Energy Procedia 59 ( 2014 ) 82 – 89

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1876-6102 © 2014 Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/3.0/).Peer-review under responsibility of the Austrian Academy of Sciencesdoi: 10.1016/j.egypro.2014.10.352

European Geosciences Union General Assembly 2014, EGU 2014

Simulation of subsea gas hydrate exploitation Georg Janicki*, Stefan Schlüter, Torsten Hennig, Görge Deerberg

Fraunhofer Institute for Environmental, Safety, and Energy Technology UMSICHT, Processes, 46047 Oberhausen, Germany

Abstract

The recovery of methane from gas hydrate layers that have been detected in several subsea sediments and permafrost regions around the world is a promising perspective to overcome future shortages in natural gas supply. Being aware that conventional natural gas resources are limited, research is going on to develop required and sustainable technologies for the production of natural gas from such new sources since the early 1990s. In recent years, intensive research has focused on the capture and storage of CO2 from combustion processes to reduce climate impact. While different man-made or natural reservoirs like deep aquifers, exhausted oil and gas deposits or other geological formations are considered to store gaseous or liquid CO2, the storage of CO2 as hydrate in former methane hydrate deposits is another promising alternative. Due to beneficial stability conditions, methane recovery may be well combined with CO2 storage in the form of hydrates. Regarding technological implementation many problems have to be overcome. Within the scope of the German research project »SUGAR« different technological approaches for the optimized exploitation of gas hydrate deposits are evaluated and compared by means of dynamic system simulations and analysis. Detailed mathematical models for the most relevant chemical and physical processes are developed. The basic mechanisms of gas hydrate formation/ dissociation and heat and mass transport in porous media are considered and implemented into simulation programs. Simulations based on geological field data have been carried out. The effects occurring during gas production and CO2 storage within a hydrate deposit are identified and described for various scenarios. The behavior of relevant process parameters such as pressure, temperature and phase saturations is discussed for different strategies. Simulation results for different scenarios, e. g. simple depressurization and CO2 injection, reveal that both the production of natural gas and the CO2 storage are possible with acceptable rates. In case of simultaneous CO2 injection an increased production rate can be expected. The results strongly depend on deposit conditions, especially multiphase flow rates are dominated by permeability terms – in other words the reservoir permeability controls production and injection rates. Furthermore, the heat transport within heterogeneous layered deposits leads to enhanced hydrate decomposition and thus higher production rates.

* Corresponding author. Tel.: +49 208 8598-1420; fax: +49 208 8598-22-1420.

E-mail address: georg.janicki@umsicht.fraunhofer.de

© 2014 Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/3.0/).Peer-review under responsibility of the Austrian Academy of Sciences

Georg Janicki et al. / Energy Procedia 59 ( 2014 ) 82 – 89 83

Keywords: natural gas extraction; subsea gas hydrates; methane hydrates; CO2 hydrates; hydrate exploitation; numerical simulation; SUGAR; CMG STARS;carbon dioxide storage;

1. Introduction

Natural gas has gained in importance compared to other fossil energy carriers, because it is considered a relatively »clean« fuel for power generation, heating systems and as transport fuel. It enabled the development of modern power plants like gas and steam cogeneration plants and peak load power plants, and serves as hydrogen source for fuel cells and chemical processes. Besides the production of biogas the extraction of methane from hydrates is considered to be a promising way to overcome future shortages. Thus various research programs have been started since the early 1990s in Japan, USA, Canada, India and Germany to investigate hydrate deposits and develop technologies to destabilize the hydrates and obtain natural gas. To describe the methane production from subsea hydrate deposits and the replacement of methane by carbon dioxide a new scientific simulation model called HYRES-C was developed and implemented in COMSOL Multiphysics. In addition, the commercially available simulation tool STARS (CMG Ltd., Canada) was used. In the following, the results of the calculations based on particular reservoir parameters, reaction kinetics, and simple depressurization as well as CO2 injection are discussed.

1.1. Characteristics of gas hydrates

Gas hydrates are ice-like compounds of water and gas molecules. At gas specific conditions of low temperature and elevated pressure (Fig. 1, right) they form in an exothermal reaction. A lattice of water molecules encloses the gas molecules (Fig. 1, left). Generally, gas hydrates can contain different gases in different cage structures, depending on their size and given thermodynamic conditions. Methane – as the main component of natural gas – as well as other small hydrocarbons, carbon dioxide and hydrogen are some examples for hydrate formers. Additives can be used either to promote or to inhibit the formation. [1]

Fig. 1. (left) Hydrate structure (sI) and influencing factors; (right) Hydrate stability curves for methane and CO2 calculated according to [2–4].

Depending on the water temperature, the geothermal gradient and salinity methane hydrate can be found in subsea deposits at water depth beyond ~300 m (Fig. 2, left). They are wide-spread along all continental margins. To name only few states, India, Japan, China, Russia and the USA have different deposits of gas hydrates within their territories (Fig. 2, right).

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Fig. 2. (left) Stability zone of natural subsea gas hydrates [5]; (right) Natural hydrate deposits [6].

1.2. Potential of gas hydrates as a natural gas resource

In In recent years, the interest in methane hydrate as an energy resource has increased around the globe. During the last two decades, worldwide research has been going on to localize and characterize the vast amounts of natural gas trapped in methane hydrates in permafrost regions and subsea sediments. According to conservative estimates, the deposits contain around 10.000 Gt of carbon. Compared to the reserves of conventional fossil fuels (coal, oil and conventional natural gas) the carbon content of subsea gas hydrates is two to three times bigger. [7, 8]

To benefit from the huge potential the German project »SUGAR – Submarine Gas hydrate Reservoirs« was launched in 2008. Research institutes as well as partners from the industry are developing sustainable and feasible technologies related to subsea gas hydrates. An illustration of the activities within the project is shown in Fig. 3. Hydroacoustics, electromagnetics and autoclave drilling technologies are used and developed further for the exploration of submarine hydrate deposits. By means of numerical simulations and lab experiments an exploitation technology is developed and evaluated. Some simulation results are shown and discussed in this paper.

Fig. 3. (left) Activities within »SUGAR« project; (right) Project aims.

Georg Janicki et al. / Energy Procedia 59 ( 2014 ) 82 – 89 85

The project aims to produce natural gas from subsea methane hydrate deposits and to store carbon dioxide from power plants and other industrial sources as CO2 hydrate in subsea sediments, as shown in Fig. 3 (right).

According to the thermodynamic equilibrium data three destabilization mechanisms for methane hydrates exist in general, that is to say rise of temperature, decrease of pressure or the addition of chemicals either to change stability conditions or to substitute methane by another gas, e.g. carbon dioxide. A combination of these approaches may be also possible to destabilize hydrates and to recover the gas. The variety of measures to supply heat into a hydrate layer for thermal destabilization ranges from injecting warm water or steam into a well over injecting fuel and oxygen to especially designed onsite combustion chambers up to electromagnetic heating of a particular region around a well. Depressurization of a hydrate-bearing region is achieved by decreasing the pressure within the target layers by one or more wells. According to the equilibrium curve of methane (Fig. 1, right), lowering the pressure will shift the equilibrium to lower temperatures. However, the release of methane gas from its hydrate consumes heat [9] so that the reaction is self-limited and only continues until the temperature reaches the new equilibrium point. The destabilization by injecting additives is well known from conventional gas production, when inhibitors (e. g. methanol, glycol, salts and polymers) are added to the gas streams in order to prevent building up hydrates that could block the pipelines. This is a good measure to prevent hydrate building during the residence time in a gas pipeline, but it has to be shown whether this would help 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, as [10] pointed out, for the hydrate dissociation reaction is endothermic.

The combination of carbon dioxide storage with methane hydrate destabilization is considered to be promising because carbon dioxide hydrate is more stable than methane hydrate (see Fig. 1, right). Neglecting many unanswered questions the substitution seems to work and was proven in small scale lab experiments [9, 11–23]. The injected CO2 remains as immobile gas hydrate within the sediment and the former trapped methane is released and can be produced as free gas. In addition, the hydrate formation is exothermal while the destabilization reaction consumes energy. The reaction enthalpies lead to the conclusion that methane hydrate destabilization with simultaneous CO2 hydrate formation works without further heat supply. Some theoretical and experimental investigations, which showed that in the case of a mixture of methane and CO2 the formation of CO2 hydrate prevails over the formation of methane hydrate at certain conditions, are summarized by [9]. As methane hydrates provide structural integrity and stability in their natural formation, incorporating CO2 hydrates as substitutes for methane hydrates will help keeping the natural sediments stable. However, the optimum measure to replace methane hydrates by carbon dioxide hydrates has not been found yet.

Successful field tests in Canada, Alaska, and in Japan have shown that the production of natural gas from gas hydrates is technically feasible. In production tests in the Nankai Trough offshore Japan (2013) [24–26] and in Mallik, Canada (2008/2009) [27], natural gas hydrates were decomposed by lowering the reservoir pressure and methane was produced via a conventional well. During the production test in Prudhoe Bay, Alaska (2012) [28] a N2/CO2 mixture was injected to decompose methane hydrate and release natural gas. The produced natural gas consisted predominantly of methane, while the injected CO2 was fixed as the hydrate in the subsurface. Until now, the highest gas production rate of 20,000 STD m3 per day was achieved in the offshore field test in Japan.

2. Numerical simulation of hydrate exploitation

A case study for the Ulleung Basin in South Korea where gas hydrates has been found in turbidites has been carried out. At a water depth of more than 2,000 m these turbidites consist of alternating layers of clay and sand with different thermo- and fluid-dynamic properties (Fig. 4). For simplification only the target layers with higher hydrate saturation which is located at 135 m below the seabed has been regarded. In this hydrate dominated zone methane hydrate occur mainly in the sandy layers at saturations around 40 percent by volume.

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Fig. 4. Model of a layered hydrate deposit in Ulleung Basin, South Korea (UBGH 2-6) [29, 30].

Table 1. Basic parameter for simulation.

Parameter Value Parameter Value

Model area 500x500 m Initial CH4 hydrate saturation

0.40 (sand); 0 (clay)

Height 30 m Initial pressure Hydrate equilibrium P at given initial T (~190 bar at 17 °C)

Porosity 0.3 (sand); 0.5 (clay) Initial temperature 17 °C (at lowest layer)

Initial gas saturation 0.05 (sand); 0 (clay) Intrinsic permeability 1000 mD (sand); 2 mD (clay)

Initial water saturation 0.55 (sand); 1 (clay)

In one scenario a 500x500x30 m large area, which could be reduced by symmetry to a triangle with an edge

length of 250 m and height of 30 m was simulated in a Cartesian system, with is discussed here. Due to geothermal conditions in the Ulleung Basin the formation of CO2 hydrate is possible to a very limited extent. Therefore, only the production of gas by means of depressurization to 30 bar is considered here and no CO2 was injected. The initial conditions are given in Table 1.

To initialize the simulation run the initial temperature was determined according to the geothermal gradient over the height of the regarded layers. As initial pressure, the equilibrium pressure at resulting temperatures was chosen in order to avoid artificial hydrate formation or decomposition during the simulation run.

Fig. 5. Profiles of temperature (left), pressure (center), and methane hydrate saturation (right) for simple depressurization to 30 bar. (a) initial conditions; (b) conditions after 4 days; (c) conditions after 1 month; (d) conditions after 15 months

Georg Janicki et al. / Energy Procedia 59 ( 2014 ) 82 – 89 87

Fig. 5 shows the results of the simulation. Here, the profiles for temperature, pressure and methane hydrate saturation for the first 15 months after the start of depressurization to 30 bar are shown. The production well with a diameter of 7 inches is located at the left edge of each of the figures. Besides the distributions of temperature (left) and pressure (center) over the height Fig. 5 shows the methane hydrate saturation within the alternating layers (right). The hydrate-bearing layers with initially 40 percent by volume are in red. At the beginning of the simulation run (Fig. 5, a) the field is at initial conditions.

Caused by the depressurization in the production well at the left edge the pressure in the reservoir starts to decrease. After 4 days due to different characteristics of the individual clay and sand layers and the associated inhomogeneous mass and heat transport, slight differences in the vertical spread of pressure front which is propagating into the reservoir occur (Fig. 5, b, middle). As soon as the pressure within the reservoir comes under the hydrate equilibrium pressure, the endothermic hydrate decomposition begins around the well (right), which is associated with a decrease in temperature (left).

Over time, the low pressure propagates further into the reservoir (Fig. 5, c, middle). It can be seen that the horizontal pressure drop within the hydrate-bearing sandy layers is greater than within the tight clay layers. This effect can be explained from different layer permeability. In addition, changing permeability within the sandy layers, which is increased by the hydrate decomposition, intensifies the different behavior. Furthermore, continuous hydrate decomposition can be observed (right). It can be observed that on the one hand, the thin layers disappear completely and faster than thicker ones. On the other hand, the hydrate decomposition increasingly takes place on the edges of the sandy hydrate layers. This so-called »fingering« effect occurs as a result of warming up of these areas from the clay layers nearby. In addition, the heat transfer within the reservoir causes a slight temperature increase within the hydrate layers, where methane hydrate was already completely decomposed and no more energy is consumed (left).

Since sufficient energy in form of heat was present within the reservoir and was transported to the hydrate layers, the ongoing hydrate decomposition cannot absorb the energy from the system. Therefore, the equilibrium temperature at 30 bar (~1°C) is not reached and the decomposition process is not limited. Thus, the entire amount of methane hydrate disappears even before the expiry of 15 months (Fig. 5, d, right).

In a different scenario the simultaneous gas production and CO2 injection has been simulated at 10 °C and 80 bar as initial conditions in a homogeneous sediment layer. Further information about the model and the parameterization can be found e. g. in [31]. In a two-well approach at one well methane is produced by depressurization to 30 bar and at a second well CO2 is injected simultaneously at a rate of 8.000 STD m3 per day and 10 °C. The distance between the two wells is 500 m. Fig. 6 shows the results. It can be seen, that injecting CO2 into a methane hydrate reservoir can enhance the production of natural gas from hydrate deposits. As a reference case only the production by depressurization was simulated for 8 years, as shown here. In case of CO2 injection the production rate starts to increase after 3 years and more methane is produced after 8 years. In contrast, if warm water at same conditions is injected instead of CO2 the rate of gas production is decreasing significantly.

Fig. 6. Comparison of production rates for simple depressurization, CO2 injection and warm water injection (bold-rates, dashed-cumulated).

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3. Summary and conclusion

An immense amount of natural gas hydrates is presumed worldwide. The feasibility of methane recovery from hydrate deposits has already been proved in different numerical simulations and field tests. In addition, the feasibility of CO2 sequestration by injecting it into hydrate reservoirs and building up CO2 hydrate has been verified numerically and by means of laboratory tests so far. Within the scope of the German research project »SUGAR«, different technological approaches for the exploitation of natural gas hydrate deposits are evaluated and compared by means of dynamic system simulations and analysis. As part of the activities various scenarios has been numerically simulated using two simulation models (CMG STARS and HYRES-C).

The results presented here illustrate the processes and effects occurring during the gas production from a natural hydrate deposit by depressurization. Based on a case study for the Ulleung Basin in South Korea it can be shown that the hydrate decomposition and thus the gas production mainly depend on the mass and heat transport within the reservoir. In particular, the reservoir permeability and the available heat, which is required to decompose the hydrate, play an important role. Due to heat transfer into the hydrate-bearing layers local temperature decrease and the thermal »self-limitation« can be affected and thus more hydrate decomposes.

A second simulation case aims at the industrially relevant CO2 sequestration problem and is set up as a two-well scenario with simultaneous methane production and CO2 sequestration. Since the productivity depends on the pressure gradient driving force towards the production well, a local increase of pressure due to injection of CO2 leads to an enhanced gas rate (compared to the case without CO2 injection). The performed simulations show that depressurization with or without simultaneous CO2 injection is a practicable way to produce methane from subsea hydrate deposits with assured rates over many years.

Acknowledgements

The support of our research activities by the German Federal Ministry of Economics and Technology (BMWi) and the German Federal Ministry of Education and Research (BMBF) within the framework of the SUGAR project is gratefully acknowledged.

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