Beyond conventional methods for CO 2 capture and storage, a promising technology of sub-seabed CO 2 storage in the form of gas hydrate has come into the limelight nowadays. In order to estimate CO 2 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 CO 2 injection and CO 2 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 CO 2 reaction, free CO 2 , 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 CO 2 hydrate formation in the sediments with two-phase flow. For CO 2 storage capacity, a total amount of 15,000-ton CO 2 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 CO 2 could be stored in the sub-seabed sediments per year for a CO 2 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.
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 [
As the major cause for global warming, anthropogenic CO2 emission into the atmosphere has increased dramatically over the past few decades, and caused negative and irreversible effects on the environment and ecosystems [
A novel approach of sub-seabed CO2 storage in the form of gas hydrate attracts much attention nowadays [
Although the previous researchers have conducted a lot of studies on the topic of sub-seabed CO2 storage by gas hydrate, they mainly focused on the lab-scale experiments and simulations [
For the practical application of this new technology, a numerical simulator incorporated with an integrated model for CO2 hydrate formation in the sand sediments was developed in our previous study [
The numerical simulator used in this study was developed by modifying a gas-liquid two-phase flow code, TOUGH + HYDRATE v1.0 [
∂ ( ϕ ( S G ρ G X G H 2 O + S A ρ A X A H 2 O ) ) / ∂ t = F G X G H 2 O + F A X A H 2 O − Q H X H H 2 O , (1)
∂ ( ϕ ( S G ρ G X G CO 2 + S A ρ A X A CO 2 ) ) / ∂ t = F G X G CO 2 + F A X A CO 2 + J G + J A − Q H X H CO 2 + Q i n j CO 2 , (2)
∂ ( ϕ S H ρ H ) / ∂ t = Q H h y d , (3)
∂ ( ( 1 − ϕ ) ρ R C R T + ∑ β ≡ A , G , H ϕ S β ρ β U β ) / ∂ t = − λ m ∇ T + ∑ β ≡ A , G h β ( F β + J β ) + ∑ β ≡ A , G h β Q β + Q H Δ H H + Q s o l CO 2 Δ H s o l CO 2 , (4)
∂ ( ϕ S A ρ A X A CO 2 ) / ∂ t = Q s o l CO 2 + F A X A CO 2 + J A CO 2 − Q H X H CO 2 , (5)
where S β is the volume fraction (i.e. saturation) of phase β º A, G, H (m3/m3), ρ β is the density of phase β º A, G, H (kg/m3), and X β κ is the mass fraction of the component κ º H2O, CO2, hydrate in phase β º A, G, H (kg/kg). F β is the flux term of phase β º A, G (kg/m3/s), J β is the diffusion term of phase β º A, G (kg/m3/s), Q β is the source/sink term of phase β º A, G (kg/m3/s), h β is the specific enthalpy of phase β º A, G (J/kg), and U β is the specific internal energy of phase β º A, G, H (J/kg). P is the pressure (Pa), T is the absolute temperature (K), and λ m is the composite thermal conductivity (W/m/K). f is the porosity of the porous medium (−), ρ R is the density of the porous medium (kg/m3), and C R is the specific heat capacity of the porous medium (J/kg/K). Q H is the total hydrate formation rate (kg/m3/s), and Δ H H is the enthalpy change during hydrate formation/dissociation (J/kg). Q s o l CO 2 is CO2 dissolution rate in the aqueous phase (kg/m3/s), Δ H s o l CO 2 is the enthalpy change during CO2 dissolution (J/kg), and Q i n j CO 2 is CO2 injection rate (kg/m3/s).
As mentioned before, in our previous study [
Q H = δ Q H 1 + Q H 2 + Q H 3 , (6)
where δ is a switch to determine whether the gas front exists in a computational cell (δ = 1) or not (δ = 0). Q H 1 , Q H 2 , and Q H 3 are the corresponding hydrate formation rates on the gas front, on the hydrate film, and on the surface of the sand particles behind the gas front (kg/m3/s), respectively, which are given as below:
Q H 1 = M H k f x 1 A 1 ( f G CO 2 − f e q CO 2 ) + M H k f ( 1 − x 1 ) A 1 ( f I 1 CO 2 − f e q CO 2 ) − Q H 1 → 3 , (7)
Q H 2 = M H k f x 2 A 2 ( f G CO 2 − f e q CO 2 ) + M H k f ( 1 − x 2 ) A 2 ( f I 2 CO 2 − f e q CO 2 ) , (8)
Q H 3 = M H k f A S ( f A CO 2 − f e q CO 2 ) + δ Q H 1 → 3 , (9)
where M H is the molar mass of CO2 hydrate (kg/mol), and k f is the intrinsic rate constant of CO2 hydrate formation (mol/m2/Pa/s). x 1 and x 2 are the rupture ratios on the gas front and behind the gas front (−), respectively. A 1 , A 2 , and A S are the gas-liquid interfacial area on the gas front and behind the gas front, and the sand surface area (m2/m3), respectively. f G CO 2 , f A CO 2 , f e q CO 2 , f I 1 CO 2 , and f I 2 CO 2 are CO2 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. Q H 1 → 3 is the hydrate formation rate transferred from Q H 1 to Q H 3 (kg/m3/s). For each sub-model in this integrated model, one can find all the details in our previous study [
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
by Sun et al. [
In addition, an injection well is located at the center of the sediment model, which is used for CO2 injection. In order to determine the length of the injection part, the CO2 flow direction in the reservoir has been considered as a main factor in this study. After the injection, CO2 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 CO2 storage reservoir, the injected CO2 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 CO2 flow blockage. Based on this reason, the injection part is also set to be 100 m, which equals to the thickness of the CO2 storage reservoir, to ensure that CO2 can spread over a wide area after the injection, and flow smoothly in the reservoir without the CO2 flow blockage.
The pore water pressure of the sediment model is assumed to be hydrostatic, and the initial hydrostatic pore water pressure P p w (MPa) can be calculated according to the empirical equation as below [
P p w = P a t m + ρ s w g ( h + z ) × 10 − 6 , (10)
where P a t m is the standard atmospheric pressure (MPa), ρ s w is the sea water density (kg/m3), g is the gravitational acceleration (m/s2), 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) [
In order to estimate CO2 storage capacity in the sediment model built in this study, a proper CO2 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 CO2 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 CO2 reaction and hydrate formation. Besides, the injection period is set to be 150 days (nearly five months), so the total amounts of CO2 injection are 1500 ton, 7500 ton, and 15,000 ton, respectively.
Parameter | Value & Unit |
---|---|
Initial pressure condition in CO2 storage reservoir | 9.12 - 10.12 MPa |
Initial temperature condition in CO2 storage reservoir | 12.0˚C - 15.0˚C |
Porosity | 0.41 |
Intrinsic permeability of CO2 storage reservoir | 1.0 × 10−12 m2 (=1000 mD) |
Intrinsic permeability of overburden and underburden | 1.0 × 10−14 m2 (=10 mD) |
Initial water saturation | 1.00 m3/m3 |
Geothermal gradient | 30.0˚C/km |
Sea water density | 1022 kg/m3 |
Grain density | 2650 kg/m3 |
Grain specific heat | 792 J/kg/˚C |
Wet thermal conductivity of CO2 storage reservoir | 2.917 W/m/˚C |
Wet thermal conductivity of overburden and underburden | 1.7 W/m/˚C |
Dry thermal conductivity | 1.0 W/m/˚C |
By the integral of the mass rate of CO2 reaction, the amount of CO2 reaction over time can be obtained accordingly, as shown in
After the injection, a part of CO2 neither forms hydrate nor dissolves into the aqueous phase. Instead, it just remains in the reservoir as free CO2.
For the amount of CO2 hydrate formation in the reservoir, the curves in
Since the total amounts of CO2 reaction and CO2 hydrate formation are the largest in Case 3, this case has been extracted as a best case to investigate the behaviors of CO2 hydrate formation in the sediments with two-phase flow.
As can be seen in
of the injection well, especially at the depth of 895 - 910 m. This is because that after CO2 hydrate forms in the reservoir, the solid hydrate occupies the pore space of the sediments, and causes the reduction in the effective permeability, which will hinder the CO2 flow to a certain extent. As a result, the injected CO2 accumulates in the vicinity of the injection well, leading to the upward shift of the isopiestic lines as mentioned before. On the other hand, during the injection, the temperature jumps significantly in the reservoir, and a high temperature zone forms in the sediments, as shown in
In order to obtain a better understanding of the behaviors of CO2 hydrate formation in the sediments with two-phase flow, the evolutions of CO2 saturation, hydrate saturation, and water saturation over time are presented in Figures 3(d)-(f), respectively. As can been seen in
For the estimation of CO2 storage capacity in the real sub-seabed sediments by gas hydrate, a large-scale geological model simulating the real sub-seabed sediments in the ocean was built in this study, and numerical simulations of CO2 injection and CO2 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 ton/day, respectively. It is found that, at the injection rate of 100 ton/day, a total amount of 15,000-ton CO2 can be injected into the sediments for an injection period of 150 days. After the injection, a part of CO2 can be stored in the sediments in the form of gas hydrate, and the rest part remains in the reservoir as free CO2 or dissolves into the aqueous phase. For a CO2 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 CO2 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 CO2 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 CO2 hydrate formation heat and CO2 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, CO2 not only flows horizontally in the reservoir, but also flows upward due to the buoyancy. As a result, a small part of CO2 permeates into the overburden, forms hydrate, and serves as a self-sealing cap to restrain the further CO2 leakage. Although the long-term injection and monitoring are still needed to fully evaluate the potential and feasibility of the technology of sub-seabed CO2 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.
This work was supported by the Hirosaki University Grant for Exploratory Research by Young Scientists and Newly-appointed Scientists, and the Open Fund of Key Laboratory of Ocean Energy Utilization and Energy Conservation of Ministry of Education at Dalian University of Technology.
Yu, T., Sato, T. and Abudula, A. (2018) Estimation of CO2 Storage Capacity in the Real Sub-Seabed Sediments by Gas Hydrate. Journal of Flow Control, Measurement & Visualization, 6, 82-94. https://doi.org/10.4236/jfcmv.2018.62008