SIMULATION OF CH 4 PRODUCTION FROM SUBSEA GAS HYDRATE DEPOSITS COUPLED WITH CO 2 STORAGE

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1 Proceedings of the 7th International Conference on Gas Hydrates (ICGH 211), Edinburgh, Scotland, United Kingdom, July 17-21, 211. SIMULATION OF CH 4 PRODUCTION FROM SUBSEA GAS HYDRATE DEPOSITS COUPLED WITH CO 2 STORAGE Georg Janicki, Görge Deerberg, Stefan Schlüter, Torsten Hennig Fraunhofer Institute for Environmental, Safety, and Energy Technology UMSICHT, Process Technology, 4647 Oberhausen GERMANY ABSTRACT Natural Gas hydrates found worldwide in subsea sediments can be used as future energy resources. To increase their potential for energy applications today new technological approaches for the extraction of natural gas from gas hydrate deposits are being discussed and developed. The combustion of hydrate-based natural gas can contribute to the energy supply but the coupled CO 2 emission causes climate change effects. To develop a sustainable hydrate based energy supply system the sequestration of CO 2 has to be coupled with the CH 4 production from the hydrate deposit. Due to this demand the simultaneous storage of CO 2 in hydrate deposits has to be developed. From the thermodynamic point of view this process seems to be applicable because CO 2 hydrate is more stable than CH 4 hydrate. Regarding technological implementation many problems have to be overcome. Especially mixing, heat and mass transfer in the reservoir are limiting factors causing very long process times. Using numerical models for dynamic system simulations and analysis different technological approaches are evaluated and compared. Therefore, detailed mathematical models for most relevant chemical and physical effects are developed and implemented into simulation programs like CMG STARS and UMSICHT HyReS. By means of abstract scenarios, the effects occurring during gas production and CO 2 sequestration within a hydrate reservoir are identified and described. Relevant parameters such as pressure, temperature and hydrate saturation are discussed and compared for three cases: depressurization, CO 2 injection after depressurization and simultaneous methane production and CO 2 injection. Keywords: submarine gas hydrates, methane hydrates, carbon dioxide hydrates, natural gas production, CO 2 storage, simulation, CMG STARS NOMENCLATURE a, a volumetric interphase area [m 2 /m 3 ] c molar concentration [mole/m 3 ] g gravity constant [m/s 2 ] k dissociation constant [mole/(m 2 Pa s)] k dissociation constant [m/s] k rel relative permeability [1] K absolute/intrinsic permeability [m 2 ] N molar mass [mole] P pressure [Pa] R volumetric molar conversion rate [mole/(m 3 s)] R volumetric molar conversion rate [mole/(m 3 s)] S saturation [1] t time [s] u velocity [m/s] V volume [m 3 ] enthalpy of hydrate decomposition [kj/mole] f fluid porosity [1] dynamic viscosity [Pa s] Carman-Kozeny exponent [1] molar density [mole/m 3 ] Corresponding author: Phone: Fax georg.janicki@umsicht.fraunhofer.de

2 Indices * in equilibrium condition intrinsic/entry conditions phase abs absolute G gas phase H hydrate phase L liquid phase INTRODUCTION Ga s hydrates consist of cages formed by water and gas molecules wh ich are stable at high pressure and low temperature [1]. As can be seen in Figure 1, the conditions for hydrate formation depend on the gas (e. g. CH 4 or CO 2 ) and possible additives (e. g. NaCl) Salinity g/kg Salinity 35 g/kg Salinity 5 g/kg In the recent past, research has focused on the capture and storage of CO 2 from combustion processes (e.g. from CCS power plants) to reduce climate change. While different natural or manmade reservoirs like deep aquifers, exhausted oil and gas deposits or other geological formations are discussed for the storage of gaseous or liquid CO 2, the storage of CO 2 in a solid and immobile form as hydrate in sediments appears to be a promising alternative. In 28, the SU GAR project 1 was launched in Germany. The project aims at the extraction natural gas from marine methane hydrate deposits and the storage of CO 2 from power plants and other industrial sources as CO 2 hydrate in marine sediments. One of the working packages is concerned with the numerical simulation of the replacement of CH 4 hydrate by CO 2 hydrate. Some results will be presented in the sequel. 12 Pressure [bar] CH 4 hydrate CO 2 hydrate CO 2 (l) + H 2O CO2 (g) + H2O CH4 (g) + H2O Temperature [ C] Figure 1: Stability curves for CH 4 and CO 2 hydrates Natural gas hydrates can be found in regions of permafrost as well as in submarine sediments at depths below approx. 3 5 m. Figure 2: Burning methane from hydrate samples In recent years, the interest in methane hydrates as an energy source has increased around the globe. Plenty of hydrate reservoirs are assumed worldwide. Conservative estimates indicate that the content of included methane is two times larger than the methane equivalent of all fossil fuel (1. Gt carbon) [2]. Figure 3: Chart of the SUGAR project NATURAL GAS PRODUCTION FROM GAS HYDRATE DEPOSITS To benefit from the potential of methane hydrate as a source of fossil fuel, the captured natural gas has to be released from the solid structure. In general, three mechanisms exist to decompose a hydrate, that is to say an increase of temperature, a decrease of pressure or the addition of chemicals either to change stability conditions or to substitute methane by another gas, e.g. carbon dioxide. Depressurization By decreasing the pressure in a production well below the stability curve (Figure 1), methane hydrate begins to decompose. However, the release of methane gas from its hydrate consumes heat [3]. As a consequence, the reaction only 1 Submarine Gas Hydrate Reservoirs: Exploration, Exploitation and Transport.

3 continues until the temperature arrives at a new stability point on the curve. Th ermal stimulation The variety of measures to add heat to a hydrate layer for thermal destabilization ranges from injecting warm water or steam into a we ll over injecting fuel and oxygen to especially designed on-site combustion chambers up to electromagnetic heating of a particular region around a well. When injecting hot water or steam into a natural hydrate deposit, one has to take into account the loss of heat during the transport through pipes over a distance up to several hundreds of meters. Recently, Schicks et al. [4] suggested the in-situ catalytic oxidation of methane to supply the heat needed to decompose the hydrate. Compared with the depressurization approach there is no self-limiting mechanism as long as heat is continuously supplied. Injection of additives Inhibitors commonly are added to the gas streams in the oil and gas industry in order to prevent the built-up of hydrates capable of blocking the pipelines. The mechanisms are either to shift the thermodynamic equilibrium to a lower temperature or to a higher pressure respectively (thermodynamic inhibitor) or to influence the reaction kinetics (kinetic inhibitor). For instance, methanol, glycol and NaCl act as thermodynamic inhibitors [5, 6]. Kinetic inhibitors are polymerbased, and they interfere with the hydrate nucleation step and/or the crystal growth [7]. This is a good means to prevent hydrate formation during the residence time in a gas pipeline, but it has not yet been shown if it is applicable to destabilize hydrates that already exist. However, a continuous gas production by inhibitor injection requires an enhanced mass transfer of chemical inhibitors and the supply of heat, because of the endothermic hydrate dissociation reaction [8]. Replacement by CO 2 The combination of carbon dioxide sequestration with methane hydrate destabilization appears to be promising because carbon dioxide hydrate is more stable than methane hydrate. The process of hydrate forming is exothermal while the decomposition consumes energy. The reaction enthalpies lead to the conclusion that methane hydrate destabilization (H = kj/mole) [9] with simultaneous CO 2 hydrate formation (H = kj/mole) [1] works without further heat supply. As methane hydrates provide structural integrity and stability in their natural formation, incorporating CO 2 hydrates as substitutes for methane hydrates will help keeping the natural sediments stable. MODELING OF GAS HYDRATE IN SEDIMENTS Fluid flow The velocity of a fluid phase in the multiphase system is given by Darcy s law: k rel, K abs P u g (1) A change of the hydrate saturation in hydratebearing sediments affects the fluid flow of gas and water in the pores. With a decrease in hydrate saturation due to decomposition, permeability within the pore space increases such that fluid flow gets enhanced. On the other hand, increasing the hydrate saturation due to formation causes a decrease in permeability which hinders the fluid flow. The blocking of the flow path by gas hydrates is described by a Carman-Kozeny type equation: K 2 f 1 f abs f K f 1f (2) Here, K is the absolute permeability at initial conditions (hydrate saturation included) and f is the fluid porosity (exponent marks the initial state). Kinetics With CMG ST ARS formation and dissociation of hydrates are modeled by the Kim-Bishnoi kinetic approach: 1 N R k a P P V t Hyd *( H ) Hyd Hyd Hyd G G (3) Here, the gas phase fugacity, simplified as partial pressure difference, is used as the driving force. In UMSICHT HyReS an alternative modeling approach has been chosen:

4 N R k a c c V t 1 Hyd *( H ) Hyd Hyd Hyd L L (4) It assumes that the formation process is controlled by the liquid phase concentrations of the hydrateforming gas. In (4), the concentration c *( ) L is the liquid phase concentration of the gas component in thermodynamic equilibrium with the hydrate present in the volume. This equilibrium concentration is different from the solution equilibrium between gas and liquid phase (solubility). SIMULATION RESULTS For simulations, a simplified reservoir model built of layers with homogeneous properties for porosity, permeability and initial gas, liquid and hydrate saturations is used. In the simulations presented below, only the hydrate layer with noflow boundaries for mass and heat was considered. diameter of area height of area Parameter Value 1 m 2 m porosity of sediment.5 initial gas saturation.5 initial liquid saturation.55 initial methane hydrate saturation.4 initial pressure 72 bar initial temperature 1 C intrinsic permeability Table 1: Basic parameters 1 md The initial conditions are shown in Table 1. As initial pressure, the equilibrium pressure at a given temperature was chosen in order to avoid artificial hydrate formation or decomposition during the simulation run. While Case 1 was simulated with both simulation tools, CMG STARS was used for Case 2 and Case 3. Case 1 As a first case, a simple depressurization is simulated in a cylindrical region with a radius of 5 m and a height of 2 m. A single production we ll with a radius of.5 m is placed in the center. St arting from methane hydrate equilibrium conditions at about 72 bar and 1 C, the pressure at the well is lowered to 3 bar. Pressure [bar] months Figure 4: Pressure history (Case 1) Figure 4 shows the evolution of the pressure over the radius of the reservoir for the first three years of production. The pressure is decreasing slowly because of the restricted permeability of the formation. While the pressure around the well is decreasing, methane hydrate starts to decompose (Figure 6). At the same time, the temperature within the formation decreases (Figure 5). Only up to 1 m around the well, methane hydrate is completely destabilized after three years. Temperature [ C] xxxsaturation CH4 hydrate [-] xxx months Figure 5: Temperature history (Case 1) months Figure 6: CH 4 hydrate saturation history (Case 1)

5 Case 2 Case 2 is a continuation of Case 1. After three years of methane production, the well is closed and starts to work as an injection well for another three years. CO 2 is injected at a temperature of 1 C and a maximum rate of 8 Nm 3 /day. At the beginning of the injection phase, pressure and temperature start to increase close to the well due to the 1 C warm CO 2 and the exothermic formation of CO 2 hydrate (Figure 7 and Figure 8). Pressure [bar] Temperature [ C] Injection phase Production phase months Figure 7: Pressure history (Case 2) Injection phase Production phase months Figure 8: Temperature history (Case 2) During the production phase (first three years) the saturation of methane hydrate only decreased within a radius of few meters around the well (Figure 9). As soon as 1 C warm CO 2 is injected into the reservoir, methane hydrate continues decomposing within a greater radius. In the region of CO 2 hydrate formation, the (P,T)- conditions are below the methane hydrate stability curve. The driving force for methane hydrate decomposition is even greater than in the case of simple depressurization. After the injection phase, the volume free of methane hydrate has a radius of approx. 75 m. In addition, while CO 2 is injected, the gaseous methane is pushed away from the well into the (closed) reservoir, and - due to compression - secondary methane hydrate formation occurs. xxxsaturation CH4 hydrate [-] xxx months Figure 9: CH 4 hydrate saturation history (Case 2) Figure 1 illustrates the development of the CO 2 hydrate saturation for the period of injection. Within the first few meters, the saturation reaches values up to 7 % after three years of injection. At a distance of more than 5 m away from the borehole, the formation of CO 2 hydrate is very limited due to the governing conditions for pressure and temperature. As CO 2 migrates into the reservoir, CO 2 hydrate forms up to 4 % within a radius of 75 m around the injection well. xxxsaturation CO2 hydrate [-]xxx xxxsaturat ion CO2 hydrate xxx [-] months Figure 1: CO 2 hydrate saturation history (Case 2) Case 3 A Cartesian region with an edge length of 9 m and a height of 2 m was used to simulate CH 4 production and CO 2 storage at two different wells. St arting from hydrate equilibrium at 72 bar and 1 C the bottom hole pressure in the production we ll is lowered to 3 bar. Simultaneously, CO 2 is injected at a maximum rate of 8 Nm 3 /day at the injection well which is located 5 m apart from the production well.

6 The distributions of pressure (Figure 11), temperature (Figure 12) and hydrate saturations (Figure 13 and Figure 14) within the reservoir are shown for a period of three years. The figures are taken along the length axis through the wells which are positioned in the central layer in depthdirection. As observed in Case 1 and Case 2, the pressure around the production well (left hand side) is decreasing slowly (Figure 11). Since CO 2 is simultaneously injected at the injection well (right hand side), the pressure starts to increase at this location. Pressure [bar] Producer Injector months Figure 11: Pressure history (Case 3) very low in this case because the conditions are close to the stability curve of methane hydrate. On the other hand, injecting CO 2 at 1 C shifts the conditions in the reservoir to those where methane hydrate is no longer stable. The resulting driving force is greater and more hydrate can be destabilized. xxxsaturation CH4 hydrate [-] xxx Producer Injector months Figure 13: CH 4 hydrate saturation history (Case 3) Figure 14 shows the saturation of CO 2 hydrate. While CH 4 hydrate decomposes, CO 2 hydrate slowly forms around the injector. The asymmetrical shape of the curves at the injector indicates a flow towards the production well. Both CO 2 hydrate formation and CH 4 hydrate decomposition occur simultaneously and cause a heating of the reservoir at the injection well and a cooling around the production well (Figure 12). Temperature [ C] Producer Injector months Figure 12: Temperature history (Case 3) Figure 13 illustrates the methane hydrate saturation around both wells. As can be observed, the amount of methane hydrate that can be decomposed with simple depressurization is limited by the decreasing temperature and pressure. The driving force for decomposition is xxxsaturation CO2 hydrate [-]xxx Injector months Figure 14: CO 2 hydrate saturation history (Case 3) In Figure 15, the produced gas at the production we ll is plotted for a period of six years. As can be seen CO 2 arrives at the production well after approx. three years, and a low amount is produced together with the natural gas from the reservoir.

7 Cum. gas CH4 [x 1 6 Nm 3 ] Time [years] cum. gas all cum. gas CH4 cum. gas CO2 Figure 15: Gas production (Case 3) In Table 2, the simulation results for produced and injected gas after three years are compared. As can be seen, more gas can be produced in Case 3 than in Case 1 and Case 2. The extraction of methane gas seems to be enhanced by the more favorable conditions within the reservoir due to CO 2 injection. Since in Case 2 and Case 3 the injection rate was limited to 8 Nm 3 /day, the same amount of CO 2 was stored. Cumulative CH 4 production [x1 6 m 3 ] Cumulative CO 2 injection [x1 6 m 3 ] Case 1 Case 2 Case Table 2: Methane hydrate experiments CONCLUSION Within the scope of the SU GAR project, simulations of the production of methane gas from subsea gas hydrate deposits coupled with CO 2 storage are carried out. A commercial reservoir simulator (CMG ST ARS) and a scientific code (UMSICHT HyReS) are used as simulation tools. The latter includes an alternative kinetic model which assumes that formation and decomposition of hydrate are controlled by the liquid-phase concentration of the hydrate-forming gas. By means of three simplified scenarios, the limitations of gas production only by depressurization have been shown. As pressure is decreasing, methane hydrate starts to decompose, and the formation cools down until no more heat is available. For the given reservoir settings, the radius of complete methane hydrate decomposition Cum. gas CO2 [Nm 3 ] around the well is only about 1 m. As soon as heat is supplied to the reservoir, methane hydrate continues decomposing. It is shown that injecting 1 C warm CO 2 results in the decomposition of methane hydrate within a greater radius. The reason is that in the region of CO 2 injection and CO 2 hydrate formation, the conditions for methane hydrate become unfavourable. Furthermore, the simultaneous methane gas production and CO 2 injection in a two-well-setting wa s discussed. For an assumed distance of 5 m between the wells, only a small fraction of CO 2 is produced together with methane gas during the first six years. For a production period of three years, 35.4 million Nm 3 methane can be produced in Case 1 and Case 2 compared to 44. million Nm 3 in Case 3. In addition, an amount of 8.8 million Nm 3 CO 2 can be stored in the reservoir in hydrate form. REFERENCES [1] Sloan, E.D. Clathrate Hydrates: The Other Common Solid Water Phase. Industrial and Engineering Chemistry Research 2; 39, [2] Kvenvolden, K.A. Methane hydrate A major reservoir of carbon in the shallow geosphere?. Chemical Geology 1988; 71, [3] Goel, N. In situ methane hydrate dissociation with carbon dioxide sequestration: Current knowledge and issues. Journal of Petroleum Sc ience and Engineering 26; 51, [4] Schicks, J.M. et al. New Approaches for the Production of Hydrocarbons from Hydrate Bearing Sediments. Energies 211, 4, [5] Sira, J. H. et al. Study of hydrate dissociation by methanol and glycol injection. Society of petroleum engineers 199; [6] Kamath, V. A. et al. Experimental study of brine injection and depressurization methods for dissociation of gas hydrates. SPE Formation Evaluation 1991; 6(4), [7] Fu, B. The development of advanced kinetic hydrate inhibitors. In: Chemistry in the Oil Industry VII: Performance in a Challenging Environment 22; [8] Cranganu, C. In-situ thermal stimulation of gas hydrates. Journal of Petroleum Science and Engineering 29; 65, [9] Handa, Y. H. Compositions, enthalpies of dissociation, and heat capacities in the range 85 to 27 K for clathrate hydrates of methane, ethane,

8 and propane, and enthalpy of dissociation of isobutane hydrate, as determined by a heat-flow calorimeter. The Journal of Chemical Thermodynamics 1986; 18(1), [1] Kang, S. -P. et al. Enthalpies of dissociation of clathrate hydrates of carbon dioxide, nitrogen, (carbon dioxide + nitrogen), and (carbon dioxide + nitrogen + tetrahydrofuran). The Journal of Chemical Thermodynamics 21; 33(5), ACKNOWLEDGEMENT The support of our research activities by the German Federal Ministry of Economics and Technology and the German Federal Ministry of Education and Research within the SU GAR project framework is gratefully acknowledged.