simultaneously the start point of the whole huff and puff process in this study. The other time points, including 60 days, 150 days, 240 days, 330 days and 420 days, are respectively

Fig. 12. Evolution of spatial distribution of SH over time using the huff and puff method during gas production from methane hydrate deposit in this study (the reference case).

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Fig. 13. Evolution of spatial distribution of SA over time using the huff and puff method during gas production from methane hydrate deposit in this study (the reference case).

the end of the third production day of the corresponding huff and puff cycle (the start point of the next huff and puff cycle, which is similar with the 105 days discussed above in Fig. 6 to 11). 6.1. Spatial distributions of SH, SA and SG Figs. 12 to 14 show the evolutions of the SH, SA, SG distributions over time in the HBL (−11 m b z b 11 m) using the huff and puff

method in the reference case during gas production from methane hydrate deposit in this study. All the time points in Figs. 12 to 14 are the ends of the third production day in a huff and puff cycle (except the 15 days in Figs. 12a, 13a and 14a) and simultaneously the start points of the next cycle. The evolutions of the spatial distributions of the hydrate, aqueous and gas saturations over time provide a measure of the magnitude of the hydrate dissociation and the phase change and flow profiles in the deposit.

Fig. 14. Evolution of spatial distribution of SG over time using the huff and puff method during gas production from methane hydrate deposit in this study (the reference case).

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Fig. 15. Evolution of spatial distribution of P over time using the huff and puff method during gas production from methane hydrate deposit in this study (the reference case).

As shown in Figs. 12 to 14, the hydrate dissociation pattern shows the following characteristics: (i) the evolution of a cylindrical dissociation interface around the well; (ii) the evolution of the lower dissociation interface near the base of the HBL; (iii) the mergence of the lower dissociation interface and the cylindrical interface around the well; (iv) the emergence and the evolution of the secondary hydrate near the top of the HBL; (v) the evolution of the high-SA region (defined as the area with the SA larger than the initial aqueous saturation 0.56 in the HBL, Table 1) and the breakthrough of the aqueous from the underburden to the cylindrical dissociated zone around the well (at the same time, the lower dissociation interface and the cylindrical interface merge together); and (vi) the expanding of the gas accumulation area in the vicinity of the well. Of those, (i), (ii) and (iii) are universal features of the hydrate dissociation using the single horizontal well (Moridis et al., 2008, 2009c; Li et al., 2010b), and in this work, they are caused by the synergistic effect of the heat stimulation by the hot brine injection and the depressurization during the production stage of the huff and puff cycle. On the other hand, (iii) is promoted by the heat flow brought with the fluid flow from the underburden towards the well; the emergence of the secondary hydrate in (iv) occurs above the well and beyond the hydrate dissociated zone near the top of the HBL, because the dissociated water and gas from hydrate move both away and toward the well. The dissociated gas moves deeper into the hydrate body (away from the well, especially moves upwards because of buoyancy) and causes

secondary hydrate formation there that result in SH higher than the initial one (0.44 in Table 1). As the hydrate dissociated zone expands over time, more and more gasses dissociated from hydrate near the dissociation interface and move into the hydrate body, result in the evolution (growth) of the secondary hydrate in (iv) during the huff and puff process. (v) is a result of the fresh water released from hydrate dissociation, and it is affected by the fluid flow from the permeable underburden, which is quite different from the cases with impermeable boundaries (Moridis et al., 2009b). (vi) is a result of the expanding of the hydrate dissociated zone. The SG in the deposit with permeability boundaries is much lower in this work (the maximum of SG is about 0.10) than that in the cases with impermeable boundaries (with the maximum of SG N 0.5) (Moridis et al., 2009b). Furthermore, the gas accumulation area is obviously affected by the fluid flow from the underburden towards the well. 6.2. Spatial distribution of P Fig. 15 shows the evolution of the P distribution over time in the entire deposit (− 41 m b z b 41 m) using the huff and puff method in the reference case during gas production from methane hydrate deposit in this study. The white lines in Fig. 15 indicate the initial position of the top and the base of the HBL at z = 11 m and z = − 11 m, respectively. The time points in Fig. 15 are the ends of the third production day in a different huff and puff cycle (except the 15 days in

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Fig. 16. Evolution of spatial distribution of T over time using the huff and puff method during gas production from methane hydrate deposit in this study (the reference case).

Figs. 12a, 13a and 14a) and simultaneously the start points of the next cycle. The P distribution over time in the deposit with permeable overburden and underburden using the huff and puff method with a single horizontal well shows the following features including (i) the

pressure gradient around the well over time at the ends of the production stages; (ii) the obviously observed increase of the minimum of the pressure around the well over time in Fig. 15; (iii) the pressure drop in the permeable overburden and underburden; (iv) and the inflections of the P distribution near the white lines of the initial position

Fig. 17. Evolution of spatial distribution of XS over time using the huff and puff method during gas production from methane hydrate deposit in this study (the reference case).

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of the top and the base of the HBL in Fig. 15. Of those, (i) is due to the depressurization effect during the production stage, (ii) is caused by the decrease of the hydrate dissociation rate over time (the diminish uptrend of VR over time as already discussed in Fig. 4) and the reduce of the depressurization efficiency due to the breakthrough of the water from the underburden, (iii) is a result of the permeable boundaries, which is different from the constant pressure in the overburden and underburden in the cases with impermeable boundaries, the reason for (iv) is the different effective permeability keff of the HBL and the upper and lower boundaries, which is already discussed above. 6.3. Spatial distribution of T Fig. 16 shows the evolution of the T distribution over time in the HBL (−11 m b z b 11 m) using the huff and puff method in the reference case during gas production from methane hydrate deposit in this study. The T distributions at the end of the huff and puff cycle shows that (i) the maximum of T in the deposit is still in the well after three days gas production; (ii) the highest T observed in the deposit is lower than 30 °C, which is much lower than the temperature of the injected hot brine (approximately 90 °C) and indicates the cooling effect during the dissociation and production proceed; (iii) the maximum of T in the deposit at the end of the huff and puff cycle increases over time due to the expanding of the hydrate dissociated zone and the decrease of the hydrate dissociation rate over time; (iv) the T distribution of the areas above and below the well is not symmetry, and obviously it is warmer in the area below the well, especially after the breakthrough of the warmer water from the underburden, because of the higher effective permeability keff after the hydrate dissociated there. 6.4. Spatial distribution of XS Fig. 17 shows the evolution of the distribution of the salt concentration (expressed as the mass fraction of salt XS in the aqueous phase) over time in the HBL (−11 m b z b 11 m) using the huff and puff method in the reference case during gas production from methane hydrate deposit in this study. The XS distribution varies in the HBL, while the XS of the injected hot brine is the same with the water salinity in the initial HBL. The locations of the intense dissociation activity can be identified as the low XS zone (defined as the area with the XS lower than 0.0300, which is lower than the initial water salinity in the HBL), where the dilution effect of hydrate dissociation is obviously shown in Fig. 17. The fresh water releases from the hydrate around the dissociation interface and flows towards the well. On the other hand, the high XS zone (defined as the area with the XS higher than 0.0310) indicates the locations of the water consuming process caused by the concentration effect of the hydrate formation in this area. The high XS zone mainly contains the area of the secondary hydrate with relative high SH above the well (Fig. 12).

Fig. 18. Sensitivity analysis: effect of the increment of the injection and production rates and the impermeable overburden on the cumulative volumes of (a) VP and (b) VR using the huff and puff method during gas production from methane hydrate deposit in this study.

both 0. In the reference case and cases (a) to (d), the increments of the injection rate are 0, 3%/cycle, 4%/cycle, 0.13 t/d/cycle and 0.22 t/d/ cycle with the initial injection rate Q inj = 4.32 t/d, and the

7. Sensitivity analysis of production from site SH7 in the Shenhu Area In this work, we investigated the sensitivity of gas production using the huff and puff method to the following conditions and parameters: the increment of the injection and production rates, the existence of the impermeable overburden, the existence of the impermeable boundaries (overburden and underburden), the temperature of the injected brine Tinj and the existence of brine injection during the injection stage. 7.1. Sensitivity to the increment of Q inj and Q pro In Figs. 18 and 19, the case with the constant injection rate Q inj = 4.32 t/d and production rate Q pro = 5.18 t/d (the reference case) means the increments of the injection and production rates are

Fig. 19. Sensitivity analysis: effect of the increment of the injection and production rates and the impermeable overburden on the cumulative mass of (i) the sum of the produced and the injected mass, (ii) the difference of the produced and the injected mass, and RGW using the huff and puff method during gas production from methane hydrate deposit in this study.

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corresponding increments of the production rate in these cases are 0, 3%/cycle, 4%/cycle, 0.17 t/d/cycle and 0.35 t/d/cycle with the initial production rate Q pro = 5.18 t/d during gas production from methane hydrate deposit in this work. Fig. 18 shows the dependences of VP and VR on the increments of the injection and production rates using the huff and puff method. Fig. 19 shows the corresponding behaviors of the cumulative mass of (i) the sum of the produced and the injected mass and (ii) the difference of the produced and the injected mass and the gas-to-water ratio RGW. As already discussed, the uptrend of VR decreases over time during using the huff and puff method with constant injection rates Q inj and production rates Q pro, because the hydrate dissociation rate decreases when the dissociation interface moves away from the well and the moving front of the injected hot brine, and beyond the thermal effect range. An effective method to accelerate the hydrate dissociation process is to increase the hot brine injection rate over time to expand maximum of the moving front of the injected hot brine and the thermal effect range. After increasing the injection rate, the production rate should be correspondingly increased and keeping consistently higher than the injection rate. In this work, based on the reference case, increments of both the injection and production rates are used in cases (a) to (d) in Figs. 18 and 19 with the same initial Q inj = 4.32 t/d and Q pro = 5.18 t/d. In all the cases in this work, the period of one cycle is 5 days, and the huff and puff process starts from 16 days (after 15 days of constant-pressure production). So in the cases in Figs. 18 and 19, in the first huff and puff cycle, on the 16 days and 17 days the injection rate is Q inj = 4.32 t/d and on the 18 days to 20 days the production rate is Q pro = 5.18 t/d. In case (a), the increments of 3%/cycle mean that in the second cycle, the injection rate is Q inj = 4.32 t/d× (1.0 + 3%)= 4.45 t/d on the 21 days and 22 days, and the production rate is Q pro = 5.18 t/ d × (1.0+ 3%) = 5.34 t/d on the 23 days to 25 days. Similarly, in case (c), the increments of 0.13 t/d/cycle of the injection rate and 0.17 t/d/cycle of the production rate mean that the injection rate is Q inj = 4.32 t/d + 0.13 t/d/cycle × (2–1) cycle = 4.45 t/d and the production rate is Q pro = 5.18 t/d+ 0.17 t/d/cycle × (2–1) cycle = 5.35 t/d in the second cycle. Both VP and VR in cases (a) to (d) are obviously and consistently larger than that in the reference case due to the higher injection and production rates. The huff and puff process ceased on the 270 days in case (a) and the 195 days in case (b) due to the flow blockage caused by the formation of secondary hydrate. Under the condition of the constant-rate production (rather than the constant-pressure production method) during the production stage of a single huff and puff cycle, the wellbore pressure PW will decrease to lower than PQ after a certain number of cycles with the increasing of both (i) the sum of the produced and the injected mass and (ii) the difference of the produced and the injected mass. The main reason for the wellbore pressure PW lower than PQ at the end of the production stage (over depressurization during the constant-rate production process) or possibly exceed the Pmax after the hot brine injection is the compound cycle increase rate of both the injection and production process. Case (b) with the higher increments of the injection and production rates (compound cyclic increase rate) ceases earlier than case (a). In cases (a) and (b), the uptrends of both VP and VR maintain almost constant until the cessation of the huff and puff process, while the hydrate dissociation interface moves away from the well. And the majority of the gas produced from the well comes from CH4 dissolved in the water rather than from the hydrate dissociated gas, especially after the water from the overburden breakthrough into the initial HBL and has been produced from the well. In cases (c) and (d), the continuous decrease of the uptrend of VR over time indicates that the hydrate dissociation rate reduces with the expanding of the hydrate dissociated zone and the escaping of the gas via the overburden because of buoyancy. Obviously, both VP and VR in case (d) are consistently larger than that in case (c) due to the higher increments of the injection and production rates.

In all the cases in Fig. 19, as a relative criterion of gas production performance, the profiles of the gas-to-water ratio RGW over time indicate that the increment of the injection and production rates has a limited effect on the RGW. 7.2. Sensitivity to the existence of the impermeable overburden In Figs. 18 and 19, the effect of the existence of the impermeable overburden on VP, VR and RGW is investigated through the following two cases: case (R_ImpOver) and case (d_ImpOver). The permeabilities of the overburden in these two cases are both zero, while all the other system parameters and conditions are the same with the reference case and case (d), respectively. As assumed in this work, the hydrate accumulation in the Shenhu Area belongs to Class 3 deposits with permeable overburden and underburden layers. The existence of the impermeable overburden in case (R_ImpOver) and case (d_ImpOver) eliminate the possibilities of the fluid flow from the top layer to the HBL and the gas escaping via the overburden caused by the effect of buoyancy. Fig. 18 shows that the huff and puff process in case (d) runs over 360 days, while the corresponding case (d_ImpOver) with impermeable overburden ceased on the 265 days due to the wellbore pressure PW b PQ and the formation of secondary hydrate. The main reason for this is the absence of the water moving from the overburden to the initial HBL and producing from the well, which caused the stronger depressurization effect in both case (R_ImpOver) and case (d_ImpOver). On the other hand, the pressurization of this semi-closed system (the deposit with the upper permeability barrier and permeable lower boundary) is more intense during the hot brine injection stage. Consequently, as shown in Fig. 18, both VP and VR in these two cases are consistently larger than the corresponding reference case and case (d) respectively, and the fluctuations of VR is of larger-scope. The gas-to-water ratio RGW in Fig. 19 shows the similar characteristic with VP, which indicates the improvement of gas production with the existence of the impermeable overburden during using the huff and puff method. 7.3. Sensitivity to the existence of the impermeable boundaries In Fig. 20, the sensitivity analysis of the existence of the impermeable boundaries on VP, VR and RGW is investigated through the following cases: case (m), case (n) and case (o). The overburden and underburden in these cases are all impermeable, and the injection rates Q inj and production rates Q pro are constant in the huff and puff process in each

Fig. 20. Sensitivity analysis: effect of the impermeable overburden on VP, VR and RGW using the huff and puff method during gas production from methane hydrate deposit in this study.

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case. A symmetry deposit within the well spacing of 90 m (−45 m ≤ x ≤ 45 m) is a closed system with the impermeable upper and lower boundaries, leaving the single horizontal well as the only sink and source point. In case (m) in Fig. 20, both Q inj and Q pro are the same with that used in the reference case. Comparing with the reference case, VP, VR and RGW in case (m) are obviously higher because of the high efficiency of the huff and puff process in the closed system. However, case (m) ceased on the 35 days because of the formation of the secondary hydrate. Case (n) and case (o) ceased on the 90 days and 110 days respectively, later than that in case (m), while Q inj and Q pro gradually decrease from case (m) to (o). Because in a closed system without the fluid flow from the upper or lower boundaries, a decreasing Q inj and Q pro means a diminishing injection and production effect (pressurization and depressurization effect), leading to a moderate and persistent huff and puff process, which increase the minimum of the wellbore pressure and reduce the tendency of secondary hydrate formation. As shown in Fig. 20, the increasing slope or uptrend of both VP and VR over time in case (m) to (o) indicates that the gas production and the hydrate dissociation process accelerated over time in the closed system because of the smooth outflow of the mass in the deposit (the constant injection and production rates, and Q inj b Q pro) and the consequently increasing driving force of hydrate dissociation. In Fig. 20, after the rapid declination in the first few cycles of the huff and puff process, a local minimum of the gas-to-water ratio RGW in case (m) to (o) is reached before an increase begins at the later times of the simulation, and all these RGW are much higher than that in the reference case with permeable boundaries. In case (m) to (o), at the end points of the production process (35 days, 90 days and 110 days), VP reaches the maximum of approximate 1910, 6700 and 6930 ST m3/m of well respectively. Considering the start point (the 15 days) of the huff and puff process, the average gas production rate Qavg = VP/t in these cases is approximately 95.5, 89.3 and 72.9 ST m3/day/m of well respectively. For a well spacing of 90 m and a 1000 m well in these cases, Q avg = 1.91 × 105, 1.79 × 105, 1.46 × 105 ST m3/day (6.63, 6.21 and 5.07 million scf/D), and are all lower than the rule-of-thumb for commercially viable production rates from offshore gas wells. In addition, the limited consistent production time in these cases (with the impermeable boundaries) is another restriction of using huff and puff method with constant injection and production rates. It is possible to achieve the long term production in the deposit with the impermeable boundaries and postpone the cessation of the production process by using a decrement of Qinj and Qpro to avoid the over depressurization during the production process.

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Fig. 21. Sensitivity analysis: effect of the temperature of the injected hot brine Tinj on VP, VR and RGW using the huff and puff method (the initial injection rate Q inj = 4.32 t/d with the increment of 0.22 t/d/cycle, and the initial production rate Q pro = 5.18 t/d with the increment of 0.35 t/d/cycle) during gas production from methane hydrate deposit in this study.

7.5. Sensitivity to the existence of brine injection Fig. 22 shows the dependences of VP and VR on the existence of brine injection during the injection stage using the huff and puff method with constant injection rates (including the injection rate = 0) and production rates during gas production from methane hydrate deposit in this study. The inexistence of the hot brine injection in case (N_inj) means that the injection rate is zero and the original injection (production) well is closed during the 2 days of the injection stage, while the production period is still 3 days in this case. Comparing with the reference case, there are several special features in case (N_inj): (i) as expected, without the hot brine injection, both VP and VR are much lower because of the limited hydrate dissociation during this unusual huff and puff process. This indicates the importance of the heat stimulation in the huff and puff method.; (ii) the gas production process ceased on about the 110 days, which is caused by the over depressurization and the consequent formation of the secondary hydrate in the production stage. Although the difference of the produced and the injected mass in case (N_inj) (1.73 t/d × 3 d = 5.19 t) in a single huff and puff cycle is much smaller than that in the reference (5.18 t/ d × 3 d − 4.32 t/d × 2 d = 6.90 t), the driving force of the hydrate

7.4. Sensitivity to Tinj Fig. 21 shows the dependences of VP, VR and RGW on the temperature of the injected hot brine Tinj using the huff and puff method. In the cases shown in Fig. 21, including case (d) with Tinj = 90 °C and case (d_T) with Tinj = 150 °C, the injection rate Q inj = 4.32 t/d (initial) with the increment of 0.22 t/d/cycle while the production rate Q pro = 5.18 t/d (initial) with the increment of 0.35 t/d/cycle. By increasing Tinj from 90 °C to 150 °C, both the cumulative volume of gas produced from the well VP and the gas released from dissociated hydrate VR did not change obviously and the gas-to-water ratio RGW only increases slightly at the early time of the production process. In other words, a higher Tinj appears to have a limited effect on gas production performance by using the huff and puff method. The similar results have been concluded (Li et al., 2010b; Moridis et al., 2009c). The reason for this is that in these cases, with the limited increment of the hot brine injection rate, the range of the thermal diffusion is restricted around the well, and depressurization rather than thermal stimulation is dominant for gas production, especially at the later times of the huff and puff process.

Fig. 22. Sensitivity analysis: effect of the existence of brine injection during the injection stage on VP and VR using the huff and puff method during gas production from methane hydrate deposit in this study.

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dissociation in the production stage in case (N_inj) is much larger because of a much lower hydrate dissociation rate (leading less hydrateoriginating gas to pressurize the deposit). 7. Summary and conclusions In this work, we investigated the gas production potential from marine gas hydrate deposits at site SH7 in the Shenhu Area of the South China Sea during the China Geological Survey in 2007. From the numerical simulation results, the following conclusions are drawn: (1) Class 3 of the hydrate deposits is most likely to occur at site SH7 and may be treated as a potential production target. We investigated the various factors and issues that may affect production from them. The gas and water production from a single well placed in the middle of HBL in the deposit is the absolute criterion of the production performance, while the gasto-water ratio used as the relative criterion is important during the evaluation of the economic efficiency of the production. (2) Combining the advantages of the depressurization and thermal stimulation methods, the huff and puff method, also known as cyclic steam stimulation (CSS), is used for gas production from marine hydrate deposit with a single horizontal well in this work. The CSS used in a horizontal well in this work is known as horizontal cyclic steam (HCS). The huff and puff method used in all the cases in this work consists of 2 days hot brine injection followed by 3 days gas production, with the absence of the traditional “soaking” stage. In all the cases in this work, at the first 15 days of the whole production process, the constant-pressure production method with the driving force of ΔPW = 0.2 P0 is used to create a small cylindrical hydrate dissociated zone around the well to make it easier for the hot brine injection into the deposit during the huff and puff process. (3) Reasonable injection and production rates should be adopted during the huff and puff process. During the production stage in each cycle, to eliminate the possibility of ice formation, reasonable production rate Qpro should be selected by ensuring the wellbore pressure PW N PQ. Injection rates of each cycle Qinj should be chosen to avoid the overpressure of the deposit during the injection stage. (4) The well design used for the huff and puff production from the Class 3 deposit at SH7 in the Shenhu Area involves hot brine injection and gas/water production. Both the injected brine and the produced gas and water from the reservoir flow from the same single horizontal well, which has 8 even distributed grooves along the circumference of the well. This simple well design does not exceed current industry capabilities. (5) Based on the field measurement of the hydrate sample from site SH7 (including the temperatures at the different depths of the deposit), the local geothermal gradient, the equilibrium pressure at the base of the hydrate layer and the general tendency of hydrate deposits to follow the hydrostatic gradient, the initial conditions in the Class 3 system in this work are determined. Before the gas production process, the entire system maintains stable without any disturbance from outside. However, mild depressurization or heat stimulation will cause the destabilization of the system. (6) In all the cases in this work, the unsmooth curves of VP and the zigzag (seesaw) appearances of the curves of VR are caused by the frequent injection and production behavior during the huff and puff cycle. The cumulative volume of the produced gas VP increases monotonically in the production stage, and maintains constant during the injection of the brine. In each huff and puff cycle, VR increases over time during the production stage because of hydrate dissociation, and decreases during the injection stage caused by hydrate formation due to the mass injection induced system pressurization.

(7) In the huff and puff process with the constant injection and production rates in all the cycles, the diminishing uptrend of VR indicates that the hydrate dissociation efficiency decreases over time due to the limited range of the thermal diffusion from the injected brine, and depressurization rather than thermal stimulation is dominant for the gas production rate at the later cycles. The corresponding gas-to-water ratio RGW declines rapidly to a quite lower level which indicates that the gas production from the deposit in this work using the huff and puff method is uneconomically profitable from the relative criterion point of view. From the absolute criterion point of view, the average gas production rate Q avg is also much lower than the rule-of-thumb for commercially viable production rates from offshore gas wells. (8) In the Class 3 system, the hydrate dissociation using the huff and puff method over time is characterized by features: the evolution of a cylindrical dissociation interface around the well, the evolution of the lower dissociation interface near the base of the HBL, the emergence of the lower dissociation interface and the cylindrical interface around the well, the emergence and the evolution of the secondary hydrate near the top of the HBL, the evolution of the high-SA region and the breakthrough of the aqueous from the underburden to the cylindrical dissociated zone around the well, and the expanding of the gas accumulation area in the vicinity of the well. (9) The pressure gradients in the overburden and underburden and the inflections of the pressure distribution near the initial top and base of the HBL are caused by fluid flow in the HBL and the permeable boundaries. The temperature increase immediately below the well caused by the warmer water rising from the permeable underburden is clearly depicted by the occurrence, spatial distribution and shapes of the T distribution there. (10) In a single huff and puff cycle, as a result of the synergistic effect of the heat stimulation by the hot brine injection and the depressurization during the production stage, the hydrate dissociation occurs mostly in the vicinity of the well, especially around a cylindrical interface. The hydrate dissociated zone diminishes and enlarges slightly and continuously during the injection and production stages respectively, due to the system pressurization and depressurization conversion within a huff and puff cycle, and there is more and more secondary hydrate formed with the hot brine injection in a cycle. Furthermore, the evolution of the P and T gradients around the well over time in a cycle are obviously observed, including the continuously increasing P, T and during the injection stage and the consequently decreasing P, T due to the depressurization in the production stage. (11) In all the cases in this work, the salinity of the injected hot brine is the same with that of the water in the initial HBL. The locations of the intense dissociation activity can be identified as the low XS zone because of the dilution effect of hydrate dissociation, while the high XS zone indicates the locations of the water consuming process caused by the concentration effect of the hydrate formation in this area. The high XS zone mainly contains the area of the secondary hydrate with relative high SH above the well. (12) Sensitivity analysis of the increment of the injection and production rates indicates that both the VP and VR increase with an increasing increment of the injection and production rates, including the compound and constant cyclic increase rate, and it has a limited effect on the gas-to-water ratio. Furthermore, the huff and puff process ceases earlier with the higher increment of the injection and production rates, especially with the compound cyclic increase rate, because of the over depressurization during the constant-rate production process in a huff and puff cycle. (13) Sensitivity analysis of the existence of the impermeable overburden indicates that in a semi-closed system with the upper permeability barrier and permeable lower boundary, the effects of both pressurization during the hot brine injection and

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(14)

(15)

(16)

(17)

depressurization in the production stage are stronger than that in the deposit with permeable upper and lower boundaries. And the larger VP, VR and RGW indicate the improvement of gas production with the existence of the impermeable overburden during using the huff and puff method. Sensitivity analysis indicated that significant improvement of gas production performance, including both the absolute criterion VP, VR and the relative criterion RGW, is observed by adopting the impermeable upper and lower boundaries in a closed system. In a closed system without the fluid flow from the upper or lower boundaries, the necessity of Qinj and Qpro for gas production is much lower, and a decreasing Qinj and Qpro means a diminishing injection and production effect (pressurization and depressurization), leading to a moderate and persistent huff and puff process, which increase the minimum of the wellbore pressure and reduce the tendency of secondary hydrate formation. The Tinj sensitivity analysis indicated that a higher Tinj appears to have a limited effect on gas production performance by using huff and puff method. The reason for this is that the range of the thermal diffusion is restricted around the well, and depressurization rather than thermal stimulation is dominant for gas production, especially at the later times of the huff and puff process. By reducing the hot brine injection rate to zero during the original 2 days of the injection stage, the sensitivity analysis of the existence of brine injection is investigated. The inexistence of the hot brine injection leads to a much lower hydrate dissociation rate and the tendency of the formation of the secondary hydrate in the production stage. In general, after the sensitivity analysis by choosing various reasonable system parameters and conditions, the Class 3 hydrate deposit at site SH7 in the Shenhu Area in this work is not suitable for commercial production using the huff and puff method in this work from the point of view of both the absolute and relative criteria of production.

Nomenclature Variables C specific heat (J/kg/K) f safety factor g gravity (m/s2) k intrinsic permeability (m2) keff effective permeability (m2) kΘ thermal conductivity (W/m/K) kΘRD thermal conductivity of dry porous medium (W/m/K) kΘRw thermal conductivity of fully saturated porous medium (W/ m/K) kΘI thermal conductivity of ice (W/m/K) MW cumulative mass of the produced water (kg) P pressure (Pa) PB initial pressure at base of HBL (Pa) Pmax maximum of the wellbore pressure (Pa) P0 initial pressure in the middle of HBL (Pa) PW pressure at the well (Pa) Q avg average gas production rate (ST m3/d) Q inj injection rate in each cycle of the huff and puff process (t/d) Q pro production rate in each cycle of the huff and puff process (t/d) RGW the gas-to-water ratio (ST m3 of CH4/m3 of H2O) R radius (m) S phase saturation t times (days) T temperature (°C) TB initial temperature at base of HBL (°C) Tinj temperature of the injected brine (°C) T0 initial temperature in the middle of HBL (°C) VP cumulative volume of the produced CH4 (ST m3)

VR

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x,y,z ΔPW ΔZ ΔZsf ΔZwd ΔZH ΔZO ΔZU ΔZW ϕ ρw ρs ρR λ

cumulative volume of hydrate-originating CH4 released in the reservoir (ST m3) cartesian coordinates (m) driving force of depressurization, P0 − PW (Pa) discretization along the z-axis (m) water depth of the seafloor (m) well depth below the seafloor (m) HBL thickness (m) overburden thickness (m) underburden thickness (m) well position above the HBL base (m) porosity typical density of the ocean water (kg/m3) typical density of the deposit (kg/m3) grain density (kg/m3) van Genuchten exponent — Table 1

Subcripts 0 A B cap e G H I irA irG n nG O P R S U W

denotes initial state aqueous phase base of HBL capillary equilibrium conditions gas phase solid hydrate phase ice phase irreducible aqueous phase irreducible gas permeability reduction exponent — Table 1 gas permeability reduction exponent — Table 1 overburden production stream rock salinity underburden well

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