Novel Technological Approach To Enhance Methane Recovery from

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Novel Technological Approach to Enhance Methane Recovery from Class 2 Hydrate Deposits by Employing CO2 injection Prathyusha Sridhara, Brian J. Anderson, Nagasree Garapati, Yongkoo Seol, and Evgeniy M. Myshakin Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.7b03441 • Publication Date (Web): 05 Feb 2018 Downloaded from http://pubs.acs.org on February 22, 2018

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Novel Technological Approach to Enhance Methane Recovery from Class 2 Hydrate Deposits by Employing CO2 injection Prathyusha Sridhara,1,2 Brian J. Anderson,1,2 Nagasree Garapati,2 Yongkoo Seol,1 Evgeniy M. Myshakin1,3* 1

National Energy Technology Laboratory, 3610 Collins Ferry Road, P.O. Box 880, Morgantown, WV 26507, USA West Virginia University, Chemical Engineering, P.O. Box 6009, Morgantown, WV 26506, USA 3 AECOM, 626 Cochran’s Mill Road, P.O. Box 10940, Pittsburgh, PA 15236, USA * Corresponding author: [email protected] KEYWORDS. Numerical simulations, Class 2 gas hydrate accumulations, enhance gas recovery, carbon storage, carbon dioxide hydrate 2

ABSTRACT: Class 2 hydrate accumulations are characterized by the presence of an aquifer underneath hydrate bearing sediment. Gas extraction from of these hydrate deposits is accompanied with release of large volumes of water that decreases gas production rates, imposes additional load on the lifting system, and, as a result, degrades economical attractiveness of possible exploitation sites. This work studies enhanced methane production from Class 2 hydrate accumulations using the CO2-assisted technique where the aquifer serves as a target zone for CO2 injection. The heat release associated with the CO2 hydrate formation and reduction of the aquifer’s permeability benefit the subsequent decomposition of the overlying methane hydrate. The new production technique includes three stages utilizing one vertical well, which serves as an injector during the first stage and as a producer in the third stage. First, the CO2 is injected into the underlying aquifer, then the well is shut down and injected CO2 is converted into hydrate during the second stage. In the third stage, decomposition of CH4 hydrate is induced by the depressurization method to estimate gas production potential over 15 years. The results reveal that methane production is increased together with simultaneous reduction of concomitant water production comparing to production from the Class 2 reservoir using only conventional depressurization.

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1. INTRODUCTION Gas hydrates are non-stoichiometric crystalline solids composed of natural gas molecules trapped inside the cages formed by hydrogen-bonded water molecules.1 Methane hydrate deposits are found in abundance around the globe in the regions of permafrost and the margins of continental shelves, where the thermodynamic conditions and adequate availability of natural gas and water favor the formation of gas hydrate. There are several methods for recovering natural gas from hydrate accumulations. Three methods include depressurization, thermal stimulation and chemical inhibitor injection. The fourth technique is an unconventional method of CO2-CH4 exchange in CH4 hydrate lattice.2 This technique offers a dual purpose of CH4 production and simultaneous sequestration of the greenhouse gas (CO2) in the geological formations in a form of the stable gas hydrate. The feasibility of the swapping process is owed to the following reasons, 1) CO2, CH4 and the mixtures of these gases form Structure I (sI) hydrate.1,3 This structural similarity maintains the host sediment integrity since swapping of CH4 by CO2 in the natural gas hydrate settings results in no lattice dimension change.4 2) CO2 hydrate is thermodynamically more stable than CH4 hydrate at temperatures and pressures typical for geological methane hydrate accumulations.5 The disadvantage of the method is related to low permeability of a hydrate-bearing formation making the migration of injected and released gases a slow process. In addition, CO2 cannot be directly injected into gas hydrate-bearing formations due to the ubiquitous presence of free water, as a result, complex mixed injectants are required.6 On the other hand, long-term storage of CO2 in the underground saline aquifers is a widely proposed approach to offset the alarming levels of CO2 in the atmosphere.7 Recently, the pilot project of CO2 injection into a saline aquifer was conducted in South-central Kansas at the rate of 120 metric ton /day.8 Unlike the CO2-CH4 swapping technique in CH4 hydrates,9 this work utilizes the CO2 injection into highly-permeable aquifer beneath methane hydrate-bearing sand (Class 2 hydrate accumulations10) to form stable CO2 hydrate with subsequent methane decomposition induced by the depressurization method. Class 2 hydrate deposits10 are one among the four types of gas hydrate accumulations present around the world both in permafrost and ocean settings. Moridis and Collett11 developed a classification system for naturally occurring gas hydrate deposits based on different phase (gas/water) distributions present in contact with the hydrate-bearing layer, which decides their gas recovery potential. Class 1 hydrate deposits are characterized by a hydrate-bearing layer underlain

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by a two-phase zone with mobile gas. In these deposits, the base of the hydrate-bearing layer is exactly at the bottom of hydrate stability zone (BHSZ). Class 2 geologic deposits are those in which the hydrate layer is underlain by water-saturated aquifer and Class 3 accumulations are composed of a hydrate layer sandwiched between low permeable shale formations. Class 4 hydrate accumulations typically found in marine sediments are characterized with low hydrate saturations and low permeability of hydrate-bearing sediments.12 Figure 1 shows aqueous phase distributions within Units D and C of the L-Pad methane hydrate accumulation at Prudhoe Bay Unit (PBU) on Alaska North Slope (ANS) indicating the contact of hydrate-bearing sand with water-bearing sand at a depth of 685 m.6 Interpretations of log data the “Mount Elbert” test site on ANS also suggest a realization of the hydratewater contact in the hydrate reservoir systems.14,15 Moreover, the short-term field tests carried at the Mallik Site, in the Mackenzie Delta, Northwest Territories, Canada, indicate that those hydrate deposits fall under the Class 2 accumulations.16

SA

Figure 1. Vertical cross-sections of water saturation (SA) distributions of Class 2 hydrate reservoir model in the Prudhoe-Bay L-Pad region.13

Boswell et al.17 indicate the occurrence of gas hydrate, free gas, and water in sand reservoirs within a variable sand−mud sequence for the Walker Ridge 313 site in the Gulf of Mexico. The presence of an aquifer poses a drawback of large volumes of water production. Numerical modeling of the Alaminos Canyon Block 818 #1 (‘‘Tigershark’’) hydrate reservoir in the Gulf of Mexico predicted that the proximity to the “infinite” aquifer prevents effective reservoir depressurization.18 The excessive flow of water in the production stream suppresses the gas release in the hydrate-bearing section of the reservoir. The low gas flow rates was also predicted in the other


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numerical studies for Class 2 reservoir models.19 Additionally, the excessive water production poses extra load on a wellbore lifting system that increases cost of gas production.20 The goal of this paper is to assess the feasibility of methane production from Class 2 hydrate deposits by means of CO2 injection into the underlying aquifer and subsequent CO2 conversion into immobile hydrate phase. Within the framework of the proposed approach, natural gas production enhancement from Class 2 hydrate deposits can be achieved by using the heat released during CO2 hydrate formation to support the methane hydrate decomposition reaction and by reducing unwanted water production from the aquifer that competes with methane flow at a producing wellbore. The production technique involves a three-stage approach using one vertical well, which serves as an injector in Stage I and as a producer in Stage III. As Stage I, liquid CO2 is injected into the mobile aqueous phase promoting the CO2 plume propagation within the aquifer. The pressure evolution is monitored within the aquifer and after its value reaches a certain threshold around the well, the injection is shut down to let the geothermal gradient shift the pressure / temperature conditions into the CO2 hydrate stability zone to initiate and maintain hydrate formation during Stage II. When the selected levels of CO2 hydrate saturations are reached across the boundary between the methane hydrate-bearing sand and water-bearing sand, the commencement of production stage (Stage III) takes place. Stage III designates the depressurization of the CH4 hydrate bearing deposits to predict gas and water production profiles over a 15-year period. Further, the conventional depressurization of a Class 2 hydrate deposits with the same parameters is considered to compare with the gas production predicted using the CO2-assisted technique. 2. NUMERICAL SIMULATIONS DETAILS 2.1. Reservoir Simulator – Mix3HydrateResSim There are a number of simulators capable of modeling complex behavior of methane hydrate reservoirs: CMG STARS,21 HydrateResSim,22 MH-21HYDRES,23 STOMP-HYD,24 TOUGH+HYDRATE,25 and others. HydrateResSim (HRS) is the open-source code available for the public through National Energy Technology Laboratory (NETL). Recently, HRS has been modified26 to include the model which accounts for formation and dissociation of ternary hydrates (CH4-CO2-N2 hydrate). The new code called Mix3HydrateResSim (Mix3HRS)26 allows distribution of six components (CH4, CO2, N2, H2O, water-soluble inhibitors and a heat pseudo-component) among


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four possible phases (gas, liquid, ice, and hydrate). Along with the phase equilibrium data, new primary variables are added for each phase state together with extra governing equations for CO2 and the other components. The mixed hydrate equilibrium pressure/temperature and cage occupancies obtained using the cell potential code27 are incorporated in Mix3HRS in a tabular form and a tri-linear interpolation is used to predict data at given conditions.28 The Mix3HRS code includes the equilibrium model considering the hydrate formation and dissociation as proceeding at equilibrium state, and the kinetic model governed by the kinetic equation of Clarke and Bishnoi.29 The kinetics plays an important role in prediction of gas production rates at a reactor core,30,31 but it is not a ratelimiting step for production at a reservoir scale that is controlled by mass- and heat-transfer.30 In this work the equilibrium model is chosen to conduct the simulations. 2.2. Reservoir Geometry and Stratigraphic Units The reservoir model considered in this work is axisymmetric representing a cylindrical domain tailored to study flow to the vertical well placed along the axis (Figure 2a). Taking advantage of the symmetry, the reservoir was simplified into a 2D model as a vertical cross-section (Figure 2b). Figure 2c shows the 2D model with stratigraphic units used in the simulation with the vertical well completed on the left side. Since the 2D model is designed to be a representative model of a Class 2 hydrate reservoir serving to assess viability of the new approach for enhanced gas production, the geometry and conditions are based on typical conditions and stratigraphic units that can be found in permafrost of ANS. The radial grid extends out to 500 m which is logarithmically distributed into 75 grid blocks, so the lowest rwell= 0.11 m and largest rx = 475 m ensuring fine discretization around the wellbore. The lateral distance is chosen to follow the typical value for a 2D hydrate reservoir model that insures the independence of the results from the lateral boundary position.32-35 The total thickness of the reservoir domain is 40 m. It consists of the sand sediment (20 m) bounded at the top and bottom by shale deposits (10 m each). The sand formation layer is split between the hydrate-bearing zone (13 m, Zone 1 in Figure 2c) and the water-bearing zone (7 m, Zone 2 in Figure 2c) representing a typical Class 2 hydrate accumulation.11 In the vertical direction the over- and underburden are discretized into sub-layers of 2 m thickness and the hydrate-bearing and water-bearing sands have sub-layers of 1 m thickness. The top and bottom boundaries of the reservoir are set at fixed tempera-


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ture conditions according to the geothermal gradient to provide heat communication with the reservoir with no mass flow allowed. The lateral boundaries are taken as impermeable for both heat and mass transfer. This assumption is based on typical hydrate depositions on ANS (including the L-Pad site) showing fault compartmentalization of the reservoirs.13,36 The lateral boundary setup is an important feature since hydraulic communication of a reservoir with open aquifer might deeply alter predictions.18 A vertical wellbore of radius 0.11 m is completed through the hydrate-bearing and water-bearing sand zones (Figure 2c).

(C)

Figure 2. (a, b) Radial reservoir grid domain; (c) The 2D radial model showing stratigraphic unit sequence. Red line is the vertical well completion.

2.3. Reservoir Properties and Initial Conditions


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The CH4 hydrate layer (Zone 1) extends from (true vertical) depth of 673 to 685 m and are typical to the geological hydrate settings on ANS.9 The hydrate-water contact is placed at a depth of 685 m similar to the PBU L-Pad hydrate deposit. For simplicity there is no dip implemented in the model and salinity of aqueous phase is assumed zero. The reservoir pressure and temperature conditions applied to the 2D model are typical to those existed on ANS.37 Homogeneous approximation of key reservoir parameters (intrinsic permeability, rock porosity, irreducible water saturation, etc.) is assumed in the simulations. The values of pertinent petrophysical parameters are tabulated below (Table 1). The composite thermal conductivity model is given by Equation 1. Permeability of the reservoir in its native state (while gas hydrate is present) is termed “initial (aqueous) effective permeability” (kieffA). The permeability of the reservoir without the gas hydrate presence is characterized with intrinsic permeability (kint). The relationship between effective and intrinsic permeability is determined using a relative permeability value calculated by the Brooks-Corey model38 (Equations 2-4). Pore space is divided between hydrate, aqueous, and gas phases and phase saturation changes (SH - hydrate, SG - gas, SA - water or liquid CO2) during hydrate decomposition / formation control mobile phase’s relative permeability and, consequently, effective permeability (keffA and keffG). The two-phase flow in porous media of a dissociating gas hydrate reservoir requires accounting for the capillary pressure that is modeled using the van Genuchten function40 (Equations 5-6). Initial pore pressure of the system is assumed to follow hydrostatic pressure distribution.41 Temperature of the reservoir is assigned based on the local geothermal gradient (0.033 °C/m37) of the ANS region. CH4 hydrate-bearing sand (Zone 1) is modeled as a two-phase system with aqueous phase (SA=0.3) in equilibrium with hydrate phase (SH=0.7). The mobile-water sand (Zone 2) and shale layers are saturated with aqueous phase only. The pressure and temperature conditions existed at the boundary between Zone 1 and Zone 2 correspond to the

BHSZ (Peq/Teq). Figure 3 displays initial pressure and temperature distributions in the reservoir before the beginning of Stage I.


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Figure 3. Initial pressure (a) and temperature (b) distributions in the reservoir model.

Composite thermal conductivity function:22

(1)

where, kΘ, kdry, kwet, kH, kI are composite, dry, wet, hydrate, and ice thermal conductivity, respectively; SA, SH, SI are aqueous (water and/or CO2), hydrate, and ice saturations, respectively; φ is porosity; thermal conductivity for CO2 hydrate and methane hydrate is assumed the same, 0.45 W/mK.1 Brooks and Corey relative permeability function:38

k rA = (S A* ) n ; k rG = ( S G* ) n

(2)

( S − S irG ) (S A − SirA ) ; S G* = G (3) (1 − S irA ) (1 − S irG ) where, krA and krG are relative permeability of aqueous and gas phases, respectively; SA and SG are aqueous and gas saturations, respectively; SirA = 0.10 and SirG = 0.001 are aqueous and gas saturation, n =3 [Ref. 39].

S A* =

;

(4)

where, keffA and keffG are effective permeability of aqueous and gas phases, respectively, kint is intrinsic permeability of porous media Van Genuchten capillary pressure function:40

[

]

Pcap = − P ( S * ) −1 / λ − 1

λ

(5)

( S A − S irA ) (6) ( S max A − S irA ) where, λ= 0.45 [Ref. 26], P = 1.25 × 104 Pa is maximum pressure [Ref. 26], SmaxA = 1, SirA= 0.09 is set below the value for the relative permeability function to avoid infinite Pcap at SA = SirA. S* =


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Table 1. Initial pertinent petrophysical parameters used in the simulations. Unit

Porosity, φ (%)

Methane hydrate saturation, SH

Intrinsic permeability, kint (md)*

Initial effective permeability, kieffA (md)*

Composite thermal conductivity, K (W/m K)**

Pore compressibility, αP (Pa-1)

Rock specific heat, ∆H (J/kg ˚C)

Rock grain density, ρ (kg/m3)

Zone 1

35

0.7

1000 /100

11 / 1.1

0.5 / 3.1

5.0×10-10

1000

2600

Zone 2

35

0

1000 /100

1000 /100

0.5 / 3.1

5.0×10-10

1000

2600

Shale

10

0

1 / 0.1

1 / 0.1

0.5 / 3.1

5.0×10-10

1000

2600

* horizontal/vertical; ** dry/wet36


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2.4. Production Scenario The simulation approach is conducted in a 'huff and puff' style with a single vertical wellbore. During Stage I, liquid CO2 is injected through the perforated zone into Zone 2 representing water-bearing sand (Figure 4a). As initial conditions in Zone 2 are within CO2 hydrate stability zone, in order to avoid immediate formation of hydrate phase, CO2 is injected in the aquifer at an elevated temperature of 13 oC. The issue of maintaining stable CO2 phase during its trip down the wellbore should be addressed at a field test site. The injection is continued until the onset of CO2 hydrate formation at the advancing front of the injected fluid in Zone 2. At Stage II the wellbore is shut-off and the system is set to be driven to a steady-state to reinstate the geothermal gradient. At a field test site the perforated interval of the well casing dedicated for injection can be closed via insertion of cement or some other solidifying agent to the bottom of the well bore. Stage II is intended to bring the thermodynamic conditions in Zone 2 back into the CO2 hydrate stability regime to induce and maintain the CO2 hydrate formation reaction (Figure 4b). In the Stage III, the dissociation of CH4 hydrate present in the Zone 1 is initiated by the depressurization method using the well interval perforated throughout Zone 1 (Figure 4c). The methane hydrate decomposition benefits from (conductive and advective) heat transport from Zone 2. Heat accumulated in Zone 2 during first two stages from injected liquid CO2, exothermic nature of CO2 dissolution in aqueous phase, and the CO2 hydrate formation reaction was mainly supplied in Stage III from the continuous CO2 hydrate formation reaction. Hence, along with depressurization, this technological approach uses an in situ thermal stimulation which supports the endothermic reaction of CH4 hydrate decomposition into gas and water. The stages are described in detail in the following sections.


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heat

(a)

(b)

heat

(c) Figure 3. Pictorial representation of the technological approach which consists of (a) Stage I, (b) Stage II and (c) Stage III.

3. RESULTS 3.1. Stage I: CO2 Injection CO2 is injected for a period of 145 days at a constant flow rate of 162 metric ton/day (82 x 103 ST m3/day) and with the specific enthalpy of –252.5 kJ/kg (appr. 13°C). The rate was selected to maintain the wellbore integrity


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given the maximum pressure buildup during injection. In 2012, during the Ignik-Sikumi field test, ConocoPhilips conducted the step rate test to measure the Formation Parting Pressure (FPP) of the in situ hydrate sediments located at PBU on the Alaska North Slope. FPP denotes the pressure which initiates formation fracture and for this work its value was calculated to be 9.86 MPa.9 Thus, in the simulations, the injection flow rate is selected such that the pressure build up around the wellbore remains lower than fracture initiation pressure (9.86 MPa). It should be noted that the chosen pressure threshold was measured for hydrate-bearing sand while initially Zone 2 consists of hydrate-free sand saturated with water at the depths similar to those in the field test.37 The loss of stiffness could lead to adjustment of that FPP and the current value is taken as an approximation. According to the initial pressure distribution in Zone 2 (Figure 3), the temperature of injected CO2 must be greater than 10°C26 to ensure that no CO2 hydrate forms around the wellbore and plugs pathways for CO2 plume propagation in the aquifer. Figure 5 shows the pressure build up around the wellbore (at the grid block adjacent to the wellbore and the boundary between Zone 1 and Zone 2) during 145 days of Stage I. After that period, hydrate formation is evolved at the propagating CO2 plume front in Zone 2 and injection is stopped. The predicted pressure around the wellbore, 9.05 MPa, is still below the estimated threshold, 9.86 MPa. During the injection period a total of 23,490 metric tons of CO2 is injected.

Figure 4. Pressure profile near to the well-bore during Stage I.


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Figure 6 displays pressure, temperature, CO2, and water saturation distributions after 145 days of injection in the reservoir within first 140 m from the wellbore. As CO2 is injected, the plume displaces water, thus increasing CO2 saturation in the domain up to 0.7 (Figure 6c) in the vicinity of the wellbore. Figure 6b shows that there is a temperature increase in the reservoir as the CO2 plume advances. The reason for the temperature increase is due to: (1) the specific enthalpy of injected CO2; (2) exothermic nature of CO2 dissolution in water (CO2 (gas) → CO2 (aq); Q = -19.4 kJ/mol42 for pure water at 13 °C). Because of heat exchange with the surrounding strata, the temperature declines as the CO2 plume propagates in the reservoir (Figure 6b). In order to enable CO2 hydrate formation, the temperature should drop below 10.5 °C at the pressure range of 8-9 MPa as shown in the phase diagram in Figure 7 (point P1). The onset of CO2 hydrate formation predicted after 145 days at a radial distance of 85 m indicates the end of Stage I, the injection well is shut off. Hydrate formation causes heat release according to the enthalpy of the CO2 hydrate formation reaction43 that manifests itself as a local increase of temperature at the far boundary of the CO2 plume around 85 m from the wellbore (Figure 6b). Hydrate formation retards further flow of the fluid to the outer boundary of the reservoir because of sharp decrease in the aquifer’s permeability. The end of Stage I denotes the beginning of Stage II, wherein the temperature in the reservoir domain is set to decrease due to heat exchange with the surroundings.


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(a) P (kPa)

(b)

(c)

(d)

Figure 5. (a) pressure, (b) temperature, (c) CO2 saturation (the arrow indicates the distance at which hydrate formation start to evolve), and (d) water saturation distributions in the reservoir after 145 days of injection.


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Figure 6. Phase equilibrium diagram for the CO2/water/hydrate system, where I stands for ice, Lw means liquid water, V designates gaseous CO2, H is CO2 hydrate, and Lco2 is liquid CO2. Q1 and Q2 are quadruple points, P1 is the temperature required to start CO2 hydrate formation in the reservoir.

3.2. Stage II: CO2 hydrate formation This stage is intended to return temperature and pressure conditions within CO2 hydrate stability zone to enable CO2 hydrate formation in Zone 2. The formation reaction is accompanied with local temperature increase and heat removal is required to maintain the process. The over- and underburden set at fixed top and bottom boundary conditions act as heat sink and heat source, respectively to drive the reservoir to steady-state heat flow (the geothermal gradient). Figure 8 shows property distributions in the reservoir after 2.5 years of Stage II. Figure 8d indicates that CO2 hydrate starts forming at the top and bottom horizontal boundaries of Zone 2. The temperature and pressure distributions (Figures 8a and 8b) confirm that the thermodynamic conditions are within CO2 hydrate stability zone (Figure 7). The small pressure drop in Zone 1 shown in Figure 8a correlates with temperature perturbation in that area within first 120 m from the wellbore (Figure 8b). The analysis reveals that in that region methane hydrate exists at the three-phase equilibrium because the temperature increase drives CH4 hydrate to the instability. There is no noticeable extent of methane hydrate decomposition since the perforated interval for production (Figure 2c) is still closed for fluid withdrawal. The slight decomposition is accompanied with heat consumption that


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forces the system to attain new Peq/Teq down along the equilibrium curve. This process results in apparent pressure decrease depicted in Figure 8a. However, the gas release causes pressure increase with consequent hydrate reformation at the three-phase interface resulting in the decomposition/formation fluctuation. In the beginning of Stage II, temperature in Zone 2 is higher than in Zone 1 and underburden. As a result, Zone 1 and underburden act as heat sink promoting hydrate formation at the boundaries. In other words, the low permeable barriers between Zone 1 and Zone 2, and between Zone 2 and underburden are evolved within first hundred meters from the wellbore that hinder hydraulic communication between those units.

b)

a)

Zone 1

Zone 2

d)

c)

Zone 1

Zone 1

Zone 2

Zone 2

Figure 7. (a) pressure, (b) temperature, (c) CO2 saturation, and (d) CO2 hydrate saturation distributions in the reservoir after 2.5 years of Stage II.


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The development of a low permeable CO2 hydrate barrier serves both ways; it limits water production from the aquifer and carbon dioxide influx into Zone 1 to either be converted into mixed CO2/CH4 hydrate or be produced at the wellbore in Stage III. During Stage I and II, the CO2/CH4 exchange process occurs at the boundary between Zone 1 and Zone 2. Because the several orders of magnitude difference in effective permeability, leakage of CO2 into Zone 1 is very limited and emergence of mixed hydrate observed primarily within 1 m from the boundary. It should be noted that the exchange reaction is exothermic that brings additional heat into Zone 1 (enthalpy of CO2 hydrate formation is around -57.7 to -63.6 kJ/mol,43 while enthalpy of methane hydrate decomposition is estimated to be around 52.7 to 55.4 kJ/mol44). The methane hydrate decomposition due to pressure drop in Zone 1 (Figure 8a) is also limited because there is no open wellbore to remove fluids from the reservoir. To study the impact of Stage II’s duration on gas production in Stage III, three simulation cases are considered (Table 2). The main reason for considering these cases is to study the effect of CO2 hydrate evolution on the ability of Zone 2 to limit water inflow and to provide sustained heat flux into Zone 1. Cases 1-3 have duration of 2.5, 3.5 and 8 years, respectively. A base case (Case 4), which employs only depressurization of Zone 1, was considered for comparison with Cases 1-3. Besides varied CO2 hydrate saturation in Zone 2, Cases 1-3 are different by initial pressure/temperature conditions before the commencement of Stage III due to varied durations of Stage II (Table 2).

Table 2. The duration of stages for Cases 1-4. CO2 hydrate saturations are given for Zone 2 at the boundary with Zone 1 after Stage II. Case number / CO2 hydrate saturation

Stage I

Stage II

Stage III

Time, years

Case 1 / 0.7

0.45

2.5

15.0

Case 2 / 0.8

0.45

3.5

15.0

Case 3 / 0.9

0.45

8.0

15.0

Case 4 / 0.0

-

-

15.0

3.3. Stage III: CH4 Hydrate Decomposition


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The decomposition of methane hydrate in Zone 1 is induced by depressurization at constant bottom-hole pressure (BHP) set at 3.5 MPa (Teq = 3.06 oC). The BHP value and the temperature regime in Zone 1 and Zone 2 fall into the thermodynamic conditions corresponding to the shaded area in Figure 9. That area defines the P/T conditions where the CH4 hydrate is unstable and CO2 hydrate is stable. This ensures that the newly formed CO2 hydrate in the underlying aquifer remains intact during Stage III while CH4 hydrate breaks down and releases methane and water.

Figure 8. Phase equilibrium diagram for CO2/water/hydrate system and CH4/water/hydate system, where I stands for ice, Lw means liquid water, VCO2, VCH4 designates gaseous CO2 and CH4 respectively, HCO2, HCH4 are CO2 hydrate and CH4 hydrate respectively, Lco2 is liquid CO2. Q1 and Q2 are quadruple points. Doted lined represents the vapor-liquid phase boundary of CO2. The shaded region designates the region of CO2 hydrate stability and CH4 hydrate instability.

Figure 10 displays the cumulative volumes of produced methane and respective production rates for all cases for 15 years. Figure 10 shows that Cases 1-3 provide higher cumulative gas volumes over a 15 year period compared to Case 4 and consistently higher production rates over the first 7.5 years. Moreover, the total volume of CH4 produced in Case 2 is the highest compared to the remaining cases and the predicted cumulative gas volume is about twice more than that in Case 4 after 15 years. The results prove that the additional heat brought into Zone 1 during Stages I and II and lowering aquifer’s permeability promote enhancement of produced gas volumes. The predicted production rates for Cases 1-3 follow the similar trend. Amongst Cases 1-3, Case 3 displays higher production rates in the first year of production due to the highest initial temperature in Zone 1. In


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Case 3 the highest temperature is attributed to the longest Stage II resulting in more heat transfer to Zone 1 from Zone 2. However, as production continues, the Case 3 rate falls behind those in Cases 1 and 2. That is again related to the prolonged Stage II causing more CO2 to be converted into hydrate phase accompanied by dissipation of release heat. As a result, at the beginning of Stage III, less free CO2 is available for the formation reaction and heat flux to Zone 1 has to be delivered through the thicker CO2 hydrate layer since conversion occurs from the boundaries of Zone 2 to its center. This finding suggests a balance between the CO2 hydrate saturation at the boundaries to hinder water influx to Zone 1 and CO2 breakthrough to the producing well, and free CO2 availability to maintain hydrate formation reaction in Zone 2 that serves as “fuel” to support methane hydrate decomposition in Zone 1.

Figure 9. Gas production rates (dashed lines) and cumulative volume (solid lines) of gas produced for Cases 1-4. Time zero designates the onset of Stage III. Case 4 designates the case without Stage I and Stage II performed, only depressurization of Zone 1 at the same BHP as for Cases 1-3.

4. DISCUSSION 4.1. Analysis of Heat Flux The gas production rates for Cases 1-3 show a steep increase in the first 2-3 years of Stage III followed by a decline and a subsequent increase for the late period (Figure 10). The peaks of gas production rates are reached because of lowering the pressure gradient as the hydrate dissociation front moves away from the wellbore. The gas


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rates increase after 7-8 years of production for Cases 1-4 as temperature in Zone 1 lowers due to the continuous decomposition reaction, which induces additional heat flux from overburden. This is supported by Figure 11 showing a reverse of heat flow between Zone 1 and overburden after 9-10 years for Cases 1-2, and 4.

Figure 10. Heat flux across the upper boundary of Zone 1 during the Stage III for all Cases 1-4. A negative sign means heat flows from overburden to Zone 1.

The methane decomposition also benefits from supply of heat flux from Zone 2, where heat is generated due to series of processes taking place in Stages I-III. The heat flux attributed to conductive and advective heat transfer mechanisms during all the three stages across the bottom boundary of Zone 1 is shown in Figure 12. Here, time is set to zero at the beginning of Stage III. A major contribution to the heat transfer comes from conductive mechanism as it follows from the analysis given in Supplemental Material. The overall trend of the curves for all the cases correlates with production rate curves in Figure 10 that suggests that heat flux from Zone 2 is a major factor influencing production performance.


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Figure 11. Heat flux across the lower boundary of Zone 1 during the Stage I (dashed line), Stage II (dotted line) and Stage III (solid line) for Cases 1-4. A positive sign means heat flow from Zone 2 to Zone 1.

Figure 13 displays the hydrate saturation and temperature distributions in the reservoir during Stage III for Case 2. The temperature elevation in Zone 2 corresponds to evolution of CO2 hydrate saturation in the aquifer at different time points. In the beginning of Stage III, CO2 hydrate saturation reaches a value around 0.8-0.9 in the top and bottom layers of Zone 2 (Figure 13). With time, the inner areas of the aquifer become filled with CO2 hydrate that continuously releases heat transferred to Zone 1 primarily by the conductive mechanism.


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Figure 12. (a) hydrate saturations and (b) temperature distributions in the reservoir during Stage III for Case 2.

4.2. Effect of Reduced Water Flow on Methane Production Apart from the additional heat flux provided to the methane hydrate-bearing sediments, another factor contributing to the higher gas production in Cases 1-3 compared to Case 4 is originated from lowered water flow from Zone 2. Since water saturation and permeability of the aquifer decrease during Stages I and II in Cases 1-3 that lowers the competitive water flow to the producing Zone 1 in Stage III. Cumulative volumes of water produced throughout the production period and the corresponding water production rates are depicted in Figure 14. Water volume produced in Case 4 is similar to that in Case 2 even though Cases 2 provides two times more gas produced (and therefore more intensive hydrate decomposition generating more water release). In Case 4, high water production is attributed to the presence of the highly permeable aquifer underneath the methane hydrate formation. This is supported by Figure 15, which displays water flow across the bottom boundary of Zone 1. The sharp rise in water flow across the lower boundary for Case 4 shown in Figure 15 proves that during the initial 1 – 1.5 year of Stage III, the higher water production rates (Figure 14) is primarily connected to hydraulic communi-


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cation with aquifer. After approximately 4 years water production is flatten out into a nearly constant value for all cases.

Figure 13. Water production rates (dashed lines) and cumulative volume (solid lines) of water produced in Cases 1-4. Time zero designates the onset of Stage III.

Figure 14. Water flow across the bottom boundary of Zone 1 during Stage III for Cases 1-4. A positive sign means flow from Zone 2 to Zone 1.

4.3. CO2 Contamination of Producing Fluids Since mixing of the production fluids with CO2 is unwanted process, the concentrations of CH4 and CO2 in the produced mobile phases were recorded throughout 15 years of Stage III to monitor a contamination level. Figure


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16 shows the cumulative amounts of CO2 and CH4 produced during Stage III. Case 3, characterized with the highest initial CO2 hydrate saturation in the aquifer at the beginning of Stage III, produces the lowest volume of CO2. On the other hand, Case 1 displays the highest cumulative volume of CO2 correlating with the lowest initial CO2 hydrate saturation in the aquifer. However, in absolute values, the contribution of CO2 in the production fluids is negligible comparing to the total methane volumes. For Cases 1-3 it is estimated to be 0.02-0.04% on volume basis. In respect to the total injected CO2 (82 x 103 ST m3/day x 145 days = 1.189 x 107ST m3) the amounts of CO2 leakage are 0.07% (Case 1), 0.05% (Case 2), 0.02% (Case 3) on volume basis. Those low numbers are a consequence of two to three orders of magnitude reduction in effective permeability in Zone 2 at the boundary with Zone 1 due to CO2 hydrate formation.

Figure 15. Cumulative volumes of CH4 (solid lines) and CO2 (dashed lines) for Cases 1-3 in the production fluids.

4.4. Enhanced Gas Recovery from CH4 Hydrate Accumulation in Zone 1 The supply of additional heat flux to Zone 1 generates more sensible heat available for the methane hydrate decomposition reaction. The latent heat absorbed by the decomposition reaction serves a heat sink. The ratio of sensible heat to latent heat called the Stefan number (Ste)45 can be used to quantify the maximum hydrate recovery (the ratio of total volume of methane produced to the total volume of methane stored in a reservoir in a form of hydrate) under adiabatic conditions.


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The Stefan number is calculated using Equation 7, where averaged initial temperatures of the methane hydratebearing sand before the commencement of Stage III are used for the calculation. Stefan numbers are collected in Table 3 together with the average temperature in Zone 1 at the beginning of Stage III.

Cp∆T # S φ∆H

(7)

where ∆$ $ T % &'( ), Ti is average temperature in Zone 1, Teq = 3.06 oC is the equilibrium temperature at the BHP (3.5 MPa), ρ = 2600 kg/m3 is density of rock, ρH = 1000 kg/m3 is hydrate density, Cp = 1000 J/kg °C is specific heat of rock, SH = 0.7 is hydrate saturation, φ = 0.35 is porosity, ∆H = 477 kJ/kg is heat of decomposition

The increase of the average temperature from ∼5.0 oC (Case 4) to 7.3-7.5 oC (Cases 1-3) translates into the theoretical (adiabatic) recovery change from 0.044 (4.4%) to 0.099-0.103 (∼10.0%). Gas hydrate recovery is considered as the important criterion of reservoir performance. Table 3 also lists the calculated recovery factors based on the predicted total produced volumes of methane after 15 years of depressurization relative to the total amount of CH4 (as hydrate) initially present in the reservoir (4.55 x 108 m3). The best producing Case 2 results in two times more of recovery compared to the base Case 4. That is attributed to higher initial temperature in Zone 1 for Case 2 comparing to Case 4 at the beginning of Stage III (Table 3). Among Cases 1-3, the first two demonstrate better recovery because more free CO2 is available in Zone 2 than it is in Case 3 to maintain the CO2 hydrate formation reaction. As a result, during Stage III more effective heat transfer into Zone 1 in Cases 1 and 2 promptly offsets the effect of slightly larger initial temperature in Zone 2 in Case 3.

Table 3. Initial (averaged) temperature in CH4 hydrate-bearing sand before Stage III (Ti), Stefan numbers, total amount of CH4 produced at the end of 15 years of depressurization (V), and recovery factors for Cases 1-4. Case

T i, o C

Stefan number (Ste)

V, (108 m3)

Recovery Factor (%)

Case 1

7.28

0.103

0.234

5.14

Case 2

7.43

0.102

0.246

5.42

Case 3

7.47

0.099

0.139

3.06

Case 4

4.97

0.044

0.121

2.66

5. CONCLUSION The new methane production technique from a Class 2 hydrate reservoir is explored by means of numerical simulations. Liquid CO2 was injected into an aquifer underlying methane hydrate formation and transformed into im-


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mobile gas hydrate phase. The heat released due to conversion into CO2 hydrate was in part used to enhance the methane hydrate decomposition induced by depressurization. The reduced permeability of the aquifer due to hydrate formation also contributes to enhanced methane production by restricting unwanted water flow from the aquifer into the production well. The technological approach consists of three stages: In Stage I, CO2 is injected into the aquifer of the Class 2 hydrate accumulation. In Stage II, the well is shut down and reservoir is let cooling below equilibrium temperatures to enable and maintain the CO2 hydrate formation reaction. The duration of this stage is dictated by a balance between availability of free CO2 to be converted into hydrate phase and achieving sufficient hydrate saturation value to block breakthrough of CO2 into the production fluids during Stage III. In Stage III, methane hydrate is depressurized for 15 years to produce methane. CO2 hydrate saturation in pore space of the aquifer reaches 70-90% during Stage II that is accompanied with reduction of effective permeability to around 1-10 md, sufficient to keep the CO2 contamination of the producing methane within 0.04% on a volume basis. At the end of Stage III, the best case predicts twice more the cumulative produced methane volume in comparison with the case using only depressurization. The result confirms that thermal stimulations of Zone 1 during Stages I-III and lowering aquifer’s permeability promote enhancement of the Class 2 reservoir performance. As an additional benefit this novel gas production technique offers permanent carbon storage in a form of hydrates. Since gas hydrate represents a solid phase it naturally prevents CO2 leakage into the atmosphere under stable thermodynamic conditions in the underground formations.

Acknowledgments The authors are thankful to Dr. Ray Boswell (NETL) for fruitful discussions and comments on this paper. This technical effort was performed in support of the National Energy Technology Laboratory's ongoing research under the RES contract DE-FE0004000.

Disclaimer This project was funded by the Department of Energy, National Energy Technology Laboratory, an agency of the United States Government, through a support contract with AECOM. Neither the United States Government nor


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any agency thereof, nor any of their employees, nor AECOM, nor any of their employees, makes any warranty, expressed or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise, does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof.

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