Estimation of CO 2 Storage Capacity in the Real Sub-Seabed Sediments by Gas Hydrate *

Beyond conventional methods for CO2 capture and storage, a promising technology of sub-seabed CO2 storage in the form of gas hydrate has come into the limelight nowadays. In order to estimate CO2 storage capacity in the real sub-seabed sediments by gas hydrate, a large-scale geological model with the radius of 100 m and the thickness of 160 m was built in this study, and the processes of CO2 injection and CO2 hydrate formation in the sediments with two-phase flow were simulated numerically at three different injection rates of 10 ton/day, 50 ton/day, and 100 ton/day for an injection period of 150 days. Then, the evolutions of CO2 reaction, free CO2, and hydrate formation over time were analyzed quantitatively, and the spatial distributions of the physical properties in the sediments were presented to investigate the behaviors of CO2 hydrate formation in the sediments with two-phase flow. For CO2 storage capacity, a total amount of 15,000-ton CO2 can be stored safely in the sediments at the injection rate of 100 ton/day for 150 days, and a maximum amount of 36,500-ton CO2 could be stored in the sub-seabed sediments per year for a CO2 storage reservoir with the thickness of 100 m. For the practical scenario, an average value of 1 ton/day/m could be used to determine the actual injection rate based on the thickness of the real sub-seabed sediments.


Introduction
Global warming has been identified as one of the most serious global environmental issues for the last several decades.According to the Climate Change 2014 by IPCC [1], the globally averaged combined land and ocean surface temperature anomaly has risen by around 0.85˚C from 1880 to 2012.Moreover, it is likely to rise by 2.6˚C -4.8˚C by the end of the 21st century.As a result, the temperature rise causes the thaw of the mountain glaciers and snow cover globally, leading to the sea level change.Over the period from 1901 to 2010, the globally averaged sea level has risen by 0.19 m, and will further rise by around 0.07 -0.36 m by 2050, and around 0.09 -0.69 m by 2080 [2].
As the major cause for global warming, anthropogenic CO 2 emission into the atmosphere has increased dramatically over the past few decades, and caused negative and irreversible effects on the environment and ecosystems [1].In order to mitigate global warming, CO 2 capture and storage (CCS) is widely regarded as one of the most effective countermeasures for CO 2 emission reduction.
The conventional methods for CCS usually refer to CO 2 injection and storage into the deep saline aquifers onshore and shallow offshore [3] [4] [5] [6] [7], which have been considered as the main stream for CCS.However, there is a social concern about the stability and security of CO 2 storage in the deep saline aquifers [8].If the cap rocks above the reservoir crack due to the earthquake, the injected CO 2 may not be able to keep stable in the deep saline aquifers, and seep out of the cap rocks through the cracks.In the worst-case scenario, the injected CO 2 may leak into the ocean, and cause ocean acidification [9] [10] [11].
A novel approach of sub-seabed CO 2 storage in the form of gas hydrate attracts much attention nowadays [12].In this technology, the high-permeability sand layers surrounded by the low-permeability mud layers in the shallow sub-seabed sediments are selected as the target geological strata for CO 2 storage, because the sand layers can serve as the reservoir, and the mud layers can serve as the overburden and underburden to restrain CO 2 leakage.During the injection, CO 2 flows into the pore space of the sand layers, and forms CO 2 hydrate gradually with the underground water under low temperature and high pressure conditions.As a result, CO 2 can be trapped stably inside the solid hydrate, and the risk of CO 2 leakage can also be reduced greatly.However, there is also an obstacle for this new technology.After the injection, the permeability of the sand layers near the injection well will drop sharply due to the hydrate formation, which may cause the CO 2 flow blockage, and hinder the further CO 2 injection.Therefore, in order to store a large amount of CO 2 in the sub-seabed sediments by gas hydrate, it is important and essential to choose a proper CO 2 injection rate, and ensure CO 2 to spread over a wide area after the injection.
Although the previous researchers have conducted a lot of studies on the topic of sub-seabed CO 2 storage by gas hydrate, they mainly focused on the lab-scale experiments and simulations [13]- [18].The behaviors of CO 2 hydrate formation in the real sub-seabed sediments with two-phase flow still remain unknown, because few investigations have been dedicated to the large-scale simulations for a relatively long injection period measured by month.
For the practical application of this new technology, a numerical simulator incorporated with an integrated model for CO 2 hydrate formation in the sand sediments was developed in our previous study [19].Then, this simulator was employed to the experimental cases for the determination of the unknown model parameters.In this study, this simulator is applied to the numerical simulations of CO 2 injection and CO 2 hydrate formation in a large-scale geological model for an injection period as long as 150 days (nearly five months), to estimate CO 2 storage capacity in the real sub-seabed sediments by gas hydrate.

Governing Equations
The numerical simulator used in this study was developed by modifying a gas-liquid two-phase flow code, TOUGH + HYDRATE v1.0 [20].This improved simulator can describe the mass balance for water, gas, hydrate, heat, and CO 2 mass fraction in the aqueous phase using the finite difference method.In this simulator, a series of five primary variables (P, T, S A , S G , and ) are solved iteratively by Newton-Raphson Method using five governing equations (mass balance equations for aqueous, gas, and hydrate phases, heat balance equation, and CO 2 mass balance equation in the aqueous phase) as below, respectively [14]: CO CO ( ) , , ( ) where S β is the volume fraction (i.e.saturation) of phase β ≡ A, G, H (m 3 /m 3 ), β ρ is the density of phase β ≡ A, G, H (kg/m 3 ), and X κ β is the mass fraction of the component κ ≡ H 2 O, CO 2 , hydrate in phase β ≡ A, G, H (kg/kg). β F is the flux term of phase β ≡ A, G (kg/m 3 /s), β J is the diffusion term of phase β ≡ A, G (kg/m 3 /s), Q β is the source/sink term of phase β ≡ A, G (kg/m 3 /s), h β is the specific enthalpy of phase β ≡ A, G (J/kg), and U β is the specific internal energy of phase β ≡ A, G, H (J/kg). P is the pressure (Pa), T is the absolute temperature (K), and m λ is the composite thermal conductivity (W/m/K).φ is the po- rosity of the porous medium (−), R ρ is the density of the porous medium (kg/m 3 ), and R C is the specific heat capacity of the porous medium (J/kg/K).
H Q is the total hydrate formation rate (kg/m 3 /s), and Δ H H is the enthalpy change during hydrate formation/dissociation (J/kg).

CO2 Hydrate Formation Model
As mentioned before, in our previous study [19], an integrated model for CO 2 hydrate formation in the sand sediments was proposed to predict hydrate formation morphologies based on the formation locations in the sand sediments.In this model, CO 2 hydrate is assumed to form at three different locations in the sand sediments, and the total hydrate formation rate H Q is described as below: where δ is a switch to determine whether the gas front exists in a computational cell (δ = 1) or not (δ = 0).( ) 1 ( ) where H M is the molar mass of CO 2 hydrate (kg/mol), and f k is the intrinsic rate constant of CO 2 hydrate formation (mol/m 2 /Pa/s). 1 x and 2 x are the rupture ratios on the gas front and behind the gas front (−), respectively.1 A ,

2
A , and S A are the gas-liquid interfacial area on the gas front and behind the gas front, and the sand surface area (m 2 /m 3 ), respectively.
, and are CO 2 fugacity in the gas phase, in the aqueous phase, at the three-phase equilibrium point, at the gas-liquid interface on the gas front and behind the gas front (Pa), respectively.
For each sub-model in this integrated model, one can find all the details in our previous study [19].

Geological Model
For the large-scale geological model simulating the real sub-seabed sediments, an axisymmetric cylinder with a radius of 100 m and a thickness of 160 m is built in this study, as shown in Figure 1.This sediment model is assumed to be located at the depth of 870 -1030 m from the sea surface (at the water depth of 500 m), and divided into three domains from top to bottom: 1) overburden, 2) CO 2 storage reservoir, and 3) underburden.The CO 2 storage reservoir is set to be composed of sand layers with the thickness of 100 m, referring to the shallow reservoir (approximately 100 m thick) used for Tomakomai CCS Demonstration Project of Japan [21].The overburden and underburden are both set to be composed of mud layers with the thickness of 30 m.According to the previous report by Sun et al. [22], it may be sufficient for these 30-m-thick overburden and underburden layers to simulate the boundary effects of heat exchange and pressure propagation.
In addition, an injection well is located at the center of the sediment model, which is used for CO 2 injection.In order to determine the length of the injection part, the CO 2 flow direction in the reservoir has been considered as a main factor in this study.After the injection, CO 2 will not only flow horizontally in the reservoir, but also flow upward due to the buoyancy.If the length of the injection part is set to be smaller than the thickness of the CO 2 storage reservoir, the injected CO 2 may only distribute and form hydrate at the upper part of the reservoir, or in the vicinity of the injection well, which will increase the risk of the CO 2 flow blockage.Based on this reason, the injection part is also set to be 100 m, which equals to the thickness of the CO 2 storage reservoir, to ensure that CO 2 can spread over a wide area after the injection, and flow smoothly in the reservoir without the CO 2 flow blockage.

Computational Conditions
The pore water pressure of the sediment model is assumed to be hydrostatic, and the initial hydrostatic pore water pressure pw P (MPa) can be calculated ac- cording to the empirical equation as below [23]: ( ) where atm P is the standard atmospheric pressure (MPa), sw ρ is the sea water density (kg/m 3 ), g is the gravitational acceleration (m/s 2 ), h and z are the water depth, and the depth of the sediments from the seafloor (m), respectively.For the initial temperature condition in the sediment model, the geothermal gradient is taken into account.Other main physical properties of the sediment model refer to the field parameters used for the numerical simulations of gas production behavior from methane hydrate reservoir at the first offshore test site in the eastern Nankai Trough, Japan (2013) [22].The model parameters used in this study are listed in Table 1.It is worth mentioning that by the preliminary calculations, it is confirmed that the initial pressure and temperature conditions in the CO 2 storage reservoir are located within the hydrate stability zone according to the phase diagram of CO 2 hydrate proposed by Kamath [24].This indicates that the initial pressure and temperature conditions determined in this study are appropriate and suitable for CO 2 hydrate formation, and hydrate can form in the reservoir after the injection.Besides, the intrinsic permeability of the overburden and underburden is set to be 100 times smaller than that of the CO 2 storage reservoir, so that the overburden and underburden can both serve as the low-permeability layers to restrain CO 2 leakage.

Simulation Results and Discussion
In order to estimate CO 2 storage capacity in the sediment model built in this study, a proper CO 2 injection rate needs to be determined in advance.By the preliminary simulations, it is found that if the injection rate is set to be larger than 100 ton/day, the CO 2 flow blockage will occur at the early stage of the injection process.Therefore, three moderate injection rates of 10 ton/day, 50 ton/day, and 100 ton/day are chosen for Case 1 -Case 3.These three cases are also used for the sensitivity analysis to investigate the influence of the injection rate on the behaviors of CO 2 reaction and hydrate formation.Besides, the injection period is set to be 150 days (nearly five months), so the total amounts of CO 2 injection are 1500 ton, 7500 ton, and 15,000 ton, respectively.

Evolutions of CO2 Reaction, Free CO2, and Hydrate Formation in the Sediment Model
Figure 2 shows the evolutions of CO 2 reaction, free CO 2 , and hydrate formation in the sediment model during the whole injection period for Case 1 -Case 3.As can be observed in Figure 2(a), the mass rates of CO 2 reaction reach the peaks at the beginning of the injection process for all the three cases.The reason is that, as mentioned before, the initial pressure and temperature conditions in the CO 2 storage reservoir are suitable for CO 2 hydrate formation, and as soon as CO 2 is injected into the reservoir, it forms hydrate immediately, leading to the jump in the mass rate of CO 2 reaction.On the other hand, during the processes of CO 2 dissociation into the aqueous phase and CO 2 hydrate formation, a large amount of heat is released in a short time, resulting in the abrupt temperature rise in the sediments, which will have a negative effect on the further hydrate formation.
Therefore, the mass rate of CO 2 reaction drops sharply after the peaks, and the heat release decreases accordingly.This phenomenon repeats again and again, and it is the reason that there are many fluctuations on the curves of the mass rates of CO 2 reaction for all the three cases, especially in Case 3. In addition, it can also be seen that the larger the injection rate is, the more intense the fluctuations become, because the amount of heat release also becomes larger.During the whole injection period, the average mass rates of CO 2 reaction in the reservoir are approximately 0.20 ton/day, 0.90 ton/day, and 1.86 ton/day, respectively, for Case 1 -Case 3.
By the integral of the mass rate of CO 2 reaction, the amount of CO 2 reaction over time can be obtained accordingly, as shown in Figure 2 After the injection, a part of CO 2 neither forms hydrate nor dissolves into the aqueous phase.Instead, it just remains in the reservoir as free CO 2 .Figure 2(c) shows the amount of free CO 2 in the reservoir over time.As can be seen in the figure, there are also some fluctuations on the curves for all the three cases.
However, the fluctuations in Figure 2(c) are just opposite to those in Figure 2(b), because the more CO 2 participates in the reaction and forms hydrate, the less it will remain in the reservoir as free CO 2 .With the increase of the injection rate, the amount of free CO 2 also rises accordingly.By the end of the whole injection period, the total amount of free CO 2 in the reservoir reach approximately 104.2 ton, 646.3 ton, and 1310.2 ton, respectively, for Case 1 -Case 3.
T. Yu et al. closely related to the amount of CO 2 hydrate formation.Besides, it is clearly observed that the more CO 2 is injected into the reservoir, the more CO 2 hydrate forms.By the end of the whole injection period, the total amount of CO 2 hydrate formation in the reservoir reach approximately 110.5 ton, 462.7 ton, and 960.7 ton, respectively, for Case 1 -Case 3.

Spatial Distributions of Physical Properties in the Sediment Model
Since the total amounts of CO 2 reaction and CO 2 hydrate formation are the largest in Case 3, this case has been extracted as a best case to investigate the behaviors of CO 2 hydrate formation in the sediments with two-phase flow.Figure 3 shows the spatial distributions of the physical properties in the sediment model after 30 days, 90 days, and 150 days, respectively, for Case 3.
As can be seen in Figure 3(a), after the injection, the isopiestic lines in the sediment model have been disturbed, and showed an upward shift in the vicinity T. Yu et al.In order to obtain a better understanding of the behaviors of CO 2 hydrate formation in the sediments with two-phase flow, the evolutions of CO 2 saturation, hydrate saturation, and water saturation over time are presented in Figures 3(d)-(f), respectively.As can been seen in Figure 3(d), after the injection, CO 2 nearly moves horizontally in the reservoir, leading to the graded distribution of the CO 2 saturation in the radial direction.However, since the density of CO 2 is smaller than that of water, the injected CO 2 also flows upward gradually.Although the intrinsic permeability of the overburden and underburden is set to be 100 times smaller than that of the CO 2 storage reservoir, a small part of CO 2 still seeps out of the reservoir, and leaks into the overburden due to the buoyancy.
On the other hand, as shown in Figure 3(e), CO 2 hydrate forms gradually in the reservoir as a result of the suitable temperature and pressure conditions, and generates a lot of heat as mentioned before.This part of CO 2 hydrate formation heat, especially along with the large amount of CO 2 dissociation heat, has a negative effect on the further hydrate formation, so the hydrate saturation in the reservoir shows a trend of heterogeneous distribution.Meanwhile, since the temperature and pressure conditions in the overburden are also within the hydrate stability zone, most of the leaked CO 2 forms a thin layer of hydrate in the overburden, especially just above the injection well, where a high hydrate saturation spot can be observed clearly.This thin layer of hydrate may serve as a self-sealing cap, and restrain the further CO 2 leakage, so that the injected CO 2 can be stored safely in the sub-seabed sediments without leaking into the ocean.
Besides, after the injection, CO 2 pushes the aqueous phase forward in the radial direction, and a part of pore water is consumed to form hydrate, so the water saturation also displays a graded distribution, creating a low water saturation zone in the vicinity of the injection well, as shown in Figure 3(f).

Conclusions
For the estimation of CO  ton/day, respectively.It is found that, at the injection rate of 100 ton/day, a total amount of 15,000-ton CO 2 can be injected into the sediments for an injection period of 150 days.After the injection, a part of CO 2 can be stored in the sediments in the form of gas hydrate, and the rest part remains in the reservoir as free CO 2 or dissolves into the aqueous phase.For a CO 2 storage reservoir with the thickness of 100 m as built in this study, at the injection rate of 100 ton/day, i.e., averagely 1 ton/day/m, a maximum amount of 36,500-ton CO 2 could be injected and stored in the sub-seabed sediments per year.For the practical scenario, this average value of 1 ton/day/m could also be used to determine the actual injection rate based on the thickness of the real sub-seabed sediments.Moreover, in order to investigate the behaviors of CO 2 hydrate formation in the sediments with two-phase flow, the spatial distributions of the physical properties in the sediments over time were presented for the case of the injection rate of 100 ton/day.The simulation results indicate that during the injection process, a large amount of heat is released due to CO 2 hydrate formation heat and CO 2 dissociation heat into the aqueous phase, leading to a high temperature zone in the reservoir which has a negative effect on the hydrate formation.After the injection, CO 2 not only flows horizontally in the reservoir, but also flows upward due to the buoyancy.As a result, a small part of CO 2 permeates into the overburden, forms hydrate, and serves as a self-sealing cap to restrain the further CO 2 leakage.Although the long-term injection and monitoring are still needed to fully evaluate the potential and feasibility of the technology of sub-seabed CO 2 storage in the form of gas hydrate, it is reasonable to believe that this novel technology can be expected to be applied in the field demonstration in the future.

T.
Yu et al.DOI: 10.4236/jfcmv.2018.6200883 Journal of Flow Control, Measurement & Visualization the gas front, on the hydrate film, and on the surface of the sand particles behind the gas front (kg/m 3 /s), respectively, which are given as below:

Figure 1 .
Figure 1.Schematic diagram of the sub-seabed sediment model built in this study.
(b).Since the curves of the mass rates of CO 2 reaction are fluctuant in Figure2(a), the curves of the amount of CO 2 reaction are also fluctuant, especially in Case 3, and present linear behaviors by appearance for 150 days.If given a much longer injection period, the status in the sediments will get close to the CO 2 flow blockage gradually.As a result, the amount of CO 2 reaction may approach to a maximum value, and the curves may present exponential behaviors by appearance.By the end of the whole injection period of 150 days, the total amounts of CO 2 reaction in the reservoir reach approximately 32.9 ton, 138.0 ton, and 286.5 ton, respectively, for Case 1 -Case 3.

Figure 2 .
Figure 2. Evolutions of CO 2 reaction, free CO 2 , and hydrate formation in the sediment model during 150 days for Case 1 -Case 3. (a) The mass rate of CO 2 reaction [ton/day]; (b) The amount of CO 2 reaction [ton]; (c) The amount of free CO 2 [ton]; (d) The amount of CO 2 hydrate formation [ton].
jection and CO 2 hydrate formation in the sediments with two-phase flow were conducted at three different injection rates of 10 ton/day, 50 ton/day, and 100

Table 1 .
The physical properties of the sediment model.