Evaluation of the spread of acid-gas plumes injected in deep saline aquifers in western Canada as an analogue for CO2 injection into continental sedimentary basins

doi:10.1016/B978-008044704-9/50049-5

Greenhouse Gas Control Technologies 7

Proceedings of the 7th International Conference on Greenhouse Gas Control Technologies 5– September 2004, Vancouver, Canada

Volume I, 2005, Pages 479-487

https://doi.org/10.1016/B978-008044704-9/50049-5 Get rights and content

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Injection of CO₂ into deep saline aquifers in sedimentary basins appears to be an important means for reducing anthropogenic emissions of CO₂ into the atmosphere. In the design, approval and monitoring of such operations it is important to predict the evolution of the plume of injected CO₂ and identify potential leakage pathways. In mature sedimentary basins such as those in North America that underwent intense exploration for and production of hydrocarbons, the number and density of wells is extremely high, and a plume of injected CO₂ is likely to encounter many wells that have to be identified and monitored. Under these circumstances, running full-blown numerical models becomes impractical and resource intensive, and simpler and faster tools are needed. An analytical model has been developed that, under a set of simplifying assumptions, can provide a rapid estimate of the shape and extent of a plume of CO₂ injected into an aquifer. The method assumes constant gas properties, which is a valid assumption for a wide range of conditions found in sedimentary basins, and homogeneous and uniform aquifer properties, which, depending on scale, can be assumed for many aquifers at least in a statistical sense. The aquifer is assumed to be horizontal, and there is no mixing, diffusion or dissolution between the injected gas and formation water.

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Cited by (46)

Cooper Basin REM gas shales after CO<inf>2</inf> storage or acid reactions: Metal mobilisation and methane accessible pore changes
2023, International Journal of Coal Geology
Shale - water - CO₂ reactions may occur during CO₂ geological storage, enhanced gas recovery, enhanced oil recovery, or supercritical CO₂ fracturing. Shale-acid reactions occur during fracturing or acid stimulation. The mobilisation of metals from these processes can be an environmental concern if production water leaks or is released at surface. In addition, reactions may cause changes at the pore scale and affect gas or fluid flow. Three gas shales from the Australian Cooper Basin REM sequence were characterised for metals in minerals by synchrotron X-ray fluorescence microscopy. Metals including Zn, As, Ni, Cr were hosted in sphalerite associated with organic matter, Pb was in pyrite cement, and Mn was hosted in siderite. The shales were separately reacted with brine and supercritical CO₂, with CO₂-SO₂, with dilute HCl, or with N₂ at 100 °C and 20 MPa in batch reactors. The solution pH decreased during mineral reactions releasing metals to solution with the general concentrations from reaction with HCl > CO₂-SO₂ > CO₂ > N₂ and brine. Of the total available Pb, As, Li, and Zn in the shales, from 0 to 17%, 0.3 to 23%, 3 to 13%, and 0.4 to 28% was released to solution respectively. Corrosion of siderite and ankerite was observed after the CO₂ reactions, with precipitation of Fe-oxides. After CO₂-SO₂ reaction siderite and ankerite were dissolved with pyrite, barite, and Fe-rich precipitates. HCl reactions resulted in complete dissolution of carbonates, with dissolution pits and no mineral precipitation observed. The changes to the fractions of gas accessible mesopores were characterised by small angle neutron scattering (SANS). The Epsilon Formation had the greatest fraction of open accessible pores in the SANS range of 10 to 150 nm, followed by the Murteree and Roseneath shale samples. After CO₂ or CO₂-SO₂ reactions a small decrease in pore accessibility was more pronounced in the Murteree and Roseneath shales, consistent with mineral precipitation. HCl reaction resulted in opening of pores at 150 nm and closing of the smallest measured pores at 10 nm. Metals were mobilised from siderite, ankerite and sulphide minerals mainly, and were dependent on the mineral and metal content but also on the injected gas stream or fluid composition. CO₂ based fluids may result in cleaner flow back water, than HCl based fluids. Geochemical reactions during CO₂ storage or acid treatment in reactive shales cause pore changes that can affect gas migration. Mineral precipitation during CO₂ and CO₂-SO₂ reactions can result in favourable self-sealing.
Effects of impurities H<inf>2</inf>S and N<inf>2</inf> on CO<inf>2</inf> migration and dissolution in sedimentary geothermal reservoirs
2021, Journal of Hydrology
Citation Excerpt :
But to our best knowledge, there has no published study investigating the impurity effects on CO2 storage and utilization in CPG systems. Apart from some impurities, e.g., N2 and Ar, allowed for reducing the costs, some hazardous gases, like H2S and SO2, even have been co-injected with CO2 deliberately, because their emission into atmosphere would cause the formation of acid rain and damage to human health (Bachu and Gunter, 2005; Bachu et al., 2005). The light-impurity species, such as N2, by decreasing the density and viscosity of injected CO2 streams, would increase the buoyancy force of free-phase CO2 and accelerate its migration (Wang et al., 2011; IEAGHG, 2011; Yu et al., 2021).
CO₂ geological storage is a key technology for reducing greenhouse gas emissions. But merely injecting CO₂ into sedimentary strata has high costs and no direct economic benefit. A more cost-effective and environment-friendly way is storing and utilizing CO₂ in deep sedimentary reservoirs for heat extraction. However, the effects of ubiquitous impurities on the sequestration safety and heat extraction performance of CO₂ in high-temperature reservoirs, are unclear. In this study, we have performed numerical simulations of multiphase flow, solute transport, and heat conduction at reservoir temperature 50–250 °C, to reveal the effects of two common impurities (i.e., H₂S and N₂) on the migration, dissolution and thermal absorption of CO₂ in sedimentary geothermal reservoirs. It is found that, for higher reservoir temperature, the impurity N₂ leads to smaller promotion on the migration of gas phase, but retains the acceleration effect on the cooling in reservoir. Above 150 °C, the deviations on the gas phase migration velocity and the CO₂ dissolution efficiency caused by 10 mol% N₂ are less than 12%. Meanwhile, the 10 mol% N₂ can increase the total heat absorbed from reservoir by about 40% at least. It means that N₂ has the potential to benefit a CO₂ plume geothermal system significantly without distinct risks. Besides, it is also found that the CO₂ dissolution efficiency can be increased and decreased by H₂S and N₂ through partitioning phenomenon, respectively.
Design-of-experiment-based proxy models for the estimation of the amount of dissolved CO<inf>2</inf> in brine: A tool for screening of candidate aquifers in geo-sequestration
2017, International Journal of Greenhouse Gas Control
Citation Excerpt :
For example, Hassanzadeh et al. (2005, 2007) used this geometry with a square lengths of 5 m and 6 m respectively. After examining the proposed data by Bachu et al. (2005) regarding deep saline aquifers in Western Canada, we decided to use 10 m in this study, because it is the most frequent thickness of reservoir between these aquifers (7 of 24). One possible option for using these similar studies in the large scale application is consideration of a sink term in the proper location to account for the removal of CO2 due to dissolution (Green and Ennis-King, 2014; Pruess and Nordbotten, 2011).
In this study, a new tool for better estimation of CO₂ dissolution in aquifers is proposed. It will be shown that this model could increase the accuracy of the prediction considerably by involving all the effective parameters and their interaction through the design of experiments approach (response surface based on Box-Behnken method). It is also shown that the difference among previous proposed dimensionless models may be the result of the difference in the amount of dissolved CO₂ for a fixed value of the Rayleigh number. In other words, for different values of the Rayleigh number (the result of changes in different parameters), the same amount of CO₂ dissolution observed, but this would not be apparent in these models.
Another contribution of this work is summarizing the parameters involved by using appropriate thermodynamic correlations (pressure, temperature, salinity, porosity and permeability are all required factors). In addition, the dependency of fluid parameters on each other is considered during the study, through the thermodynamic correlations, and the effects of different parameters are studied simultaneously. The results indicate that salinity is the most important parameter in all the periods, while permeability is the most controlling parameter, after salinity, in the overall behaviour of the system. For all the periods, porosity and salinity have negative effects, while temperature and permeability have a positive influence. Although pressure has small negative impact on the diffusion coefficient and amount of dissolved CO₂ in the early period, it affects thermodynamic correlations (especially density difference between brine and brine + CO₂ solution), and its impact changes from negative to positive through the life-time of the sequestration.
Since, simulations are performed at discrete points of a continuous range of parameters in the development of the proxy models, Monte Carlo simulation was used to explore the whole range for the final conclusion. The closely similar behaviour of the Monte Carlo result curve and discrete points result, shows that the proxy models can be freely used in the selected ranges.
Flow regime analysis for geologic CO<inf>2</inf> sequestration and other subsurface fluid injections
2016, International Journal of Greenhouse Gas Control
Carbon dioxide (CO₂) injection into a confined saline aquifer may be modeled as an axisymmetric two-phase flow problem. Assuming the CO₂ and brine segregate quickly in the vertical direction due to strong buoyancy, and neglecting capillary pressure and miscibility, the lubrication approximation leads to a one-dimensional nonlinear advection-diffusion equation that describes the evolution of the sharp CO₂-brine interface. The interface evolution is driven by two forces: the force from fluid injection (the lateral pressure gradient due to injection), and buoyancy. Analytical solutions can be derived when one of the two forces is dominant. The solutions depend on the viscosity ratio ( $M$ ) between the displaced and injected fluids, and a buoyancy parameter ( $Γ$ ) that measures the relative importance of buoyancy compared to the driving force from injection. Different combinations of these two parameters give different forms of the solutions. But for all the solutions, the radius of the lateral spreading of the injected fluid follows, $r \propto t^{1 / 2}$ with the proportionality coefficient differing for the different solutions. In this paper, we identify the kinds of solutions appropriate for practical CO₂ injection projects as well as other subsurface fluid injection applications. We use data from eight CO₂ injection projects, twenty-four acid gas injection projects, two liquid waste disposal projects, and one CO₂-WAG enhanced oil recovery project. The solutions provide guidance for the expected behavior of fluid spreading under the different injection operations while providing general insights into overall fluid flow behavior.
Experimental study of density-driven convection effects on CO<inf>2</inf> dissolution rate in formation water for geological storage
2014, Journal of Natural Gas Science and Engineering
Citation Excerpt :
If we have the physical parameters expressed in Eq. (12), we can find an estimation of the convective mass flux of CO2, dissolved in each sequestration site, which would be helpful in examining the strength of candidate aquifer for CO2 geological storage. For examining the applicability of the presented scaling relationship, sample calculations for site number 11 in Alberta basin aquifers (Hassanzadeh et al., 2007; Bachu et al., 2005; Bachu and Carroll, 2005) with porosity equal to 0.09, permeability of 137 mD (assume isotropic), H∼60 m, Δρ = 4.1 kg/m3, μ = 0.36 × 10−3 Pa s, D = 7.6 × 10−9 m2/s, and ΔC = 660 mol/m3 were performed. Therefore, the Rayleigh number is ∼1359.
Permanent storage of CO₂ in saline aquifers is known as one of the best methods for carbon dioxide sequestration. Understanding the role of convection in CO₂ dissolution of saline aquifers – which affects the long-term fate of the injected CO₂ and the security of storage – is extremely important. In this paper, two types of experiments are performed; first, visualization experiment in Hele–Shaw cell; and second, quantitative experiments at elevated pressure. These experiments are used to investigate the effect of Density-Driven Convection (DDC) on CO₂ dissolution rate in saline aquifers. For this aim; first, visualization test is performed in a Hele–Shaw cell to observe convective instabilities and its effect on dissolution rate. Afterward, quantitative tests are performed, in which four parameters are calculated: Total Dissolution, Diffusion Dissolution (DD), Convection Dissolution (CD), and CO₂ Convective Flux (F_CO2). Through employing these parameters, the behavior of convection and its effects on CO₂ dissolution rate based on the scaled experiments is shown, and two scaling relationships one between Rayleigh and Sherwood number and the other one between CO₂ Convective Flux and Rayleigh number are developed. Such scaling relationships provide an estimation of the maximum convective dissolution of CO₂ in saline aquifers which would be useful for assessing suitable CO₂ storage sites.
Effect of exposure environment on the interactions between acid gas (H<inf>2</inf>S and CO<inf>2</inf>) and pozzolan-amended wellbore cement under acid gas co-sequestration conditions
2014, International Journal of Greenhouse Gas Control
Citation Excerpt :
In addition to pure CO2 injection, acid-gas (a mixture of CO2 and H2S) injection is also on the rise (Bachu and Gunter, 2004; Machel, 2005), so as to reduce atmospheric emissions of toxic H2S and reduce the cost to conduct surface desulfurization (Bachu et al., 2003). Acid gas injection is mainly employed to store H2S and CO2 separated from sour natural gas (Bachu and Carroll, 2005; Bachu et al., 2005). It could also be used to sequester H2S and CO2 from pre-combustion capture of carbon from coal-fired power plants (Kutchko et al., 2011).
Laboratory experiments were conducted to determine the effect of exposure environment on the integrity of pozzolan-amended Class H cement under geologic acid gas co-sequestration conditions. Cement was exposed to two potential subsurface storage environments: (1) a supercritical mixture of CO₂/H₂S and (2) a CO₂/H₂S saturated brine. Results show that cement alteration is dependent on the amount of pozzolan addition. The alteration rate and mechanism also differ for the two exposure scenarios. Cement containing 35% pozzolan amounts by volume (hereafter referred to as 35 vol% pozzolan cement) exposed to the aqueous environment was more vulnerable to alteration, compared with the same pozzolan content cement exposed to a supercritical mixture of CO₂/H₂S (21 mol% H₂S). Specifically, 35 vol% pozzolan cement exposed to the aqueous environment exhibited a higher level of mineral dissolution (e.g., C-S-H, 3CaO·SiO₂, 2CaO·SiO₂, etc.) and a higher degree of sulfur alteration than the same pozzolan content samples exposed to the supercritical mixture of CO₂–H₂S (21 mol% H₂S). Different from the 35 vol% pozzolan cement, the cement containing 65% pozzolan by volume (hereafter referred to as 65 vol% pozzolan cement) was more susceptible to alteration in the supercritical CO₂/H₂S (21 mol% H₂S) environment, compared with the same pozzolan content cement exposed to the aqueous environment. Increasing the H₂S mol% in the supercritical phase from 21 mol% to 40 mol% increased the alteration of cement exposed to both exposure environments. The 65 vol% pozzolan cement was more resistant to H₂S and CO₂ alteration than the 35 vol% pozzolan cement if the H₂S content was high (i.e., 40 mol%), while the 35 vol% pozzolan cement was more resistant to H₂S and CO₂ alteration than the 65 vol% pozzolan cement if the H₂S content was relatively low (i.e., 21 mol%). It was observed that while the two related exposure environments resulted in different degrees of cement alteration, the exposure environments did not result in the formation of different minerals.

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- Evaluation of the spread of acid-gas plumes injected in deep saline aquifers in western Canada as an analogue for CO2 injection into continental sedimentary basins

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- Evaluation of the spread of acid-gas plumes injected in deep saline aquifers in western Canada as an analogue for CO₂ injection into continental sedimentary basins