Effect of wellbore design on the production behaviour of methane hydrate-bearing sediments induced by depressurization

Applied Energy 254 (2019) 113635

Contents lists available at ScienceDirect

Applied Energy journal homepage: www.elsevier.com/locate/apenergy

Effect of wellbore design on the production behaviour of methane hydratebearing sediments induced by depressurization

T

Zhenyuan Yina,b, Li Huangc,d, , Praveen Lingaa, ⁎

⁎

a

Department of Chemical and Biomolecular Engineering, National University of Singapore, Singapore 117582, Singapore Lloyd’s Register Singapore Pte. Ltd., Singapore 138522, Singapore c The Key Laboratory of Gas Hydrate, Ministry of Natural Resources, Qingdao Institute of Marine Geology, Qingdao 266071, China d Laboratory for Marine Mineral Resources, Qingdao National Laboratory for Marine Science and Technology, Qingdao 266071, China b

HIGHLIGHTS

different wellbore designs are employed in production from hydrate-bearing sediments. • Five gas production and step-wise water production are observed at all pressures. • Continuous design offers better control of water production than bore-hole design. • Slotted-liner • Partial perforation and perforation location affect water production more than gas production. ARTICLE INFO

ABSTRACT

Keywords: Wellbore design Hydrate-bearing sediments Energy recovery Depressurization Production behaviour Slotted-liner

Methane hydrates have been considered as the future clean energy resource. To recover energy from hydratebearing sediments safely and effectively requires a fundamental understanding of the dynamic behaviour of hydrates in sandy media. Past field production tests have proved the technical feasibility of gas production from hydrate reservoirs. However, technical challenges (e.g. sand production and excessive water production) remain in realizing long-term economic-viable production. In this study, we investigate the effect of various wellbore designs (specifically the shape and the location of perforations) on the fluid production behaviour in aqueousrich hydrate-bearing sediments. Slotted-liner design was first-time incorporated in depressurization under different bottom-hole pressures (2.5 MPa, 3.0 MPa and 4.0 MPa). Continuous gas production and step-wise water production during the early stage of depressurization were observed at all pressures because of the change of fluid flow path from reservoir to wellbore. Compared with traditional borehole design, slotted-liner design showed advantage in controlling water production under low BHP (2.5 MPa). Using wellbores with different perforation locations, it was observed that perforation location does not pose a significant impact on the behaviour of gas production; whereas, middle perforation away from the aqueous-rich and hydrate-rich region yielded the least water production. The experimental results from this study demonstrated the possibility of employing slotted-liner well and varying the perforation location in reducing water production from methane hydrate-bearing sediments. Our findings can pave way for the testing of novel wellbore designs to further enhance gas recovery and reduce water production from hydrate reservoirs.

1. Introduction Methane hydrates (MHs) are solid crystalline compounds, which consist of cages of water molecules trapping the (guest) gas molecule [1]. They are stable at favourable conditions of low temperature T and high pressure P within the hydrate stability region [2]. MH-bearing sediments (MHBS) are widely distributed in nature at permafrost

locations and below the seafloor near the continental margin [3]. Energy recovery from MHBS has attracted intensifying research interests around the world due to the abundance of resource volume (3,000 trilling cubic meter of CH4 [4]) and the capability of MH storing CH4 efficiently (170 vCH4/vH2O [5]). Recent field production tests at Japan Eastern Nankai Trough [6] and China Shenhu Area, South China Sea [7] have proved the technical feasibility of producing gas from hydrate

⁎ Corresponding authors at: Department of Chemical and Biomolecular Engineering, National University of Singapore, Singapore 117582, Singapore (P. Linga); The Key Laboratory of Gas Hydrate, Ministry of Natural Resources, Qingdao Institute of Marine Geology, Qingdao 266071, China (L. Huang). E-mail addresses: [email protected] (L. Huang), [email protected] (P. Linga).

https://doi.org/10.1016/j.apenergy.2019.113635 Received 3 May 2019; Received in revised form 11 July 2019; Accepted 30 July 2019 0306-2619/ © 2019 Elsevier Ltd. All rights reserved.

Applied Energy 254 (2019) 113635

Z. Yin, et al.

reservoir. However, technical challenges remain in the field (i.e. unpredictable sand production and excessive water production [8]), which hinders the rate of gas production and the economic viability of the long-term production. Thus, it is critically important to develop and test various production technologies (e.g. well completion, wellbore design, and sand control device) to improve the gas-liquid seperation efficiency and to sustain a high gas production rate with a high gas recovery in order to realize a long-term economic-viable production [9]. Investigation of MH dissociation and the associated fluid production behaviour from MHBS in laboratory is necessitated by the scarcity of the hydrate core samples extracted from the field [8] and the long duration and the high cost involved in the drilling and coring programs and the production tests (e.g. the Mallik site in Canada [10], the Nankai Trough in Japan [6] and the Shenhua Area at South China Sea [7]). Unlike a field production test, where the production conditions cannot be controlled conveniently, investigation of production behaviour from MHBS in laboratory offers a unique controlled environment for hydrate dissociation. A few studies have incorporated wellbores within the hydrate-bearing sediments with the aim of promoting hydrate dissociation and enhancing gas recovery [11–14] in addition to testing the classical hydrate dissociation methods (i.e. thermal stimulation [15], depressurization [16], injection of hydrate inhibitors [17], and the combination of the above [18]). Loh et al. [19] employed a dual wellbore system in a V = 5.6 L reactor to investigate the gas production from a laboratory synthesized hydrate-bearing sediments using a combination of depressurization and heating method. Their results indicated that heating of the wellbore can enhance the gas recovery, however the production behaviour of water was not discussed explicitly in their paper, which is also an important factor in hydrate dissociation experiment. Feng et al. [11] compared the performance of vertical and horizontal well (with four slots) on the gas production performance in a V = 117.8 L reactor. However, the hydrate-bearing samples synthesized in their experiment yielded low hydrate saturation SH (~0.28) and had high gas saturation SG (~0.51). Such sample is not representative of the actual phase saturations of oceanic hydrate-bearing sediments identified at marine locations [20,21]. Konno et al. [14] studied the effect of different depressurization scheme using a vertical wellbore (with boreholes) on the gas production behaviour of an artificial sample with high SH (~0.64) in a V = 1710 L reactor. Their results suggested that depressurizing at a low bottom-hole pressure (BHP) below the quadruple point of MH resulted in a high gas recovery ratio. Recent experiments by Chong et al. [12,13], which incorporated a horizontal wellbore and a vertical wellbore during the depressurization of MH-bearing sediments showed improvements on the cumulative gas production and reductions in the cumulative water production compared with a point dissociation method [22]. So far, majority of the experimental studies have focused on the effect of dissociation conditions (i.e. P and T) on the fluid production behaviour, while less is known on the effect of various types of wellbore design and completion (e.g. open-hole, slotted-liner, perforated holes, gravel packed well, etc.) on the production behaviour. Frequently, radial flow to a vertical well results in increasingly higher flow velocity near the well and different borehole designs could introduce different pressure differences and flow regimes, thus affecting the overall production behaviour from hydrate-bearing sediments [23]. For example, the slotted-liner design offers advantages over the perforated-holes in terms of sand control and wellbore stability [24]. Thus, the application of such type of cost-effective wellbore is desired especially in the context of production from hydrate-bearing sediments, where the geomechanical stability of the hydrate region is uncertain [8]. In fact, during the China’s first methane hydrate production test in 2017, modifications of the wellbore design with enlarged borehole and gravel packing have proven to be a robust and cost-effective solution to enhance the gas production performance in the vertical well [7].

Another aspect related to the design of wellbore is the partial completion (or perforation), which is also common in the petroleum production system as a result of a bad perforation job or poor gravel pack placement [25]. The producing height that is open to the hydratebearing sediments is typically smaller than the reservoir height in a partial completion scenario and is located at different sections of the wellbore to avoid possible water coning. During the 2013 Japan 1st hydrate field test at Nankai Trough, the perforation interval was selected to be the top 38.0 m out of the total 53.0 m hydrate concentrated interval because of the aquifer located at the bottom of hydrate region [26]. Similar partial perforation was also reported in the 2nd offshore oceanic hydrate field test for well P2 and P3 at Eastern Nankai Trough in 2017 [27]. While partial perforation reduces the well exposure to the reservoir, the effect of such completion on the productivity of vertical wells involving hydrate-bearing sediments has not been well investigated so far. Based on the limitations identified from the above literature and in view of the potential challenges likely to be encountered in a field production test, we designed experiments in this study to simulate the MH dissociation process induced by depressurization using five different wellbore designs with the following objectives: (a) to access the fluid production performance using a vertical wellbore with slottedliner (hereafter denoted as SL) design under different BHPs; (b) to compare the fluid production performance between the SL design and a borehole (hereafter denoted as BH) design to identify (possibility) the superiority of the two; and (c) the effect of different perforation intervals on the fluid production. In all experiments, we repeatedly synthesized aqueous-rich MHBS using the excess-water technique targeting at the same phase saturations (SH = 0.42, SA = 0.56 and SG = 0.02) to control the only changing variable in the study is the design of wellbore. The formation and dissociation steps in all experiments were analysed and quantified in detail, which provided the evolution of all phase saturations over time and the cumulative fluid production with their recovery percentage. The results from this study offer important insights into the optimal design of the production well involving hydrate-bearing sediments, which can improve the recovery of gas and energy efficiency in both experiments and (possibly) field applications. 2. Experimental section 2.1. Materials Pure methane gas (99.9%) supplied by Air Liquide Singapore Pte. Ltd. and deionized water were used to synthesize the MH core samples. The sandy medium was unconsolidated silica sand with particle size ranging from 0.10 to 0.60 mm (D50 = 0.25 mm) supplied by River Sands Pty Ltd. Fig. S2 in the Supporting Information shows the particle size distribution of the sandy medium used in this study. The D50 of the fine sands was slightly larger than the D50 identified in the natural core samples extracted from Nankai Trough, Japan (D50 = ~0.10 mm) [28] and Krishna Godavari Basin, India (D50 = ~0.05 mm) [20]. The density of the sands was 2.65 g/cm3. The porosity (ϕ) was 0.44 with absolute permeability k = 3.8 Darcy from the mercury porosimetry test. 2.2. Experimental apparatus Fig. 1 shows the schematic of the experimental apparatus. It consisted of two major components: (a) a cylindrical reactor (V = 0.98 L) made from SS316 stainless steel with maximum working pressure, Pmax = 10.0 MPa; and (b) a fluid production system consisting of a V = 0.40 L gas–liquid separator (GLS) and a V = 1.0 L gas reservoir (GR). The dimension of the reactor has been reported in our previous studies [22,29–31] and a schematic is shown in Fig. 2. The reactor was thermally insulated from the surrounding by one layer of insulation foam. Two T-type 6-point thermocouples ( ± 0.1 °C) were installed at 2

Applied Energy 254 (2019) 113635

Z. Yin, et al.

Fig. 1. Schematic of the experimental apparatus for MH formation and dissociation experiments.

two different locations (see Fig. 2) to acquire temperatures. Two Rosemount SMART pressure transmitters ( ± 20 kPa) were installed at positions Ptop and Pbot (see Fig. 1) to acquire pressures. Temperature of the reactor and the injected water was controlled by two PolyScience 15.0 L circulating refrigerated chillers (RC1 and RC2 in Fig. 1). Water injection was conducted using the Teledyne ISCO 500D syringe pump via valve V2 (see Fig. 1). During depressurization, the bottom-hole pressure (BHP) was controlled by a Fisher-Baumann control valve with a PID controller (OMEGA CN2120). The gas-liquid flow was separated in the GLS. Water was collected with the mass measured by a precision balance ( ± 0.1 g, model KERN 572-57). Produced CH4 accumulated in the interconnected GR and GLS. A vacuum pump (brand Vacuubrand MZ-2C-NT) was used

to ensure that GR and GLS were at the vacuum state before depressurization. One pressure transmitter (PGR) was equipped to measure the pressure of the GR to quantify the amount of produced gas. All the connecting lines was ¼ inch O.D. stainless steel tubes provided by Swagelok. Data acquisition system integrated with LabView 2017 software from National Instruments was used to record the experimental data on a personal computer with a user-defined frequency. 2.3. Configuration of wellbore Fig. 3 shows the configurations of the five different vertical wellbore designs used in this study. All wellbores were stainless steel tubes located at the centre of the reactor with the same internal diameter

4.6 mm

25 mm

Pressure outlet

Tb1

31 mm

Ta1

20 mm 20 mm

Tb2

Ta2

Cooling jacket

Tb3 Ta3

120 mm Tb4

Ta4

90 mm

Production well

Tb5

38 mm

25 mm

Ta5

Tb6

Thermocouple

Ta6

25 mm

15 mm

102 mm 5 mm

SS316 Reactor

132 mm

Fig. 2. Schematic of the cross-section view of the reactor showing the dimension of the reactor, the position of the vertical wellbore, and the position of the two 6point thermocouples. 3

Applied Energy 254 (2019) 113635

Z. Yin, et al.

wellbore, respectively (see Fig. 3c, d and e). It should be noted that all wellbores were covered by one layer of stainless-steel mesh (No. 200) to prevent sand production. Table 1 lists the dimension of the wellbores with a picture showing all five wellbores in Fig. S1 in the supporting information. 2.4. Experimental procedure 2.4.1. MH formation The experimental procedure to form aqueous-rich MHBS via the excess-water method has been discussed and numerically analysed in our previous studies [22,29–31]. In brief, 1469.4 g quartz sand was tightly packed in the reactor before sealing it off. The effective volume of the reactor excluding the volume of the wellbore was 0.97 L. The resulting porosity of the sandy medium (ρsand = 2.65 g/cm3) inside reactor was 43.1%. Subsequently, the reactor and the connecting tubing were purged with CH4 to a pressure of 1.0 MPa three times to remove the residual air. Gas injection was carried out from valve Vbot (see Fig. 1) to a pressure of 6.7 MPa and allowed to stabilize at T = 15.0 °C for t = 1.0 hrs. Deionized water was injected into the reactor from valve V2 (see Fig. 1) at a rate of QW = 30 mL/min for t = 5.7 min to pressurize the reactor to P = 9.6 MPa. Another t = 2.0 hr was allowed for the aqueous and gas phase to homogenize within the sediments. Temperature of the circulating water (RC1) was adjusted down from T = 15.0 °C to 1.0 °C to induce MH formation. Rapid MH nucleation and formation events can be identified from the response of T and P typical of MH formation (i.e. drastic pressure drop and sudden increase in temperature). The 2nd water injection was conducted after P stabilized at Peq = 3.1 MPa at T = 1.0 °C. Deionized water at a rate of QW = 30 mL/ min was injected for t = 7.2 min to pressurize the system back to P = 9.5 MPa. The objective was to (a) increase the driving force for MH formation; (b) to convert majority of CH4 gas into MH; and (c) to create an aqueous-rich environment for the hydrate-bearing sediments. It should be noted that T of the injected water was strictly controlled below T = 6.0 °C via the circulating chiller (RC2) in order not to destabilize the MH that has been formed from our earlier numeral analysis

Fig. 3. Schematic of the configurations of the five different vertical wellbore designs: (a) single-inline slotted-liner design; (b) borehole design; (c) borehole design at top section; (d) borehole design at middle section; and (e) borehole design at bottom section.

rw = 4.6 mm (see Fig. 1). Both slotted-liner (SL) design and borehole (BH) design have the same perforation interval h = 90.0 mm but different geometry of perforations. SL design consists of 36 single vertical in-line liners with w = 1.5 mm and l = 10.0 mm (see Fig. 3a). BH design consists of 108 round-shape perforations (6 holes per 5.0 mm) with diameter Dh = 2.5 mm (see Fig. 3b). Three other wells BH-top, BH-mid, and BH-bot have the same round shape perforations as the BH design and a shorter perforation interval h = 30.0 mm. They vary in the location of the perforations, which are at the upper section 0–30.0 mm, middle section 30.0–60.0 mm, and lower section 60.0–90.0 mm of the

Table 1 Summary of the dimension, number, and the type of perforations in the two different types of vertical wellbore.

4

Applied Energy 254 (2019) 113635

Z. Yin, et al.

Table 2 Summary of the experimental conditions and the estimated saturations of various phases at the end of the formation of MH-bearing sediments. Exp No.

PCH4 (MPa)

nCH4 (mol)

VH2O (mL)

nH2O (mol)

Final Pavg (MPa)

Final Tavg (°C)

XCH4 (%)

SH (%)

SA (%)

SG (%)

tf (hr)

SL-a SL-b SL-c BH-a BH-b BH-c BH-Top BH-Mid BH-Bot

6.71 6.74 6.74 6.68 6.74 6.69 6.74 6.74 6.71

1.46 1.47 1.47 1.46 1.47 1.46 1.47 1.47 1.46

388.0 384.3 387.5 386.0 385.0 385.5 391.0 394.5 391.0

21.59 21.39 21.57 21.49 21.43 21.46 21.77 21.96 21.77

5.86 5.95 6.25 6.63 6.30 5.71 6.50 6.52 6.78

6.38 6.30 6.28 6.41 6.26 6.19 6.28 6.24 6.29

98.44 94.97 95.58 94.75 94.96 95.66 96.15 97.04 95.86

44.05 42.21 42.46 41.77 42.16 42.17 42.71 43.00 42.37

54.23 52.30 52.90 53.18 52.57 52.78 53.48 54.04 53.74

1.72 5.48 4.63 5.05 5.27 5.05 3.81 2.97 3.88

100.1 101.0 104.6 108.5 111.2 100.3 101.3 102.5 105.3

(5)

of the process [31]. The total amount of gas and water injected during each step were recorded and listed in Table 2 for all experiments. When the pressure plateaued at P = ~6.0 MPa with ΔP/ Δt < 10 kPa/hr, T of the system was increased step-wise from T = 1.0 °C to T = 6.0 °C, which corresponded to the T at ~ 100 m below seafloor assuming a seafloor temperature of 2.2 °C and a geothermal gradient of 4.3 °C/km [21,32]. When P and T stabilized at their final desired set point (P = ~6.0 MPa and T = ~6.0 °C), MH formation was deemed completed. In all the experiments, the time taken for the MH formation process was ~100.0 hr. All the data of P and T were recorded with a frequency of 20.0 s.

nMH = Xgas × ngas, init

2.4.2. MH dissociation The dissociation of MH was induced by depressurization through the vertical wellbores under three different constant back-pressure modes (BHP = 4.0 MPa, 3.0 MPa and 2.5 MPa). Valve Vbot was first closed before the start of depressurization. The depressurization was initiated by slowly open valve V3 while maintaining a constant backpressure through the control valve (CV see Fig. 1). In this study, the set point of CV was considered the same as the BHP within the vertical wellbore because of the negligible pressure drop in the short connection tubing. The percentage opening of the CV was controlled by the attached PID controller to ensure a constant BHP throughout the depressurization stage. During the depressurization stage, temperature of the circulating water (RC1) was maintained at 6.0 °C. The time taken for the cumulative fluid production to stabilize varied between 2.0 and 10.0 hrs depending on the different BHPs implemented. All the data of P, T, and the mass of water were recorded with a frequency of 10.0 s.

Si = Vi / Vpore = ni i / Vpore

where Xgas represents the conversation of CH4 into MH. The molar density of water and MH can be used as constant with values of 18.0 cm3/mol and 136.7 cm3/mol [35] because of their week dependence on P and T. The molar density of gas (100% CH4) was estimated based on the measured P and T using the Peng-Robinson (PR) equation of state (EOS) due to the non-ideality of CH4 under high pressure (3.0 MPa < P < 9.6 MPa). Xgas can be estimated by solving the coupled Eqs. (2)–(5) numerically (using Matlab 2018b). Accordingly, phase saturation can be estimated based on the volume fraction of each phase as

2.5.2. Quantifying fluid production and phase saturations during MH dissociation The cumulative production water (MW) was measured by the weighing balance. The cumulative production of gas (VG) was estimated based on the time-series data of PGR and the volume of the produced gas (Vgas). Vgas equals the summation of the effective volume in GLS and the volume of GR (Vgas = VGLS − VW + VGR). The compressibility factor of the produced gas (z) was estimated based on the measured P and T using the PR-EOS discussed earlier. The amount of gas and water that were produced from the reactor can be estimated as follows

n water , P = (m water , P

WGR =

gas

+ n water

water

+ nMH

nMH = nMH , F

NH × Xgas × ngas, init

(10)

ngas, P

(11)

n water , P

(12)

nMH , D th

where ni,F represents the number of mole of the i phase at the end of MH formation, nMH,D represents the number of mole of MH that has dissociated, and ngas,P and nwater,P represents the number of mole of gas and water that has been produced from the reactor. nMH,D can be estimated by combining Eqs. (2) and (10)–(12) using the measured timeseries data of P and T. It should be noted that the phase saturation estimated using this method is only representative of the average phase saturation, where no spatial distribution is accounted for. The spatial distribution of phase

MH

where ni represents the number of mole and ρi represents the molar density of the ith phase (i = gas, water, and MH). ni can be further expressed in Eqs. (3)–(5),

n water = n water , init

(9)

n water = n water , F + NH × nMH , D

(2)

Xgas )

(8)

n water , P ngas, P

ngas = ngas, F + nMH , D

with an average hydration number NH = 6.0 assumed [34]. The pore-volume balance equation is presented as

ngas = ngas, init (1

PGR, init Vgas, init / zRTinit

which is a key parameter for the evaluation of gas production from hydrate reservoir. The same pore-volume balance Eq. (2) holds true during MH dissociation, but ni are described differently in Eqs. (10)–(12) during dissociation,

(1)

CH4 · NH H2 O

= Vgas + Vwater + VMH = ngas

(7)

Based on the nwater,P and ngas,P, water gas ratio (WGR) can also be estimated as

2.5.1. Quantifying phase saturations during MH formation To quantify the phase saturation of all phases (SA, SH and SG), we used the pore-volume balance method, which has been discussed in detail in our earlier study of MH formation [33]. The advantage over the traditional gas-uptake method is that the change of the gas phase volume during MH formation is fully accounted for. The equations for the pore-volume balance method are summarized as follows: The reaction of MH formation is expressed as

Vpore = Vr ×

water

m water , init )/

ngas, P = PGR Vgas/ zRTavg

2.5. Methods of calculation

CH4 + NH H2 O

(6)

(3) (4) 5

Applied Energy 254 (2019) 113635

Z. Yin, et al.

10

1st water

D injection

F

9 8

P (MPa)

20

Ptop Pbot PGR

2nd water injection

Tmax 18 Tmin Tavg 16 14

7

2nd MH formation

6

H

12

End of MH formation

I 8

Cooling

4

10

Depressurization

1st MH formation

5

E

3 2

6

MH dissociation

Temperature peak

4

1

2

Gas production

A

0 0

20

40

60

T (oC)

11

80

100

120

140

160

0

Time (hr) Fig. 5. Evolution of experimental measured pressure (Ptop, Pbot and PSV) and temperature (Tmax, Tmin and Tavg) over time during MH formation and dissociation processes in experiment SL-a. Letters indicating the end of each process are in accordance with Fig. 4.

Fig. 4. Trajectory of the experimental measured Pavg and Tavg during MH formation (in red line) and dissociation (in blue line) in relation to the MH equilibrium curve in experiment SL-a.

combination effect of the circulating water and the ambient surrounding.

saturation can only be determined by advanced instrumental techniques with the capability of in-situ phase visualization (e.g. X-ray Computer Tomography [36,37], Magnetic Resonance Imaging [38] or Electrical Resistivity Tomography [39], etc.). In the absence of direct visualization technique, numerical analysis of experimental results using the state-of-the-art simulator (e.g. T + H [40,41]) could also provide high-resolution spatial distributions of phase saturations [30,31]. In our earlier study on the importance of the heterogeneity on the production behaviour [42], we have demonstrated that gas production behaviour is not sensitive to the assumption of phase uniformity. Thus, in this study, we consider the estimated average phase saturation a good representation of the hydrate-bearing system.

3.2. Evolution of P and T during MH formation and dissociation Fig. 5 shows the evolution of P (Ptop, Pbot and PGR) and T (Tmin, Tmax and Tavg) during the MH formation and dissociation processes. Injection of gas and water (A → D) resulted in P increase from P = 0.1 MPa to 9.5 MPa at T = 15.0 °C. The cooling from the reactor boundary from 15.0 °C to 1.0 °C induced a rapid MH formation (D → E), which is evidenced by the fast pressure drop from 9.5 MPa to 3.1 MPa (MH Peq at T = 1.0 °C) within 20.0 hrs. The pressure difference between Ptop and Pbot was not discernible, which suggested a good hydraulic connectivity within the MH-bearing sediments vertically. Multiple temperature peaks were observed at t = 10.0 hr and 18.0 hr, which indicated both primary and secondary exothermic MH formation events. The 1st MH formation process is deemed to complete when P and T stabilized to their final levels (Pavg = 3.1 MPa, Tavg = 1.5 °C) with no driving force for the MH formation reaction. The 2nd water injection (E → F in Fig. 5) resulted in a significant increase in P and provided further driving force for MH formation. This is evidenced by the slow but continuous P drop from P = 9.5 MPa to P = 6.6 MPa (F → H in Fig. 5). Interestingly, Ptop decreased faster and started to deviate from Pbot from t = 70.0 hr towards the end with a maximum deviation (ΔP = Pbot − Ptop) of 0.7 MPa. This can be attributed to the heterogeneity of SH inside the synthesized MHBS, which resulted in a permeability reduction near the bottom section of the reactor and isolated the reactor from the bottom connecting tube. Similar behaviour was also observed by Kumar et al. [45] in their experiments when SH > 0.35. The 2nd MH formation process lasted for t = ~76.0 hr with P approaching asymptotically to its final level. This can be attributed to the increasing mass transfer resistance caused by the decreased volume of the free gas (SG < 0.05) in the pore space [46]. During the depressurization stage (H → I in Fig. 5), Ptop decreased rapidly from P = 6.5 MPa to P = 4.0 MPa and maintained constant. PGR kept increasing because of gas production. All the measured T decreased drastically upon the start of depressurization due to the endothermic nature of MH dissociation (ΔH = 56.9 kJ/mol [47]). After reaching the minimum T at all positions, T gradually increased back and stabilized at different levels depending on the monitoring position. It should be noted that generally Tmax represented the T at the upper section of the reactor (locations of Ta1 and Tb1 in Fig. 2), while Tmin

3. Results and discussion 3.1. P-T trajectory during MH formation and dissociation Fig. 4 shows the typical evolution of Pavg and Tavg during MH formation (A → H) and MH dissociation (H → I) in our experiments. Injection of gas (A → B) and water (C → D) increased the system P to the desired setpoint P = 9.6 MPa. The cooling from 15.0 °C to 1.0 °C induced a rapid MH formation (D → E), which was evidenced by the decrease of P from 9.5 MPa to 3.1 MPa (MH Peq at T = 1.0 °C). It is interesting to notice that MH did not form immediately after entering the MH stability zone due to the metastability region of MH [43]. Similar behaviour where the onset temperature of MH formation is lower than the equilibrium temperature was also reported in a number of MH formation experiments [44]. The 2nd water injection step resulted in a significant increase in P (E → F) and provided further driving force for the 2nd stage of MH formation. During this stage, P dropped from P = 9.5 MPa to P = 6.6 MPa (F → G). Increasing T from 1.0 °C to 6.0 °C within the MH stability region (G → H) did not pose a significant impact on the response of P (P maintained at 6.6 MPa). This indicates that MH was stable within the stability region and only the solubility of gas was affected during this stage from the analysis of Yin et al. [31]. MH dissociation was induced by depressurization (H → I) from P = 6.6 MPa to P = 4.0 MPa, the Pavg-Tavg trajectory did not coincide with the Peq-Teq curve with Tavg slightly higher than Teq. This was attributed to the heterogeneity of the MH-bearing sediments and the hydrate dissociation at non-equilibrium condition. Tavg increased from Tmin = 4.2 °C to 6.5 °C (Point I) at constant P = 4.0 MPa under the 6

Applied Energy 254 (2019) 113635

Z. Yin, et al.

the decrease in the driving force of MH formation over time, which is defined as the fugacity difference between the gas phase (fg) and the equilibrium (feq) based on the kinetic model of Clarke and Bishnoi [49]. The 2nd water injection lasted t = 7.3 mins and resulted in a significant increase in the system pressure and subsequently the driving force (Δf = fCH4 − feq) for MH formation. It is observed in Fig. 6b that XCH4 increased drastically from 0.73 to 0.93 (see the small panel in Fig. 6b) with SH increasing from 0.33 to 0.41 (see the small panel in Fig. 6a) during this relatively short period. The injected water also boosted SA from 0.12 to 0.54, yielding an excess-water condition for the MHBS. SG decreased linearly over time from 0.55 to 0.04 due to: (a) the consumption of CH4 for MH formation; and (b) the dissolution of CH4 into the injected H2O. During the 2nd stage of MH formation spanning from t = 24.0 hr to 100.0 hr, MH continued to form but at a very slow and attenuated rate (ΔSH/Δt = 0.0003/hr) because of the relatively small amount of CH4 left for the formation reaction and the associated high mass transfer resistance in the system [46]. At the end of the 2nd MH formation, the phase saturations were SH = 0.43, SA = 0.53, and SG = 0.04 with XCH4 = 0.97. The phase saturations for all nine experiments after MH formation were listed in Table 2 and shown in Fig. 7. 3.4. Effect of BHP using slotted-liner design The effect of BHP on the production behaviour using one type of vertical borehole design has been investigated by Chong et al. [12]. The production behaviour using vertical wellbore with a slotted-liner design under different BHPs has not been investigated yet and is of particular interest in this study. Fig. 8 presents the evolution of Ptop and the cumulative production of fluid during depressurization under BHPs = 2.5 MPa, 3.0 MPa and 4.0 MPa. It can be observed that BHP decreased in a step-wise manner and maintained practically constant during the entire MH dissociation experiments in Fig. 8a. The depressurization stage was relatively fast and the pressure draw down completed within 2.0 mins in all experiments. Decreasing BHP significantly increased the rate of VG and the final volume of VG produced in Fig. 8b. Consequently, the final gas recovery ratio Rgas increased significantly from Rgas = 0.77 to Rgas = 0.91 when decreasing BHP from 4.0 MPa to 2.5 MPa. This can be attributed to the higher driving force Δf induced for MH dissociation when lowering the BHP based on the kinetic rate equation of Kim et al. [50]. Earlier sensitivity study has found that in a relative small-scale reactor, kinetic rate of hydrate dissociation is the dominating factor controlling the gas production [42]. Thus, decreasing BHP provides a higher driving force for the hydrate dissociation reaction and can be one effective method to

Fig. 6. Evolution of (1) phase saturation of SH, SA and SG; and (b) conversion of CH4 to MH during the MH formation process estimated by the pore-volume balance method in SL-a.

represented that at the middle section of the reactor (locations of Ta4 and Tb4 in Fig. 2). A temperature difference between Tmax and Tmin (ΔT = 1.0 °C) persisted during the entire MH formation and dissociation. This can be attributed to the location of the circulating refrigerant (see Fig. 2) and the imperfect insulation of the reactor, especially near the top boundary. The temperature gradient inside the reactor was also the major contribution to the spatial heterogeneity of SH as numerically analysed in the earlier study of Yin et al. [33] on MH formation in the same sandy medium. 3.3. Evolution of phase saturation during MH formation Fig. 6 presents the evolution of the phase saturations and the conversion of CH4 to MH during the MH formation process. The initial phase saturations of the system are SA = 0.38 and SG = 0.62. During the 1st stage of MH formation, SH and XCH4 did not increase until t = 3.8 hr, which can be attributed to the gas dissolution stage [48] outside the MH stability region and the metastability zone inside the MH stability region [33]. Rapid MH formation was marked by a sharp increase in SH (ΔSH/Δt = 0.017/hr) and plateaued to its final level SH = 0.33 at t = 23.8 hr. Consequently, both SA and SG decreased in the opposite trend of SH. At the end of the 1st MH formation, SG decreased from 0.62 to 0.55 and SA decreased from 0.38 to 0.12 with XCH4 = 0.73. From the slope of the SH curve, it is found that the rate of MH formation is largest at the start and gradually decreased over time. This can be attributed to

Fig. 7. Summary of phase saturations of gas, aqueous and hydrate at the end of MH formation in all experiments. 7

Applied Energy 254 (2019) 113635

Z. Yin, et al.

Fig. 9. Evolution of phase saturation of aqueous, gas, and hydrate in reactor using vertical wellbore with slotted-liner design under BHP = 4.0 MPa (SL-a), 3.0 MPa (SL-b), and 2.5 MPa (SL-c).

within the wellbore. It is interesting to note that MW did not follow a clear trend with BHP as VG, which can possibly due to the heterogeneity of various phases in the synthetic MH-bearing samples in the laboratory. Yet, as expected decreasing BHP from 4.0 MPa to 3.0 MPa increased the final mass of MW. Compared with the experiments under the same BHP = 4.0 MPa in the study of Chong et al. [12,13] using a wellbore with borehole design, MW in the slotted-liner design decreased by 30.0% suggesting the superiority of slotted-liner design in preventing water production from the hydrate-bearing samples. Fig. 9 shows the evolution of the phase saturations of all phases (SH, SA and SG) in the reactor during depressurization estimated by the porevolume balance method. In all cases, SH decreased continuously from its starting level and approached asymptotically to 0 at the end of hydrate dissociation. Comparing between different cases in Fig. 9a, it is evident that decreasing BHP significantly increased the rate of hydrate dissociation and decreased the hydrate dissociation time with reasons analysed earlier. The time used for half of the MH to dissociate (t50,H) are summarized in Table 3, which reduced from 72.0 min to 24.0 min to 19.4 min when the BHP is decreased from 4.0 MPa to 3.0 MPa to 2.5 MPa. SA in the reactor decreased drastically upon the start of depressurization due to the fast drainage of water from the reactor (see Fig. 9b) during this period. The aqueous-rich environment promoted the production of water over gas due to the high relative permeability. After SA

Fig. 8. Summary of (a) evolution of Ptop (same as BHP) over time; (b) cumulative production of gas, VG; and (c) cumulative production of water, MW using slotted-linear design wellbore under BHP = 4.0 MPa (SL-a), 3.0 MPa (SL-b), and 2.5 MPa (SL-c).

increase the rate of VG. Fig. 8c presents the cumulative production of water, MW under different BHPs. Contrary to continuous production of VG, the production of water followed practically a step-increase trend over time and in the opposite trend of Ptop. MW started to increase drastically upon the start of depressurization and the produced water continued at a high rate for ~1.5 hrs before it plateaued to its final level. In addition, fast depressurization favours an initial quick water production as shown in the small panel in Fig. 8c. This can be attributed to two main reasons: (a) the excess-water environment (SA = 0.60) of the hydrate-bearing sediments, and (b) the incorporation of the slotted-liner vertical wellbore, which altered the flow path of the gas-liquid two phase flow 8

Applied Energy 254 (2019) 113635

Z. Yin, et al.

Table 3 Summary of the experimental conditions and the associated cumulative fluid production during the depressurization experiments in the presence of different configurations of wellbore. Exp No.

Wellbore Configuration

BHP (MPa)

Final PGR (MPa)

nG (mol)

RG (%)

Final QW (g)

nW (mol)

RW (%)

Water Gas Ratio (mol/mol)

t50,G (min)

t50,W (min)

t50,H (min)

SL-a SL-b SL-c BH-a BH-b BH-c BH-top BH-mid

Slotted-Liner Slotted-Liner Slotted-Liner Borehole Borehole Borehole Borehole Top section Borehole Middle section Borehole Bottom section

4.0 3.0 2.5 4.0 3.0 2.5 4.0 4.0

1.83 1.95 2.12 1.90 2.01 1.92 1.78 1.71

1.15 1.20 1.33 1.18 1.26 1.23 1.10 1.07

78.77 81.63 90.49 80.82 85.88 84.20 74.83 72.78

88.0 106.0 94.1 77.2 87.2 103.1 100.0 76.9

4.89 5.89 5.22 4.29 4.84 5.73 5.59 4.27

22.68 27.53 24.23 19.96 22.59 26.70 25.68 19.44

4.25 4.95 3.92 3.63 3.84 4.66 5.08 3.99

72.6 29.6 22.2 90.3 28.2 21.7 76.8 73.2

7.8 6.8 7.5 24.3 7.5 7.5 8.4 12.9

72.0 24.0 19.4 81.4 26.4 20.4 81.6 75.0

4.0

1.80

1.10

75.34

117.0

6.48

29.77

5.89

76.6

14.3

58.8

BH-bot

reaching a minimum, it started to increase because of the accumulation of the water generated from hydrate dissociation and outweighed the production. SA in all cases plateaued to the same final level (SA = 0.60–0.65) in Fig. 9b. SG in the reactor increased monotonically from the start of dissociation and gradually plateaued to its final level (SG = 0.25–0.35) after t = 2.0 hr. This indicated that after t = 2.0 hr, all the CH4 gas generated from hydrate dissociation should be produced from the reactor outlet.

compares well with the CSMGem [1] estimation Teq = −0.60 °C and is below the MH quadruple point. However, we deem that no ice was formed in the process because the relative short period of time (t < 10 mins) below the freezing point of water and no abnormality was identified in the T response. In addition, it is found that both Tavg and Tmax are higher than Teq, which can be attributed to (a) the initial temperature difference inside the reactor (a warm region near the top boundary and a cold region near the cooling boundary); and (b) the spatial heterogeneous distribution of SH that requires different levels of heat to fuel the dissociation reaction. To examine the heat transfer characteristics of the process, Fig. 11 presents the evolution of the spatial distribution of the measured T under different BHPs at different time points (t = 0 min, 3 min, 60 min, 120 min, and 180 min in Fig. 10). The initial spatial distribution of T inside the reactor at t = 0 min confirms our earlier analysis that a warm region existed near the top boundary (see panel A in Fig. 11). At t = 3 min when the dissociation reaction is at its maximum, a low temperature region expands to the entire domain of the reactor (see panel B in Fig. 10). The lowest temperature Tmin attained is determined by the BHPs employed. The low temperature region continues to shrink from t = 60 min till t = 180 min from the outer boundary to the centre of the hydrate-bearing core (see panels C-E in Fig. 11), suggesting the direction of the heat transfer from reactor outer boundary inward to the centre. During this period, heat conduction is the dominant process controlling the heat transfer behaviour of the system. After t = 180 min, spatial distribution of T resembled that at the start of the dissociation t = 0 min with the exception in BHP = 4.0 MPa due to the slow ongoing hydrate dissociation. Such heat transfer behaviour is typical in a laboratory apparatus investigating the dissociation behaviour of hydrate-bearing samples because of the circumferential temperature boundary condition. Our findings are also corroborated by the experimental and numerical studies of Konno et al. [51] and Wang et al. [52] investigating the hydrate dissociation behaviour below quadruple point. The above analysis suggeseted that BHP = 2.5 MPa could be the lowest pressure that can be employed to avoid ice generation from MH dissociation.

3.5. Spatial distribution of T at different BHPs Fig. 10 shows the evolution of temperature (Tmin, Tmax and Tavg from the twelve T monitoring points in Fig. 2) over time. In all cases, T at all positions started to decrease drastically at the start of the depressurization because of the strong endothermic nature of MH dissociation. The specific heat of the system fuels the fast hydrate dissociation front initially but is not sufficent. Under the combination of heat inflow from the circulating water and the surrounding ambient, T started to recover back gradually after reaching the minimum. The time taken for T to stabilize in all cases are practically the same and around 3.0 hrs. During this period, hydrate continues to dissociation (see Fig. 9a) at a nonequilibrium condition. It is interesting to note that in all the BHPs employed, Tmin reached the equilibrium temperature of MH, Teq. It should be noted that Tmin attained at BHP = 4.0 MPa (4.20 °C) and BHP = 3.0 MPa (1.41 °C) are above the MH quadruple point. Tmin at BHP = 2.5 MPa (−0.63 °C)

3.6. Slotted-liner design vs. borehole design Fig. 12 shows the comparison of cumulative production of VG, MW and the water gas ratio WGR between slotted-liner (SL) and borehole (BH) design under BHP = 2.5 MPa, 3.0 MPa and 4.0 MPa. Similar to the SL design, decreasing BHP increased the rate of gas production in BH design. The production profiles of gas over time are self-similar between the two different wellbore configurations in Fig. 12a. This can be attributed to the relative small scale of the reactor apparatus, where the dominating mechanism for gas production is the kinetic rate of the reaction and the heat transfer of the hydrate-bearing sediments instead of the fluid flow in porous media [42]. However, in terms of MW shown

Fig. 10. Evolution of temperature (Tavg, Tmin and Tmax) using vertical wellbore with slotted-liner design under BHP = 4.0 MPa (SL-a), 3.0 MPa (SL-b), and 2.5 MPa (SL-c). 9

Applied Energy 254 (2019) 113635

Z. Yin, et al.

Fig. 11. Evolution of the spatial distribution of T using vertical wellbore with slotted-liner design under BHP = 4.0 MPa (SL-a) in panels A1-E1, 3.0 MPa (SL-b) in panels A2-E2, and 2.5 MPa (SL-c) in panels A3-E3. Scales are on the right of all panels. Points A-E refer to the specific time in Fig. 10.

in Fig. 12b, the production time of water in the SL design is relatively shorter than the BH design under all BHPs. Decreasing BHP increased the final MW produced from 64.5 g to 108.1 g in the BH design. Thus, under deep pressure drawdown scenario (e.g. BHP = 2.5 MPa), SL shows a superiority controlling the water production from the hydratebearing sediments. This can be attributed to the shape of the liner, whereby the long and narrow slots alters the radial flow path of aqueous phase into the wellbore and reduced the perforation area, thus providing a barrier for continuous water to be produced [23]. The WGR profiles shown in Fig. 12c shows an overall similar behaviour, which increased to a maximum peak (~50.0 g/L) at the start of depressurization for a short duration and decreased gradually until stabilized around 4.0 g/L after t = 2.0–3.0 hrs. The optimal wellbore design which yielded the smallest WGR is the SL design at BHP = 2.5 MPa with WGR = 3.4 g/L.

was slightly lower (VG = 23.2L) with a gas recovery ratio of 72.8%. It is interesting to note that there was a slight delay in the gas production from BH-top at the start of depressurization. This can be attributed to the location of perforations away from the concentrated-SH zone and sufficient time need to be waited for the dissociated CH4 gas to migrate upward to the open perforations to be produced. Cumulative water production followed a two-stage pattern in all three different cases: (a) MW increased exponentially at the start of depressurization (t = 0–1.0 hr); and (b) MW plateaued to the final level during the rest of the constant-pressure period (t = 1.0–10.0hr). The initial water production rate followed the order of BH-top > BHbot > BH-mid. This can be explained by the fact that majority of the aqueous phase in the MHBS was located at the top section of the reactor before dissociation and can be readily produced upon depressurization due to high water saturation and large relatively permeability of water. Our numerical simulation studies on the same MH formation and dissociation process has confirmed such heterogeneous spatial distribution of aqueous phase [29,31]. The experimental results suggested that high water production rate could potentially hinder the production of gas at early stage. This is evidenced by the production profile of BH-top in Fig. 13, where the highest water production rate upon depressurization results in a delay in the gas production. This can be explained by the reduction in the relative permeability of gas phase due to the high saturation of SA near wellbore and the reasons discussed earlier. The final mass of water produced followed the order: BH-bot (116.64 g) > BH-top (100.62 g) > BH-mid (76.86 g) as shown in Table 3. This is expected because the free water and the water produced from hydrate dissociation tend to drain down to the bottom section of the reactor due to gravity and can be produced easily from the bottom perforations. It should be noted that the initial produced water during the depressurization stage accounted for more than 90% of the total water produced in all cases. This can be attributed to the flow of aqueous phase driven by the pressure difference between the wellbore perforations and the body of the HBS. During the relatively long constantpressure (BHP = 4.0 MPa) stage, water production appeared to be slow and not in sync with the gas production. This can be attributed to the

3.7. Effect of partial perforation location Given the practically similar gas production profiles and the relatively lower water produced in BH design under BHP = 4.0 MPa (see Fig. 12a), we further investigated using the same type of BH design the effect of different partial perforation locations on the production behaviour. Three different types of wellbore with borehole perforations at the top section (BH-top), middle section (BH-mid) and bottom section (BH-bot) of the wellbore were incorporated in the centre of the reactor (see Fig. 3c–e). Same perforation length l = 30.0 mm and perforation area 3.5% (see Table 1) were used to ensure that the only changing variable is the location of perforation. Fig. 13 shows the comparison of the cumulative production of gas and water in experiments BH-top, BH-mid and BH-bot at BHP = 4.0 MPa. Overall, different perforation locations yielded similar continuous gas production behaviour. The gas production profiles were representative of aqueous-rich hydrate bearing sediments [22], where no or little free gas remained in the system and the gas production rate was positively related to the rate of hydrate dissociation. The final gas produced for BH-top and BH-bot were practically the same (VG = 24.8 L) with a gas recovery ratio of ~75.0%. Final gas produced for BH-mid 10

Applied Energy 254 (2019) 113635

Z. Yin, et al.

Fig. 13. Comparison of cumulative production of gas and water using wellbore BH-top, BH-mid and BH-bot under BHP = 4.0 MPa.

therefore have an implication for future field applications from the well completion perspective: selecting targeted layers and blocking off undesired aqueous-rich layers help prevent water production in hydrate reservoirs [55]. Fig. 14 presents a summary of the gas recovery ratio (RG), the water recovery ratio (RW) and the hydrate dissociation time (t50,H) for all wellbore designs used in this study. The desired optimal condition for MH dissociation process lies at the bottom corner of the figure with high RG, low RW and short t50,H. In view of this criteria, the optimal design of the wellbore should be the slotted-liner type and the desired BHP should be at 2.5 MPa. In addition, it is found that the perforation location does not pose a significant impact on the production of gas by comparing the partial completion cases (BH-top, BH-mid, and BH-bot) with the full completion case (BH-a). However, in terms of reducing water production, the optimal perforation location is at the middle section of the wellbore with reasons analysed earlier. 4. Conclusions In this study, the effect of different wellbore designs on the production behaviour of aqueous-rich methane hydrate-bearing sediments induced by depressurization was investigated experimentally. The wellbore design varies in two factors: (a) the shape of the perforation (slotted-liner vs. borehole); and (b) the location of the partial perforations (BH-top, BH-mid and BH-bot). We synthesized nine samples of MHBS through the excess-water method and quantified them of similar phase saturations (SH = 43.0%, SA = 54.0% and SG = 3.0%) based on the pore-volume balance method. The incorporation of the slotted-liner wellbore altered the flow path of the gas-water two phase flow from reservoir to wellbore, thus resulted in a continuous gas production and a step-wise water production under all BHPs (2.5 MPa, 3.0 MPa and 4.0 MPa). In addition, slotted-liner design showed superiority than the borehole design in controlling water production under deep depressurization scenario (BHP = 2.5 MPa). By comparing the production behaviours with different perforation locations, it was found that perforation at the middle section of the wellbore away from the high-SA and high-SH region is ideal for preventing excessive water production. The perforation locations have minimal effect on the production of gas in the current small-scale reactor. Our results clearly demonstrated that the design of wellbore is one important factor to consider in improving the gas production and gas recovery ratio from methane hydratebearing sediments. The optimal wellbore design and perforation location may shed light on improved experimental design conditions and possibly field applications in the future. Future studies can incorporate the results from the single-well study into a multi-well system to further

Fig. 12. Comparison of (a) cumulative gas production profiles, (b) cumulative water production profiles and (c) water-gas ratio across various BHPs and wellbore designs (SL- Slotted-liner; BH- Borehole).

density-driven fluid flow in porous media, where expansion and buoyance effect drives the flow of gas and gravity drives the flow of water downward and limits the lateral flow [53]. The optimal design that yielded the smallest WGR is the wellbore with middle perforations, BH-mid with WGR = 3.99 (see Table 3). This demonstrated that the perforation at the middle section of the wellbore away from the high-SA and high-SH region significantly reduced the water production because of the spherical flow regime induced [24]. The experimental results were also corroborated by the simulation results of Yuan et al. [54], in which they reported that middle production interval resulted in the least amount of water produced in a hydrate reservoir. The experimental results presented in this paper could 11

Applied Energy 254 (2019) 113635

Z. Yin, et al.

Fig. 14. Summary of (a) cumulative gas recovery ratio RG, (b) cumulative water recovery ratio RW and (c) time for half of the MH to dissociate t50,H under various designs of wellbore in this study.

improve the gas recovery and energy efficiency for production from methane hydrate-bearing sediments.

future commercial production. Energy Fuels 2017;31:2607–16. [7] Li J-f, Ye J-l, Qin X-w, Qiu H-j, Wu N-y, Lu H-l, et al. The first offshore natural gas hydrate production test in South China Sea. China Geol 2018;1:5–16. [8] Moridis G, Collett TS, Pooladi-Darvish M, Hancock SH, Santamarina C, Boswell R, et al. Challenges, uncertainties, and issues facing gas production from gas-hydrate deposits. SPE-131792-PA. 2011; 14:76–112. [9] Yin Z, Linga P. Methane hydrates: a future clean energy resource. Chin J Chem Eng 2019. [10] Dallimore SR, Collett TS. Scientific results from the Mallik 2002 Gas Hydrate Production Research Well Program, Mackenzie Delta, Northwest Territories, Canada. Canada: Natural Resources Canada, Geological Survey of Canada, Vancouver, BC (Canada); 2005. [11] Feng J-C, Wang Y, Li X-S, Li G, Zhang Y, Chen Z-Y. Effect of horizontal and vertical well patterns on methane hydrate dissociation behaviors in pilot-scale hydrate simulator. Appl Energy 2015;145:69–79. [12] Chong ZR, Moh JWR, Yin Z, Zhao J, Linga P. Effect of vertical wellbore incorporation on energy recovery from aqueous rich hydrate sediments. Appl Energy 2018;229:637–47. [13] Chong ZR, Zhao J, Chan JHR, Yin Z, Linga P. Effect of horizontal wellbore on the production behavior from marine hydrate bearing sediment. Appl Energy 2018;214:117–30. [14] Konno Y, Jin Y, Shinjou K, Nagao J. Experimental evaluation of the gas recovery factor of methane hydrate in sandy sediment. RSC Adv 2014;4:51666–75. [15] Tang LG, Xiao R, Huang C, Feng ZP, Fan SS. Experimental investigation of production behavior of gas hydrate under thermal stimulation in unconsolidated sediment. Energy Fuels 2005;19:2402–7. [16] Li X-S, Yang B, Zhang Y, Li G, Duan L-P, Wang Y, et al. Experimental investigation into gas production from methane hydrate in sediment by depressurization in a novel pilot-scale hydrate simulator. Appl Energy 2012;93:722–32. [17] Li G, Li X-S, Tang L-G, Zhang Y. Experimental investigation of production behavior of methane hydrate under ethylene glycol injection in unconsolidated sediment. Energy Fuels 2007;21:3388–93. [18] Song Y, Cheng C, Zhao J, Zhu Z, Liu W, Yang M, et al. Evaluation of gas production from methane hydrates using depressurization, thermal stimulation and combined methods. Appl Energy 2015;145:265–77. [19] Loh M, Too JL, Falser S, Linga P, Khoo BC, Palmer A. Gas production from methane hydrates in a dual wellbore system. Energy Fuels 2015;29:35–42. [20] Yoneda J, Oshima M, Kida M, Kato A, Konno Y, Jin Y, et al. Permeability variation and anisotropy of gas hydrate-bearing pressure-core sediments recovered from the Krishna-Godavari Basin, offshore India. Mar Pet Geol 2018. [21] Holland ME, Schultheiss PJ, Roberts JA. Gas hydrate saturation and morphology

Acknowledgement The financial support from Lloyds Register Singapore Pte. Ltd. (LRSPL) is greatly appreciated. Zhenyuan Yin appreciate the sponsorship from LRSPL and Singapore EDB for the IPP scholarship. Li Huang acknowledges the support from the China Scholarship Council for the sponsorship. Appendix A. Supplementary material The picture of the five different vertical wellbores used in this experimental study is shown in in the Fig. S1 in the Supporting Information. The particle size analysis of the sandy medium used in the experiments is shown in Fig. S2 in the Supporting Information. The Supporting Information is accessible via the Internet. Supplementary data to this article can be found online at https://doi.org/10.1016/j. apenergy.2019.113635. References [1] Sloan Jr. ED, Koh CA. Clathrate hydrates of the natural gases. 3rd ed. Boca Raton, FL: CRC Press; 2008. [2] Englezos P. Clathrate hydrates. Ind Eng Chem Res 1993;32:1251–74. [3] Boswell R, Collett TS. Current perspectives on gas hydrate resources. Energy Environ Sci 2011;4:1206–15. [4] Chong ZR, Yang SHB, Babu P, Linga P, Li X-S. Review of natural gas hydrates as an energy resource: prospects and challenges. Appl Energy 2016;162:1633–52. [5] Koh CA. Towards a fundamental understanding of natural gas hydrates. Chem Soc Rev 2002;31:157–67. [6] Konno Y, Fujii T, Sato A, Akamine K, Naiki M, Masuda Y, et al. Key findings of the world’s first offshore methane hydrate production test off the coast of Japan: toward

12

Applied Energy 254 (2019) 113635

Z. Yin, et al.

[22] [23] [24] [25] [26] [27] [28] [29] [30] [31] [32] [33] [34] [35] [36] [37] [38]

from analysis of pressure cores acquired in the Bay of Bengal during expedition NGHP-02, offshore India. Mar Pet Geol 2018. Chong ZR, Yin Z, Tan JHC, Linga P. Experimental investigations on energy recovery from water-saturated hydrate bearing sediments via depressurization approach. Appl Energy 2017;204:1513–25. Furui K, Zhu D, Hill AD. A Comprehensive Model of Horizontal Well Completion Performance. SPE-84401-PA. 2005; 20:207–20. Economides MJ, Hill AD, Ehlig-Economides C, Zhu D. Petroleum production systems. Pearson Education, Inc.; 2012. Merey Ş. Drilling of gas hydrate reservoirs. J Nat Gas Sci Eng 2016;35:1167–79. Kurihara M, Sato A, Ouchi H, Narita H, Masuda Y, Saeki T, et al. Prediction of Gas Productivity From Eastern Nankai Trough Methane-Hydrate Reservoirs. SPE131792-PA. 2009; 12:477–99. The second offshore production test of methane hydrates in the Eastern Nankai Trough and Site Characterization Efforts; 2019. Konno Y, Yoneda J, Egawa K, Ito T, Jin Y, Kida M, et al. Permeability of sediment cores from methane hydrate deposit in the Eastern Nankai Trough. Mar Pet Geol 2015;66:487–95. Yin Z, Moridis G, Chong ZR, Tan HK, Linga P. Numerical analysis of experimental studies of methane hydrate dissociation induced by depressurization in a sandy porous medium. Appl Energy 2018;230:444–59. Yin Z, Moridis G, Chong ZR, Tan HK, Linga P. Numerical analysis of experiments on thermally induced dissociation of methane hydrates in porous media. Ind Eng Chem Res 2018;57:5776–91. Yin Z, Moridis G, Tan HK, Linga P. Numerical analysis of experimental studies of methane hydrate formation in a sandy porous medium. Appl Energy 2018;220:681–704. Matsumoto R, Tomaru H, Lu H. Detection and evaluation of gas hydrates in the Eastern Nankai trough by geochemical and geophysical methods. Resour Geol 2004;54:53–67. Yin Z, Moridis G, Chong ZR, Linga P. Effectiveness of multi-stage cooling processes in improving the CH4-hydrate saturation uniformity in sandy laboratory samples. Appl Energy 2019;250:729–47. Sloan ED. Gas hydrates: review of physical/chemical properties. Energy Fuels 1998;12:191–6. Waite WF, Santamarina JC, Cortes DD, Dugan B, Espinoza D, Germaine J, et al. Physical properties of hydrate-bearing sediments. Rev Geophys 2009;47. Seol Y, Kneafsey TJ. X-ray computed-tomography observations of water flow through anisotropic methane hydrate-bearing sand. J Petrol Sci Eng 2009;66:121–32. Kneafsey TJ, Tomutsa L, Moridis GJ, Seol Y, Freifeld BM, Taylor CE, et al. Methane hydrate formation and dissociation in a partially saturated core-scale sand sample. J Petrol Sci Eng 2007;56:108–26. Bagherzadeh SA, Moudrakovski IL, Ripmeester JA, Englezos P. Magnetic resonance imaging of gas hydrate formation in a bed of silica sand particles. Energy Fuels 2011;25:3083–92.

[39] Priegnitz M, Thaler J, Spangenberg E, Rücker C, Schicks JM. A cylindrical electrical resistivity tomography array for three-dimensional monitoring of hydrate formation and dissociation. Rev Sci Instrum 2013;84:104502. [40] Moridis GJ. User's manual for the hydrate v1. 5 option of TOUGH+ v1. 5: a code for the simulation of system behavior in hydrate-bearing geologic media. LBNL-6869E. Berkeley, California, USA: Lawrence Berkeley National Laboratory; 2014. [41] Moridis GJ. User's manual of the TOUGH+ core code v1. 5: a general-purpose simulator of non-isothermal flow and transport through porous and fractured media. LBNL 6871E. Berkeley, California, USA: Lawrence Berkeley National Laboratory; 2014. [42] Yin Z, Moridis G, Tan HK, Linga P. Numerical modelling of methane hydrate dissociation in sandy porous media by depressurization with a parametric study. Offshore technology conference Asia. Kuala Lumpur, Malaysia: offshore technology conference. 2018. p. 10. [43] Khurana M, Yin Z, Linga P. A review of clathrate hydrate nucleation. ACS Sustainable Chem Eng 2017;5:11176–203. [44] Ohno H, Strobel TA, Dec SF, Sloan JED, Koh CA. Raman studies of methane−ethane hydrate metastability. J Phys Chem A 2009;113:1711–6. [45] Kumar A, Maini B, Bishnoi PR, Clarke M, Zatsepina O, Srinivasan S. Experimental determination of permeability in the presence of hydrates and its effect on the dissociation characteristics of gas hydrates in porous media. J Petrol Sci Eng 2010;70:114–22. [46] Linga P, Haligva C, Nam SC, Ripmeester JA, Englezos P. Gas hydrate formation in a variable volume bed of silica sand particles. Energy Fuels 2009;23:5496–507. [47] Sloan ED, Fleyfel F. Hydrate dissociation enthalpy and guest size. Fluid Phase Equilib 1992;76:123–40. [48] Servio P, Englezos P. Measurement of dissolved methane in water in equilibrium with its hydrate. J Chem Eng Data 2002;47:87–90. [49] Clarke M, Bishnoi PR. Determination of the activation energy and intrinsic rate constant of methane gas hydrate decomposition. Can J Chem Eng 2001;79:143–7. [50] Kim HC, Bishnoi PR, Heidemann RA, Rizvi SSH. Kinetics of methane hydrate decomposition. Chem Eng Sci 1987;42:1645–53. [51] Konno Y, Uchiumi T, Oyama H, Jin Y, Nagao J, Masuda Y, et al. Dissociation behavior of methane hydrate in sandy porous media below the quadruple point. Energy Fuels 2012;26:4310–20. [52] Wang Y, Feng J-C, Li X-S, Zhang Y, Li G. Large scale experimental evaluation to methane hydrate dissociation below quadruple point in sandy sediment. Appl Energy 2016;162:372–81. [53] Holzbecher EO. Modeling density-driven flow in porous media: principles, numerics, software. Springer Science & Business Media; 1998. [54] Yuan Y, Xu T, Xin X, Xia Y. Multiphase Flow Behavior of Layered Methane Hydrate Reservoir Induced by Gas Production. Geofluids 2017;2017:15. [55] Yu T, Guan G, Abudula A. Production performance and numerical investigation of the 2017 offshore methane hydrate production test in the Nankai Trough of Japan. Appl Energy 2019;251:113338.

13