Polymer Flooding in an Artificial Hydrate Bearing Sediments for

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Polymer Flooding in an Artificial Hydrate Bearing Sediments for Methane Gas Recovery Vishnu Chandrasekharan Nair, Deepjyoti Mech, Pawan Gupta, and Jitendra S. Sangwai Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.8b00874 • Publication Date (Web): 07 May 2018 Downloaded from http://pubs.acs.org on May 7, 2018

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Research Article

Polymer Flooding in an Artificial Hydrate Bearing Sediments for Methane Gas Recovery

Vishnu Chandrasekharan Nair, Deepjyoti Mech, Pawan Gupta, Jitendra S. Sangwai* Gas hydrate and Flow assurance Laboratory, Petroleum Engineering Program, Department of Ocean Engineering, Indian Institute of Technology Madras, Chennai 600 036, India

Corresponding Author: Jitendra Sangwai: [email protected] Phone: +91-44-2257-4825 (Office) Fax: +91-44-2257-4802

1 ACS Paragon Plus Environment

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ABSTRACT Polymer flooding has been one of the most promising method used for enhanced oil recovery from matured crude oil reservoirs across the globe due to its distinct advantages over simple water flooding. However, the use of polymer flooding has not yet been investigated for methane recovery from hydrate reservoirs. In our earlier work, we have investigated the effect of various molecular weights and concentrations of polyethylene glycol (PEG) polymer on the phase stability and kinetics of methane hydrate. This information has been explored for successful use of PEG as a chemical agent for polymer flooding from hydrate reservoirs. In this work, detailed experimental investigations on methane production from hydrate bearing sediments have been carried out using PEG polymer flooding in a 3-dimensional hydrate reactor. Initially, methane hydrate formation has been investigated using two silica sand porous beds (viz., 0.16 mm and 0.46 mm), and pure water at an initial hydrate formation pressure of 8 MPa and 277.15 K. Subsequently, hydrate dissociation studies have been carried out using polymer flooding at final hydrate reservoir pressure of ~4.3 MPa and 277.15 K. The effect of molecular weights (200 and 600 kg/kmol, viz., PEG-200 and PEG-600, respectively), concentrations (0.2 and 0.4 mass fractions) and injection rates (1 and 5 mL/min) of PEG aqueous solution has been analysed for methane gas recovery. PEG-200 is observed to be an effective flooding agent as compared to PEG-600 and other inhibitor used in the literature, such as ethylene glycol. In addition, studies on the total dissolved solids (TDS) and electrical conductivity of PEG aqueous solutions have also been investigated before and after flooding to check the efficacy of polymer flooding for methane production. PEG is having much lower freezing point (208.15 K, i.e., -65 oC) as compared to ethylene glycol (260.25 K, i.e., -12.9 oC), therefore polymer flooding is expected to be more beneficial for methane gas production from hydrate bearing zones with low reservoir temperatures.


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Keywords: Gas Hydrate; Inhibitor; Polyethylene Glycol, Polymer Flooding; Recovery. 1. INTRODUCTION Natural gas hydrates are crystalline solid bodies formed through hydrogen bonding of water molecules, in which the gas molecules are encapsulated inside the water cavities. Generally, these gas molecules are methane, ethane, propane, and carbon dioxide.1 Natural gas hydrates have gained significant importance due to their potential role as a future sustainable energy resource. Gas hydrates reserves are spread over the permafrost and deepsea sediments around the world.1–4 Natural gas hydrates have an estimated amount of 2.1×1016 m3 of methane gas which is significant as compared to other conventional carbonaceous fuel reserves available.2,3,5 Enormous amounts of natural gas hydrate reserves comprise around 53% of the worldwide fossil fuels, which is about 10,000 gigatons according to an energy resource estimation by Kvenvolden.6 Many field trials have been carried out for natural gas recovery from these hydrate reserves with minimum success due to the hostile environments like permafrost regions and deep-sea conditions which have been briefly reviewed in recent literatures.5,7–10 The most potential methods of methane recovery from hydrate reservoirs are thermal stimulation, depressurization and injection of a suitable hydrate inhibitor. These methods use the information on hydrate phase stability and kinetics of hydrate dissociation.11–17 In thermal stimulation, the temperature of hydrate bearing zone is increased beyond the hydrate phase stability zone, whereas in depressurization, the pressure is decreased below the hydrate phase stability zone to dissociate it. In hydrate inhibitor injection method, the hydrates are dissociated by shifting the phase equilibrium curve towards higher pressures and lower temperatures, which leads to release of methane gas from the methane hydrate.1,18–20 In addition, another approach for methane production from the hydrate zone is the CO2 sequestration process.11,12,21–26 In this method, CO2 gas (preferably in the form of CO2+N2


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mixture) is injected into methane hydrate reservoirs to replace methane out of hydrate cages by CO2 gas, thus resulting in the production of methane gas.1,27,28 In thermal stimulation method, severe heat losses have been accounted which can lead to several other operational challenges affecting energy efficiency.5,29–36 Although depressurization is relatively an energy efficient process, the hydrate may reform during methane gas production and choke the wellbore and production tubing.4,29,37,38 Also, the depressurization process may weaken the formation.5,39 Alternatively, hydrate inhibitor injection can be a potentially efficient method due to its ease of operation. This process can have several advantages such as increased energy efficiency, decreased risk of hydrate reformation, and help in maintaining the formation stability by altering the properties of wellbore and reservoir matrix.29,38,40 Generally, two types of inhibitors are used; thermodynamic inhibitors and low dosage kinetic hydrate inhibitors (LDHI).19,41,42 The thermodynamic inhibitors shift the phase stability of hydrate to higher pressure and lower temperature thereby dissociating hydrates. LDHI can be categorised into two parts: antiagglomerate (AA) and kinetic hydrate inhibitors (KHI) inhibitors, where AA prevents the agglomeration of small hydrate particles into bigger form, while KHI prevents the hydrate formation for longer duration.1,19,43 The common thermodynamic inhibitors are monoethylene glycol, di-ethylene glycol, triethylene glycol and methanol, which are mostly used to prevent hydrate formation and deposition in pipelines thereby resolving flow assurance issues.1,44–47 Some dissolved salts (for e.g., NaCl, CaCl2, KCl, NaBr) are also used as thermodynamic hydrate inhibitors.40,48,49 Although hydrate inhibitors are one of the most effective techniques used for preventing hydrate formation during flow assurance, their use for natural gas production from hydrate deposits is not very well investigated. Thermodynamic inhibition for hydrate dissociation is considered to be a highly effective method as compared to other dissociation


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methods. With methanol injection, the gas production rate from methane hydrate on an average could be increased by a factor of 4.4,29 Sira et al.49 and Kamath et al.50 conducted a methane production study using a synthesized porous frost core by injection of brine, methanol and ethylene glycol (EG). In their study, hydrates were formed by pressurising the core holder with methane at around 8.3 MPa and 274 K. From their results, it has been observed that the gas production rate was enhanced with increase in brine concentration, whereas injection of methanol showed higher cumulative gas production as compared to EG. Kawamura et al.51, using a new hydrate experimental set-up for hydrate dissociation, observed that the hydrate dissociation rates were increased due to the injection of warm methanol aqueous solution, and also it effectively inhibited the hydrate reformation within the dissociating core sample. In their subsequent study, Kawamura et al.52 investigated the effect of combined inhibitor (methanol) injection or steam injection methods with depressurization method for methane production using a methane hydrate bearing sediment made in the laboratory. The rate of methane production was found to be faster using combined (methanol injection and depressurization) method as compared to the other combined or individual methods. In their subsequent study,53 they investigated the injection of higher concentration of methanol in an aqueous solution, which effectively resulted in higher rate of gas production. Fan et al.54 performed experiments on methane hydrate dissociation using EG and found that the rate of dissociation was dependent on the concentration and flow rate of EG. Li et al.55 investigated the gas production behaviour from methane hydrate sample in porous bed using injection of EG in a one dimensional apparatus. Their results showed that the gas production efficiency is affected by the concentration and injection rate of EG and showed the maximum value at 60 wt% of EG. Lee32 investigated hydrate dissociation and productivity of methane gas from porous rocks by injecting brine in a one-dimensional device. The rate of methane production was found to reduce significantly


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when the concentration of brine was very high (upto 20 wt%). Gulbrandsen and Svartaas18 investigated the effect of KHI, viz., polyvinylcaprolactam (PVCap) for methane production. It was observed that the energy requirement for PVCap to dissociate hydrate is more as compared to other thermodynamic inhibitors. Li et al.40 investigated hydrate dissociation using inhibitor (methanol) injection, where the production efficiency was found to be increased with the increase in methanol concentration and injection rate. However, the efficiency of methanol injection reached at a maximum value at 60 wt% concentration of methanol. Based on the literature review, a very few chemical inhibitors have been analysed for injection into hydrate bearing sediments for natural gas production. Studies have mostly been conducted under specific conditions such as, using a one dimensional apparatus and with single particle size of sand. Polymer flooding has been one of the most promising method used for enhanced oil recovery from matured crude oil reservoirs across the globe.56–59 The significant advantage of polymer flooding over simple water injection is that it provides improved sweep efficiency by reducing the viscous fingering effects in the subsurface reservoir formations which otherwise is stringent in case of simple water flooding.60–62 Polymer flooding also provides favourable mobility ratio by increasing the viscosity of the displacing fluid, thus improving the recovery.61,63 However, the use of polymer flooding has not yet been investigated in detail for methane recovery from hydrate reservoirs. Information on the dissociation kinetics of methane hydrate and the effect of the molecular weight of polymers is necessary for the successful use polymer flooding for gas production from hydrate reservoirs. In our earlier work, we have investigated the effect of various molecular weights and concentrations of polyethylene glycol (PEG) polymer on the phase stability and kinetics of methane hydrate.64,65 PEG was found to act as both thermodynamic and kinetic hydrate inhibitor.64,65 The molecular weight of PEG was found to have a significant impact on the phase stability


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and kinetics of methane hydrate inhibition. It was observed that the methane hydrate inhibition increases with decrease in the molecular weight and with increase in the concentration of PEG.64 In this work, this information has been explored for successful use of PEG as a chemical agent for polymer flooding from hydrate reservoirs. The present work focuses on the methane production from hydrate bearing sediments using polymer flooding, in which PEG is used as a polymer agent. PEG is non-hazardous and easily biodegradable as compared to other common hydrate inhibitors (EG and methanol).64– 67

Initially, methane hydrate formation was investigated in two different porous media

prepared using two different types of silica sand particles, viz., 0.16 mm and 0.46 mm, and pure water at an initial hydrate formation pressure of 8 MPa and 277.15 K. Subsequently, hydrate dissociation studies have been carried out using polymer flooding at final hydrate reservoir pressure of ~4.3 MPa and 277. 15 K. The final hydrate reservoir pressure of the system has been maintained in-between the equilibrium pressure of pure methane hydrate and that of hydrate+PEG aqueous solution.64 This study provides detailed investigations on the effect of molecular weights (200 and 600 kg/kmol; viz., PEG-200 and PEG-600, respectively), concentrations [0.2 and 0.4 mass fractions (mf)] and injection rates (1 and 5 mL/min) of PEG aqueous solution in methane hydrate reservoirs formed using two different porous sand bed S1 (0.16 mm) and S2 (0.46 mm) on the methane recovery. Total dissolved solids (TDS) and electrical conductivity of the PEG aqueous solutions have also been measured before and after the flooding to check the impact of polymer flooding.

2. EXPERIMENTAL SECTION 2.1. Materials Table 1 shows the materials used for the study along with their suppliers and purity. The deionized distilled water of grade ‘Type 3’ has been obtained from an equipment named


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Labostar (SIEMENS, Germany). Methane gas of purity 99.97 mole % is used in all the experiments, which is supplied by Bhuruka Gas Agency, Bangalore, India. The aqueous PEG polymer solutions are prepared using an accurate analytical balance (AS-220/X; RADWAG, Poland) based on a gravimetric method with an uncertainty of ± 0.00004 mass fraction. Two silica sand samples (supplied by RR construction, Chennai), viz., S1 and S2, with different sizes 0.16 mm and 0.46 mm respectively, have been used to form the porous bed for hydrate formation.

2.2. Measurement of Properties of PEG Aqueous systems Initially, before using PEG solution for polymer flooding, viscosity of the PEG aqueous solution, TDS and electrical conductivity were measured. The values of TDS and electrical conductivity of the solution obtained after polymer flooding were then compared to the respective initial values.

2.2.1. Viscosity Measurements A rheometer (MCR-52, Anton-Paar, Austria) with cup and bob geometry has been used to measure the viscosities of PEG aqueous solutions at 277.15 K. Temperature of the rheometer was set at 277.15 K using a water bath HAAKE A25 (Thermofischer Scientific, USA) during the viscosity measurements. The Anton Paar RheoplusTM software was used to record the data on viscosity.

2.2.2. Electrical Conductivity and TDS Measurements An electrical conductivity meter (PC2700, Eutech instruments, Singapore) was used to determine the electrical conductivity and total dissolved solids (TDS) of the PEG aqueous


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solutions before and after flooding in the porous sand beds. The instrument has a measuring range from 0.050 µS/cm to 500.0 µS/cm with an accuracy of ±1 % of full scale.

2.3. Polymer Flooding in Hydrate Reservoir 2.3.1. Experimental Set-up The experimental set-up designed for this study is shown in Figure 1. The set-up helps in the formation of methane hydrate in the silica sand bed (viz., S1 and S2) followed by hydrate dissociation using polymer flooding and methane recovery into the gas collector (Figure 1a). The set-up consists of a reactor (SS-316) with a capacity of 759 mL (approximately). The reactor is furnished with four temperature sensors, namely, T1, T2, T3, and T4 (Figure 1b). These temperature sensors are Resistance Temperature Detectors (RTD) with working range of 6.15 K-673 K, and are fixed at different depths to capture temperature information during hydrate formation and dissociation. A pressure transducer (Wika A10, Amar Equipment Pvt Ltd., Mumbai) having an accuracy of ≤ ±1 % of the span was used to measure the pressure. Inlet and outlet valves are attached at the tubing to the reactor for injection and release of the gas respectively. The reactor is submerged properly in ethylene glycol solution bath through which the water+glycol mixture was circulated from a water bath (HAAKE A25, Thermo-Fischer Scientific, USA) to maintain the temperature of the system at desired condition (277.15 K). As the region (Chennai, India) is hot during summer, the reactor set-up with surrounding bath has been kept inside an insulated box to provide better insulation from the temperature variation in the atmosphere. The reactor is connected to a methane gas cylinder to pressurize the reactor up to a desired experimental pressure of hydrate formation (8 MPa). The temperature sensors and pressure transducer were connected to the data acquisition system and then to a computer (PC). The pressure and temperature


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conditions as a function of time are acquired online for every 30 s sampling interval using a SCADA software. During hydrate dissociation, produced methane gas has been collected into a gas collector via back-pressure (BP) valve. A porous filter was provided to prevent any small sand particles in the gas stream from entering into the production flowline/tube thus allowing only the gas to pass from the outlet valve of the reactor to the gas collector. In addition, an accumulator is installed in-between porous filter and BP valve to collect excess PEG aqueous solution inside it and allows the methane gas to get separated and eventually collect it in the gas collector via the BP valve (Figure 1a).

2.3.2. Methane Hydrate Formation and Dissociation using Polymer Flooding Figure 1a shows the detailed experimental set-up which helps to explain the experimental procedure for methane hydrate formation and dissociation in porous media during polymer flooding. Two silica sand samples of different average particle sizes, S1 (0.16 mm) and S2 (0.46 mm), are used after sieving, repeated washing with distilled water and subsequent air drying. In this work, hydrate formation experiments have been conducted using 70 % water saturation which is based on our previous work.7 Porous media consists of silica sand of approximately equal to 700 mL volume (which weights, for S1= 998.2 gm with pore volume of 0.244 cm3/gm and S2= 1026.2 gm with pore volume of 0.245 cm3/gm) volume was used to fill the reactor. Silica sand bed was prepared by uniform layering of sand and distilled water alternatively in eight to twelve stages for avoiding the air pockets and to make the silica sand closely packed. This procedure also ensures uniform water saturation across the bed. The sand beds (with individual sands S1 and S2) were found to have 375.92 mD and 489.30 mD permeability, respectively. The reactor was then closed by tightening the bolts after making the porous bed and then RTDs were inserted properly at their respective


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positions (Figure 1b). Subsequently, the reactor is immersed in the ethylene glycol solution which is connected to the water bath (HAAKE A25, Thermo-Fischer Scientific, USA) to control and maintain the temperature of the reactor. The temperature of the water bath was fixed to keep the reactor at the desired temperature (277.15K). After stabilization of the reactor temperature, it is flushed with methane gas two to three times by pressurizing it at about 0.3 MPa to remove the atmospheric air that may be present inside the reactor. Afterward, the reactor was pressurized upto 8 MPa (initial hydrate formation pressure) with methane gas. As the hydrate formation reaction is initiated, the hydrate formation was noticed by a sharp increase in the temperature and sudden drop of the pressure inside the reactor. The pressure of the reactor starts to decrease after the onset of hydrate induction due to continuous gas uptake into the hydrate phase which is getting formed in the silica sand bed porous medium. Completion of hydrate formation was accomplished when there is no further gas intake and no significant decrease in pressure during further experimental time. Table S1 (supporting information) shows various hydrate formation experiments carried out in this study along with the nomenclature used for various experiments. The hydrate formation experiment was then followed by the dissociation of hydrate via injection of PEG aqueous solution into the hydrate bearing silica sand porous media (see for details on various dissociation experiments in Table 2). During the dissociation experiment, PEG aqueous solution is injected into the reactor containing hydrate bearing sediments at two different rates (1 mL/min and 5 mL/min) separately. The solution has been passed through the tube which is kept inside the insulated box so that the temperature of the injected PEG aqueous solution is thermally equilibrated with the bed temperature (277.15 K) before getting into the hydrate reservoir. The first experiment has been carried out using S1 silica sand bed with PEG-200 aqueous solution at 0.2 mass fraction, which is denoted as (S1_PEG-200_0.2 mf) at 1 mL/min of injection rate. Similarly, other nomenclature follows


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(see Table S1 and Table 2). For all the experiments, 180 ml of PEG aqueous solution has been used which is based on 1 mL/min for three hours dissociation experiment. Before starting the hydrate dissociation, pressure of the flowline from the outlet valve of the reactor upto to the BP valve (see Figure 1a) was equalised to the reactor pressure using methane gas from gas cylinder so as to avoid hydrate dissociation due to sudden pressure reduction. The BP valve was set at a pressure (for e.g., 4.3 MPa for S1 PEG-200 at 0.2 mf ), which is inbetween the equilibrium pressure of pure methane hydrate (3.9 MPa at 277.15 K) and that of hydrate+PEG aqueous solution (for e.g., 5 MPa at 277.15 K of PEG-200 at 0.2 mf)

64

to

ensure that the methane gas is recovered only from the hydrate dissociation due to PEG aqueous solution flooding. Further details are provided in results and discussion section. Subsequently, injection of PEG aqueous solution started and the outlet valve of the reactor was opened simultaneously, where after some time, the dissociated methane gas started to flow through flowline (III) and accumulator (IV), and then recovered in the gas collector (V) (for number denotation, see Figure 1a). During dissociation, consumed gas (II) in the hydrate phase and free gas (I) present in the reactor along with line gas (III) start to flow to the gas collector through accumulator and BP valve as shown in Figure 1(a). In the accumulator, both the recovered gas (IV) and excess injected aqueous solution are stored. Accumulator allows the gas to get separated from the produced PEG aqueous solution (gravity separation) and pass through the exit of the accumulator to the gas collector (V) via BP valve. Cumulative gas was collected in the gas collector (V) after completion of the hydrate dissociation. Eq.1 was used to determine the gas that is recovered from the methane hydrate reservoir: ℎ = − − − −

(1)


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The methane recovery percentage (%) from hydrate bearing sediments using various molecular weight/concentrations of PEG aqueous solutions is calculated using Eq. 2: % =

ℎ × 100 ℎ ℎ

(2) The gas production ratio (GPR) is calculated using Eq. 3:29 ! ! =

ℎ " ℎ

(3) The inhibitor effectiveness (Ɛinhibitor) is defined as the quantity of natural gas produced (mL) to the mass (g) of the inhibitor solution (PEG + water) injected, as calculated using Eq. 4. The PEG effectiveness (ƐPEG) is defined as the quantity of natural gas produced (mL) to the mass (g) of the PEG injected (mass of PEG only), and calculated using Eq. 5:29

Ɛ$%&$'$()* =

ℎ " ℎ +@-.! ℎ/ 0 (4)

Ɛ123 =

ℎ " ℎ +@-.! " !4 0

(5)

where, NTP is normal temperature and pressure conditions (Pressure = 0.101325 MPa; T = 293.15 K).

3. RESULTS AND DISCUSSION In this work, various experiments have been performed on polymer flooding in hydrate bearing sediments using two different porous sand beds of particle sizes 0.16 and


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0.46 mm. The reactor was charged with methane gas at an initial pressure of 8 MPa and 277.15 K. The temperature of the reactor was maintained at 277.15 K for all the hydrate formation and polymer flooding experiments. After the hydrate formation was over, methane is recovered from hydrate bearing sediments using polymer flooding. In this section, initially, details on the hydrate formation experiments have been provided followed by details on the methane recovery using polymer flooding. 3.1. Hydrate Formation in Porous Media Initially, methane hydrate formation experiments have been performed using two porous sand beds. The details are given in the Table S1 (supporting information). Induction time, moles of gas consumed, gas-to-hydrate conversion, water-to-hydrate conversion, etc., are mentioned in Table S1 for various experiments. Equations used for the calculation of moles of gas consumed during hydrate formation, and the final saturation of water, gas and hydrate in the porous silica sand beds have been provided in the supporting information (Eqs. S1 to S7). Other equations used for calculation of gas-to-hydrate conversion, and water-tohydrate conversion are available elsewhere7,68 and are not reproduced for the sake of brevity. Figure 2 shows the sample pressure-temperature profile during methane hydrate formation for (a) S1 porous bed (Expt. run 1, S1_PEG-200_0.2 mf), and (b) S2 porous bed (Expt. run 7, S2_PEG-200_0.2 mf). From Figure 2, it has been observed that the delayed induction time in the case of S2 sand bed as compared to S1 sand bed is attributed to its bigger particle size. This is because, it has been speculated that the hydrate nucleation occurs at the surface of sand particles.69 Bed with a smaller sand size silica sand (S1) provides more number of nucleation sites as compared to the porous bed with bigger sand particles (S2). For S1 porous bed, pressure in the reactor got stabilized after 4 h and no further decline has been observed, whereas for S2 porous bed, it took almost 16 h to stabilize the pressure which indicates the end of hydrate formation in the reactor. In addition, two discrete hydrate induction points


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have been observed for S2 porous silica sand bed. Figure 3 shows methane gas consumption profiles during hydrate formation for both silica sand beds (Expt. run 1, S1_PEG-200_0.2 mf and Expt. run 7, S2_PEG-200_0.2 mf; in Table 2). It has been observed that the moles of gas consumed during hydrate formation was slightly more for S1 bed as compared to S2 bed. This may be attributed to the enhanced kinetics of methane hydrate formation in case of smaller silica sand size, which provides more surface area for gas-liquid interaction and hence improves the methane-water contact. It has been postulated that, due to the increase in the surface area for S1 sand bed, the water forms thin layer around the sand grains and hence less bulk accumulation of water occurs in the pore spaces as compared to that of silica sand with bigger grain size (S2 bed). This may results in the formation of smaller hydrate particles in S1 sand bed as compared to bigger hydrate particles in S2 sand bed. This observation is inline with the previous studies.7,70 Also as observed in the previous studies,7,70 here, the hydrate saturation in the presence of bigger particle sized silica sand bed was found to be slightly lower than the small particle sized bed as shown in Table 2. Similar trends have been observed for all other hydrate formation experiments as reported in Table 2. As mentioned above, the moles of gas consumed at the end of methane hydrate formation was found to be slightly more for S1 silica sand bed as compared to S2 silica sand bed and thus, it can be related to the hydrate saturation as well (Table 2). Even though, the hydrate saturation (calculated using Eq. S6 in supporting information) for both silica sand beds are almost the same (0.14 to 0.15, see Table 2) before the start of hydrate dissociation experiments and thus the effect of silica sand size can also be investigated for polymer flooding operations.

3.2. Polymer Flooding in Hydrate Reservoirs In the current work, eight experiments have been performed to examine the methane recovery from simulated hydrate reservoir using polymer flooding containing PEG aqueous


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solutions of different molecular weights and concentrations. Two different injection rates, viz., 1 mL/min and 5 mL/min have been used for polymer flooding (Table 2). A cumulative quantity of 180 mL of polymer has been injected in to the hydrate reservoir for the recovery of methane. The polymer flooding was continued for 3 h at the injection rate of 1 mL/min and 0.6 h at injection rate of 5 mL/min, where injection rate at 5 mL/min was performed only for S1 bed to investigate the effect of injection rate (S1_PEG-200_0.4 mf in Table 2). Figure 4 shows the average pressure rating (set pressure during hydrate dissociation) with error bars maintained for all the experiments containing S1 and S2 porous silica sand beds during methane hydrate dissociation studies. This figure in fact validates the claim that the hydrate dissociation is purely due to polymer flooding and no other effects such as depressurization were employed. It has been observed that the average hydrate reservoir pressure lies strictly in-between the equilibrium pressure of methane hydrate in pure water (3.9 MPa) and respective hydrate+PEG aqueous solutions at 277.15 K. From our previous studies,64,65 it has been observed that the methane hydrate equilibrium pressure in the presence of PEG aqueous solutions are approximately 5 MPa for PEG-200 at 0.2 mf; 8 MPa for PEG-200 at 0.4 mf and 6.5 MPa for PEG-600 at 0.4 mf, respectively, at 277.15 K (also shown in Figure 4). If the set pressure at back-pressure valve (BP, see Figure 1a) falls below the equilibrium pressure of methane hydrate system in pure water then the dissociation may happens also due to the depressurization effect and not solemnly due to the inhibition effect of PEG aqueous solutions. If the set pressure exceeds the hydrate equilibrium pressures of respective PEG aqueous solutions (Figure 4), then the hydrate will remain stable and dissociation will not happen. This procedure of pressure ratings ensures that the methane hydrate dissociation is purely due to polymer flooding and not due to depressurization or any other effect.


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3.2.1. Variation of Temperature and Pressure during Hydrate Dissociation Figure 5 shows the temperature and pressure profiles of the sand bed reactor during methane hydrate dissociation during polymer flooding. The temperature readings show a decline due to the endothermic nature of hydrate dissociation.1,71,72 It has been observed that the four temperature sensors (T1-T4) show same trend throughout the hydrate dissociation. This indicates the presence of hydrate saturation throughout the porous media. However, the decline in temperature varies slightly (with an average temperature decline of approximately 0.8 K at around 1-1.25 h) for each sensor as shown in Figure 5. It is possibly due to the nonuniformity of hydrate saturation in the porous media. Temperature sensor T1 shows the maximum decline (≈ 2 K) in temperature, which indicates the maximum hydrate dissociation near the T1 measuring point (Figure 1b). It is due to the fact that an injection point of PEG aqueous solution is at the vicinity of T1 sensor, i.e., at the bottom of the porous bed (see Figure 1b), resulting in quick hydrate dissociation near T1. As the pressure is regulated using a back pressure valve (BP) and kept in-between the equilibrium pressure of methane hydrate in the presence of PEG aqueous solution and that of pure water (as depicted in Figure 4), there is no significant variation in the pressure reading throughout methane hydrate dissociation. Figure 6 shows the distribution of temperature profile in the sand bed reactor during methane hydrate dissociation due to the injection of various PEG aqueous solutions with different molecular weights and concentrations. Figure 6a shows the temperature profiles for S1 sand bed with different PEG aqueous solutions. It clearly indicates that the temperature decline is higher for PEG-200 aqueous solution at 0.4 mass fraction (S1_PEG-200_0.4 mf) as compared to those with lower concentrations and higher molecular weights of PEG aqueous solutions (S1_PEG-200_0.2 mf and S1_PEG-600_0.4 mf). This may be due to the faster dissociation of hydrate in the reactor as the PEG-200_0.4 mf is found to be better


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thermodynamic inhibitor as compared to PEG-200_0.2 mf and PEG-600_0.4 mf.64,65 Figure 6b shows the comparison of temperature profiles for S1 and S2 silica sand beds during methane hydrate dissociation due to the injection of PEG-200 aqueous solution at 0.2 mf. It has been observed that the temperature decline of (S2_PEG-200_0.2 mf) is more than (S1_PEG-200_0.2 mf) with a difference of about 0.5 K. Since, the pore spaces in S2 bed is larger (due to large particle size) as compared to that of S1 bed, there might be the formation of bigger methane hydrate particles in the pore space of S2 bed as compared to S1 bed. Therefore, during dissociation of these bigger hydrate particles, higher temperature decline during hydrate dissociation (due to higher endothermicity) might have been observed in case of S2 bed.

3.2.2. Methane Gas Production during Polymer Flooding The cumulative number of moles of methane gas produced has been calculated at every 30 minutes for all the polymer flooding experiments and is shown in Figure 7. The moles of gas recovered are in-line with the observations from the temperature decline curve for the same bed as discussed earlier (Figures 6a and b). It is clear that the methane recovery is higher for S1 porous bed as compared to S2 porous bed at the same PEG aqueous solution and with the same mass fraction, for ex. S1_PEG-200_0.2 mf (0.42 mol) and S2_PEG200_0.2 mf (0.27 mol). This may be due to the larger area of contact of the PEG aqueous solution with the hydrate particles in case of smaller particle size silica sand bed (S1) resulting in more hydrate dissociation than the S2 bed. Also, it is expected that, in smaller particle size bed, the hydrate particle is more like in dispersed state as compared to the lumps of hydrate formed inside the higher particle silica sand bed (S2) due its larger pore space. Higher concentration of PEG, i.e., PEG-200_0.4 mf, acts as better hydrate inhibitor as compared to PEG-200_0.2 mf as observed in our earlier work,64 however, only a slightly


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higher number of moles of methane production is observed as compared to lower mass fraction (0.42 mole for S1_PEG-200_0.2 mf and 0.43 mole for S1_PEG-200_0.4 mf as shown in Figure 7). Also, higher methane recovery has been observed in case of PEG200_0.2 mf (0.42 moles for S1_PEG-200_0.2 mf) as compared to PEG-600_0.4 mf (0.15 moles for S1_PEG-600_0.4 mf), even though PEG-600_0.4 mf acts as a better hydrate inhibitor that PEG-200_0.2 mf.64 In order to investigate the better recovery in the presence of PEG-200_0.2 mf than PEG-600_0.4 mf (which is in contradiction to the thermodynamic hydrate inhibition efficiency), the viscosities of PEG aqueous solutions have been investigated (and reported in Table 2). It has been observed that the viscosity of the PEG200_0.2 mf (8.72 mPas) is lower than the PEG-600_0.4 mf (28.20 mPas) aqueous solution. The higher viscosity in case of PEG-600_0.4 mf might have hindered the easy penetration of aqueous polymer solution in the porous bed. This fact has further been validated based on the TDS and electrical conductivity measurements before and after polymer flooding as discussed later. Similarly, when comparing the effect of molecular weight of PEG on the methane recovery performance from the porous hydrate reservoirs, it is found that PEG-200 act as the better recovery agent than PEG-600 at the same mass fraction. This is due to the better thermodynamic inhibition of PEG-200 polymer solution due to its lower molecular weight than the PEG-600 polymer solution as observed in our earlier work.65

3.2.3. Polymer Flooding Performance in the Recovery of Methane from Hydrate Reservoir The performance of polymer flooding for recovery of methane from hydrate bearing sediments containing silica sand particles of different sizes

have been analysed using

injection of PEG aqueous solutions as shown in Figure 8. Methane recovery (%) from various hydrate bearing sediments has been calculated using Eq. 2. Figure 8a shows the methane recovery (%) from various hydrate bearing sediments at an injection rate of 1 mL/min and for


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various mass fractions (0.2 and 0.4 mfs) of PEG-200 and PEG-600 aqueous solutions. It has been observed that the PEG-200 aqueous solution shows more methane recovery (%) as compared to PEG-600 aqueous solution at the same mass fraction and injection rate (1 mL/min) for S1 porous bed (91.2 % for S1_PEG-200_0.4 mf and 31.6 % for S1_PEG600_0.4 mf). Moreover, as the concentration of PEG-200 increases from 0.2 to 0.4 mass fractions, the methane recovery (%) also increases slightly for S1 bed (88.8 % for S1_PEG200_0.2 mf and 91.2 % for S1_PEG-200_0.4 mf). This is due to the fact that PEG-200 aqueous solution has been found to show higher thermodynamic inhibition as compared to PEG-600 and also the increase in mass fraction for the same molecular weight PEG solution has shown positive effect on thermodynamic hydrate inhibition.64 In addition, the methane recovery from S1 bed is found to be more as compared to S2 bed for PEG-200 aqueous solutions at the same PEG mass fraction (88.8 % for S1_PEG-200_0.2 mf and 58.7 % for S2_PEG-200_0.2 mf). The reason behind this effect of silica sand size on methane recovery has already been discussed earlier in section 3.2.2. Figure 8b shows the effect of injection rates (1 and 5 mL/min) on the methane recovery (%).

Injection rate of 1 mL/min shows more methane recovery as compared to

injection rate at 5 mL/min for PEG-200 aqueous solutions at 0.4 mass fraction for the same S1 bed. The reason for higher recovery for slower injection rate can be due to higher residence time for the PEG aqueous solution in the hydrate reactor in case of 1 mL/min than 5 mL/min. Higher residence time for 1 mL/min allows higher interaction of polymer molecules for hydrate dissociation and reduction of polymer mobility in the porous bed as compared to higher injection rate. The technical requirements for the success of polymer flooding for enhanced oil recovery from matured crude oil reservoirs involves: piston-like displacement, reduced viscous fingering, reduced mobility, and higher residence time in the


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crude oil reservoirs,58,59,61,73 and as observed from this study, the same holds true even for polymer flooding from hydrate bearing sediment. Gas production ratios (GPR), effectiveness of inhibitor solution (Ɛinhibitor) and effectiveness of PEG (ƐPEG) have been determined for various polymer flooding cases using Eqs. 3-5, respectively, and are reported in Figure 9 and Table 3 along with selected literature data. From Figure 9, it has been observed that S1_PEG-200_0.2 mf and S1_PEG-200_0.4 mf are having almost equal GPR but the ƐPEG of S1_PEG-200_0.2 mf is very high as compared to S1_PEG-200_0.4 mf. So, PEG-200_0.2 mf can be considered as more effective polymer flooding agent as compared to PEG-200_0.4 mf for the studied hydrate system. From Table 3, it has been observed that PEG-200 aqueous system shows more GPR as compared to EG aqueous system.29 PEG-200 aqueous system at low (0.2) mass fraction shows 46.93% of gas production ratio as compared to 24.1% of EG aqueous system at comparatively high (0.3) mass fraction. In addition, 0.4 mass fraction of PEG-200 aqueous system shows higher GPR than 0.5 mass fraction of EG aqueous system. In general, both the inhibitor effectiveness and PEG effectiveness are found to be higher for the PEG-200_0.2 mf. So, it can be interpreted that PEG-200 act as a better polymer agent at lower concentration (0.2 mf). Furthermore, it can be noted that effectiveness of PEG200 is much better than the EG (Table 3) at higher concentrations. In this study, low concentrations of PEG have shown higher gas production ratio as compared to high concentrations of EG aqueous solution studied in the literature.29 This may be due to the fact that the polymer increases the viscosity of injection fluid (PEG aqueous solution), which in turn decreases the viscous fingering effect. Therefore, it helps to achieve piston type displacement of methane gas out of hydrate reservoir and increases the volumetric sweep efficiency.58,59,61,73 Moreover, Yuan et al.29 investigated a soaking type procedure using EG aqueous solution in which the injected EG might have got diluted due to the presence of


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water in the porous media after hydrate dissociation. However in our study, continuous injection of PEG aqueous solution has been performed, so that a dilution was not that predominantly restricting factor as compared to the work of Yuan et al.29 Both PEG effectiveness and inhibitor effectiveness are found to be significantly high for PEG as compared to EG.29,55 It has also been observed that the PEG-600 aqueous system showed very low GPR as compared to other inhibitor aqueous systems. Since, high molecular weight polymer (PEG600) is having higher viscosity than PEG-200 and EG due to which there is difficulty for PEG-600 solution in reaching out to the each micro-section of the porous bed increasing the inaccessible pore volume, thus reducing the hydrate-polymer interaction, hydrate dissociation, and recovery. This fact has also been confirmed based on the viscosity, TDS and electrical conductivity measurements as discussed later. It has also been said that higher molecular weight and viscosity of polymer solution are not even good for enhanced oil recovery from conventional crude oil reservoirs because they increases the inaccessible pore volume.58,59,74 Also, in our earlier study on bulk reactor system, PEG-600 aqueous solution have shown lower rate of dissociation for methane hydrate system under bulk conditions65 and thus, in this work PEG-600 results in lower methane gas production ratio as compared to other cases. Therefore, PEG-200 has been found to be more prominent polymer agent for methane gas production from methane hydrate bearing sediments as compared to EG and PEG-600 aqueous systems. In addition, PEG is having 208.15 K (-65 oC) freezing point, which is much lower than a commercial inhibitor, ethylene glycol (260.25 K, i.e., -12.9 oC), therefore polymer flooding containing PEG systems is more beneficial for production of gas from a very low temperature hydrate reservoirs.

3.4. Properties of PEG Aqueous Solutions before and after Polymer Flooding


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Table 4 shows measured properties such as, electrical conductivity and TDS of PEG aqueous solutions before and after polymer flooding in the silica sand bed hydrate reservoir. Viscosity of different PEG aqueous solutions at various concentrations has also been shown in Table 2. It has been observed that the viscosity of PEG-600 aqueous solution at 277.15 K is higher than the PEG-200 aqueous solutions (0.2 mf and 0.4 mf). Due to higher viscosity of PEG-600, lower gas recovery was obtained from the hydrate bearing sands due to inefficient flooding in the pore spaces as compared to PEG-200. To confirm this, electrical conductivity measurements of polymer solutions have been performed before and after polymer flooding. The change in electrical conductivity is because of quartz, which is salinity independent, and possibly related to proton transfer directly on the mineral surface.75 It has been observed that electrical conductivity and TDS of PEG aqueous solutions increased significantly after the flooding (Table 4). This could be due to the presence of small sediment particles in the PEG aqueous solution after polymer flooding. Higher TDS concentration after polymer flooding correlates with higher concentration of minute silica particles in the produced PEG aqueous solution at the end of flooding process, which is due to the interaction of sand bed and PEG aqueous solutions.76 It is known that the electrical conductivity and TDS are directly proportional to each other.77 With increase in molecular weight and injection rate of PEG aqueous solution, the electrical conductivity and TDS got decreased (see Table 4). An increment of approximately 200% in electrical conductivity has been observed for PEG-200, while only 50 % change has been observed in case of PEG-600. In addition, similar observation has been found for TDS. This indicates that the PEG-600 solution was not effectively flooded in the porous bed as compared to PEG-200 aqueous solution. This has resulted in lower methane recovery (%) for PEG-600 as compared to PEG-200 as discussed earlier.


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CONCLUSION In this work, detailed experimental investigations on the methane production from hydrate bearing sediments has been carried out using PEG polymer flooding in a 3-D hydrate reactor. Initially, methane hydrate formation has been investigated using two silica sand porous beds [viz., S1 (0.16 mm) and S2 (0.46 mm)], and pure water at an initial hydrate formation pressure of 8 MPa and 277.15 K. Subsequently, hydrate dissociation studies have been carried out using polymer flooding at final hydrate reservoir pressure of ~4.3 MPa and 277.15 K. The effect of molecular weight (200 and 600 kg/kmol, vis., PEG-200 and PEG600, respectively), concentrations (0.2 and 0.4 mass fractions) and injection rates (1 and 5 mL/min) of PEG aqueous solution in methane hydrate reservoirs has been analysed for methane gas recovery. This work demonstrate that the methane recovery is higher for smaller particle size silica sand bed (S1) as compared to bigger particle size silica sand bed (S2). PEG-200 is observed to be an effective polymer agent for polymer flooding as compared to PEG-600 and the inhibitor used in the literature, such as ethylene glycol. In addition, high concentration of polymer at 0.4 mf for PEG-200 aqueous solutions provided higher methane recovery as compared to other combinations. Both the inhibitor effectiveness and PEG effectiveness are found to be higher for the PEG-200_0.2 mf as compared to PEG-200_04 mf, PEG-600_0.4 mf and other inhibitor used in the literature, such as ethylene glycol. So, it can be interpreted that PEG-200 act as a better polymer agent at lower concentration (0.2 mf). It has also been observed that lower injection rate (1 mL/min) was more effective in recovery of methane gas from simulated porous hydrate reservoir. This work provides practicable approach to use an environment friendly polymer for the development of an effective polymer flooding process for the production of methane gas from hydrate reservoir especially for low temperature and


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permafrost hydrate bearing zones. Polymer flooding could be an effective method for methane gas recovery from consolidated pore filling hydrate reservoirs.

Supporting Information The Supporting Information containing the details on the various methane hydrate formation experiments carried out in this work, along with various equations used for the calculation of moles of gas consumed during hydrate formation, and the final saturation of water, gas and hydrate in the porous silica sand beds, is available free of charge on the ACS Publications website..

Acknowledgement Dr. Jitendra S. Sangwai would like to acknowledge the financial support from IIT Madras as part of the Institute Research and Development Award (IRDA) – 2017 (ref.: OEC/17-18/835/RFIR/JITE) for the work.

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Table 1 Purities and suppliers of materials used for the studya

Chemical

Supplier

Purity

Methane

Bhuruka Gas Agency, Banglore

99.97 mol%

Merck, Mumbai

>0.99 mf

Merck, Mumbai

>0.99 mf

Polyethylene Glycol (PEG-200), 200 kg/kmol Polyethylene Glycol (PEG-600), 600 kg/kmol a

Deionized water was used in all the experiments.


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Table 2 Properties and experimental conditions of prepared artificial sand bed methane hydrate reservoir in the laboratory. SH: Hydrate saturation; SG: Gas saturation; SW: Water saturation. S1= 0.16 mm; S2 = 0.46 mm.

Nomenclature of Expt.

Experiments

Run

PEG Injection rate (mL/min)

#

Viscosity of PEG aqueous

Average

Reservoir pressure at the

solution at

temperature at the

start of polymer flooding

277.15 K ±1 K

start of polymer flooding (K)

(MPa)

SH#

SG#

SW#

(mPas)

1

S1_PEG-200_0.2 mf

1

8.72 ± 0.03

277.33

4.29

0.14

0.53

0.33

2

S1_PEG-200_0.2 mf

1

8.72 ± 0.03

276.01

4.16

0.14

0.54

0.32

3

S1_PEG-200_0.4 mf

1

16.75 ± 0.55

277.13

4.36

0.15

0.53

0.32

4

S1_PEG-200_0.4 mf

1

8.72 ± 0.03

277.38

4.35

0.15

0.53

0.32

5

S1_PEG-200_0.4 mf

5

16.75 ± 0.55

276.86

4.39

0.15

0.53

0.32

6

S1_PEG-600_0.4 mf

1

28.20 ± 0.05

276.46

4.36

0.15

0.53

0.32

7

S2_PEG-200_0.2 mf

1

8.72 ± 0.03

276.89

4.58

0.14

0.53

0.33

8

S2_PEG-200_0.2 mf

1

8.72 ± 0.03

277.36

4.42

0.14

0.53

0.33

Calculated using Eqs. S2, S4 and S6, respectively, as given in supporting information. 33

ACS Paragon Plus Environment

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Page 34 of 44

Table 3 Details on the gas production ratio (GPR), inhibitor effectiveness, PEG/EG effectiveness for methane recovery from hydrate reservoir. Nomenclature of

Porous bed

Inhibitor

Reservoir

Reservoir

Mass

Gas

Inhibitor

PEG/EG

Experiments

size

aqueous

temperature

pressure

fraction

production

effectiveness

effectiveness

(K)

(MPa)

ratio × 100

(Ɛinhibitor)#

(ƐPEG/ ƐEG)+

(mL/g)

(mL/g)

system

(mm)

(%)

Reference

S1_PEG-200_0.2 mf

0.16

PEG-200

277.15

4.3

0.2

46.93±0.013

54.76±1.30

273.48±6.5

This work

S1_PEG-200_0.4 mf

0.16

PEG-200

277.15

4.3

0.4

47.22±0.016

54.17±1.91

135.28±3.2

This work

S2_PEG-200_0.2 mf

0.46

PEG-200

277.15

4.3

0.2

29.28±0.007

34.55±0.65

172.55±4.7

This work

S1_PEG-600_0.4 mf

0.16

PEG-600

277.15

4.3

0.4

16.66

19.10

47.65

This work

#

---

0.38

EG

275.15

3.0

0.3

24.10

30.00

99.90

Yuan et al.2

---

0.38

EG

275.15

3.0

0.5

28.50

46.00

91.90

Yuan et al.2

---

0.30-0.45

EG

275.15

3.8

0.3

---

10.19

33.97

Li et al.55

---

0.30-0.45

EG

275.15

3.8

0.7

---

6.19

20.64

Li et al.55

mass of PEG/EG + water mass of pure PEG/EG

+

34


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Energy & Fuels

Table 4 Comparison of measured properties (TDS and electrical conductivity) of PEG aqueous solution before and after injection. Expt.

Nomenclature of

Porous

Polymer

Mass

PEG

Run

Experiments

bed size

system

fraction

Injection

of PEG

rate

(mm)

(mL/min)

Electrical conductivity (µS/cm)

Total dissolved solids (TDS) (ppm)

Before

After

flooding

flooding

% change

Before

After

flooding

flooding

% change

1

S1_PEG-200_0.2 mf

0.16

PEG-200

0.2

1

88.14

266.72

202.61

58.61

265.22

352.52

2

S1_PEG-200_0.2 mf

0.16

PEG-200

0.2

1

88.49

266.67

201.36

58.64

265.23

352.30

3

S1_PEG-200_0.4 mf

0.16

PEG-200

0.4

1

82.98

277.10

233.94

54.68

272.00

397.44

4

S1_PEG-200_0.4 mf

0.16

PEG-200

0.4

1

83.98

276.60

229.36

54.96

271.10

393.27

5

S1_PEG-200_0.4 mf

0.16

PEG-200

0.4

5

82.98

195.30

135.36

54.68

191.00

249.31

6

S1_PEG-600_0.4 mf

0.16

PEG-600

0.4

1

83.46

125.30

50.13

53.23

122.60

130.32

7

S2_PEG-200_0.2 mf

0.46

PEG-200

0.2

1

88.14

264.40

199.98

58.61

258.30

340.71

8

S2_PEG-200_0.2 mf

0.46

PEG-200

0.2

1

88.49

263.90

198.23

58.64

258.40

340.65

35


Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47

(a) 36


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Energy & Fuels

(b) Figure 1. Schematic diagram of the (a) 3-dimensional hydrate reactor and experimental setup used in this work; (b) reactor with RTD positions.


Energy & Fuels

9

300

S1 Porous bed

8

Hydrate induction

Pressure (MPa)

7 280

6 5

270

4 260

Pressure Temperature

3

Temperature (K)

290

2

250 0

5

10

15

Time (h)

20

(a) 9

300

S2 Porous bed first induction

8 7

second induction 280

6 5

270

4 260

Pressure Temperature

3

Temperature (K)

290

Pressure (MPa)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 38 of 44

250

2 0

5

10

15

20

Time (h) (b) Figure 2. Pressure-temperature profile during methane hydrate formation for (a) S1 porous bed (Expt. run 1, S1_PEG-200_0.2 mf); (b) S2 porous bed (Expt. run 7, S2_PEG200_0.2 mf). (Experimental run number as in Table S1 and Table 2). 38 ACS Paragon Plus Environment

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Energy & Fuels

Figure 3. Methane consumption profile of S1 and S2 bed (Expt. run 1, S1_PEG-200_0.2 mf and Expt. run 7, S1_PEG-200_0.2 mf).

Figure 4. Pressure rating (set pressure as shown by symbols) in the silica sand bed hydrate reactor during hydrate dissociation using various PEG aqueous solutions at different concentrations. Lines shows the equilibrium pressure at 277.15 K, - - - - 3.8 MPa for pure water; -

- - -, - - - -: 5 MPa for PEG-200_0.2 mf; - - - -: 6.5 MPa for PEG-600_0.4 mf;

- - - -: 8 MPa PEG-200_0.4 mf. Data from various literatures.1,64,65 39 ACS Paragon Plus Environment

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Figure 5. Temperature and pressure profile of the sand bed reactor during methane hydrate dissociation due to the injection of PEG-200 aqueous solution at 0.4 mass fraction (Expt. run 3, S1_PEG-200_04 mf).


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Energy & Fuels

(a)

(b) Figure 6. Distribution of temperature profile in the sand bed reactor during methane hydrate dissociation due to polymer flooding of various PEG aqueous solutions at different concentrations: (a) for the same sand-bed, S1 (Expt. runs 1, S1_PEG-200_0.2 mf; Expt. run 3, S1_PEG-200_0.4 mf and Expt. run 6, S1_PEG-600_0.4 mf); (b) comparison between sand beds S1 and S2 (Expt. runs 1, S1_PEG-200_0.2 mf and Expt. run 8, S2_PEG-200_0.2 mf).


Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Figure 7. Methane gas recovery using different PEG aqueous solutions for S1 and S2 porous bed.


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Energy & Fuels

(a)

(b)

Figure 8. Methane recovery (%) using different PEG aqueous solutions: (a) for S1 and S2 porous bed at the same injection rate of 1 mL/min; (b) for same porous bed (S1) at different injection rates (1 and 5 mL/min).


Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Figure 9. Comparison of gas production ratio (GPR) and PEG effectiveness of different PEG aqueous systems.

***


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Polymer Flooding in an Artificial Hydrate Bearing Sediments for

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