A global assessment of deep-sea basalt sites for carbon sequestration

Difficulties in efficient DNA extraction from deep-sea volcanic basalt, due to high metal concentration, complex organic matter, or sometimes the low biomass, have hampered the understanding of the significant biosphere both at and below the sea floor. In order to optimize the DNA extraction from basaltic rocks, sterilized basalts with different particle sizes and chemically synthesized goethite were inoculated with an iron oxidizer Marinobacter aquaeolei and an extreme halophilic archaeon Halobaculum gomorrense respectively, and extracted with several methods. Large variations in DNA yields by different extracting methods including FastDNA® spin for soil kit, GeneClean® for ancient DNA kit, UltraClean™ and traditional phenol-chloroform methods. Among the commercially available kits tested here, FAST spin kit and GeneClean® for ancient DNA kit yield 10 times more DNA than the UltraClean™ kit used. In combination with FAST spin kit, skim milk greatly enhanced the archaeal DNA yields. DNA extracting efficiency was low with the cell number lower than 1 × 106 cells, but reached as high as 88% with a cell number of 1 × 108 cells. On these points, different strategies should be taken into consideration for the DNA extraction from basalts, depending on original biomass and cell types anticipated. FAST spin kit could provide high quality bacterial DNA for downstream PCR whilst the combination of FAST spin kit with skim milk would greatly enhance the archaeal DNA yields. GeneClean® for ancient DNA kit is also recommended for archaeal DNA extraction from deep sea basalt due to its high yield.

Geological storage of anthropogenic carbon dioxide is regarded as a technically and economically viable strategy for mitigating carbon dioxide induced climate warming. 
 
 Central to geological storage of anthropogenic carbon dioxide is the water rock interaction, which has a direct bearing on pH induced wettability evolution in saline aquifers. Consequently, understanding contact angle trend versus injected gas pressure is useful, considering its relationship to pH evolution in formation brine due to dissolved gas at prevailing temperatures and salinities. Several research works have published experimental data on contact angle versus pressure pertaining to geological conditions of anthropogenic carbon storage. In the present study, we have used thermodynamic theories relating to a surface charge model, contact angle and the classical Nernst equation to derive a logarithmic pH dependent contact angle equation. Considering the relationship between carbon dioxide solubility and pressure for a given temperature and salinity as well as the link between pH and the extent of solubility, we have plotted calculated contact angles versus corresponding pressures. Results of the plots obtained compare well with literature values. Therefore, given the lack of theoretical approach regarding contact angle versus pressure, our research work fills the knowledge gap considering the novelty in the derivation of the pH dependent contact angle equation.

To reduce current high concentrations of anthropogenic greenhouse gases in the atmosphere to levels stipulated by the Intergovernmental Panel on Climate Change, geological sequestration has been universally proposed. On the basis of cost analysis and global availability, deep saline aquifers are the prime targets for most proposed commercial and pilot scale projects.While the geological storage of anthropogenic carbon dioxide is expected to mitigate global warming, the technical aspects of the injection deserve to be considered for efficient injection projects. The water rock interaction phenomenon occurs due to carbonic acid generation which causes surface protonation reactions and has the potential to decrease water wettability of the system leading to enhanced water mobility and efficient gas injection. Therefore, for a saline aquifer rock with minerals capable of ion exchange reactions that consume solution protons, the wettability of such a system is likely to be preserved leading to reduced water mobility and poor gas injection. Generally, the extents to which surface protonation and ion exchange reactions occur depend on the free energy change of the reaction.In this paper, we have carried out thermodynamic computations for the free energies of surface protonation and ion exchange reactions. Based on the values of computed free energies, which show that ion exchange reactions have lower free energies, we have discussed the wettability implications for geological storage in silica rich saline aquifer systems.

The saline aquifer is the most reliable place where anthropogenic carbon dioxide gas storage has shown a promising future. This paper evaluates and predicts the capacities of different carbon dioxide storage trapping mechanisms in storing carbon dioxide gas in low porosity and permeability deep saline aquifers by using commercial reservoir simulator software i.e., Computer modeling group (CMG). Four carbon dioxide storage trapping modeled and simulated were structural or stratigraphic trapping mechanisms, residual trapping mechanisms, solubility trapping mechanisms, and mineral trapping mechanisms. Carbon dioxide gas was injected into a deep saline aquifer for 15 years, followed by 833 years of post-injection. To reflect the real field reality and have a reasonable approximation of the amount of carbon dioxide which can be stored in an aquifer, this paper included water vaporization effects that occur during carbon dioxide injection and water injection operations so as to optimize residual and solubility trapping mechanisms as the most important trapping mechanisms. Furthermore, the effects of different important parameters such as salinity, vertical-to-horizontal permeability ratio, injection rate, bottom hole pressure, and temperature on each carbon dioxide trapping mechanism were analyzed. Results revealed that each carbon dioxide trapping mechanism has a different capacity for storing carbon dioxide and could be either affected linearly or nonlinearly with various parameters. Higher aquifer temperatures are not recommended for carbon dioxide storage because most of the carbon dioxide gas is stored as free gas, which increases the risk of leakage in case of mechanical failure or imbalance. Excess salinity is the only factor that reduces aquifer storage capacity. Furthermore, it was found that an aquifer with a lower vertical-to-horizontal permeability ratio is recommended for carbon dioxide storage because it increases carbon dioxide stored in an immobile phase, which avoids risk leakages. There was an increase of 43.2% and a decrease of 16.84% for minimum and maximum vertical-to-horizontal permeability (kv/kh) ratios, respectively, compared to the base for residual trapping mechanisms. Also, there was a decrease of carbon dioxide dissolved by 19% at maximum kv/kh ratios and an increase of 58% at minimum kv/kh ratios, compared to the base case. Further, there was an increase of carbon dioxide trapped by 96.4% and dissolved by 97% when water was injected at a higher rate compared to the base case (no water injection). Thus, a high injection rate is suggested to enhance residual and solubility trapping mechanisms. It is recommended that the carbon dioxide injection rate and bottom hole pressure be kept at optimal levels to avoid mechanical failure due to aquifer pressures building up, which can increase the risk of leakages and must be monitored and controlled at the surface using pressure gauges or sensor technology.

This paper reviews key areas of carbon dioxide storage in saline aquifers. Among several potential geological carbon dioxide storage sites, saline aquifers offer the highest storage potential capacity and are relatively common worldwide. Geological storage of carbon dioxide in saline formations is achieved through various physical and chemical trapping mechanisms. When carbon dioxide is injected in the subsurface, it is first trapped by primary trapping mechanisms, which are static and hydrodynamic trapping below the cap rock. The secondary trapping mechanisms, solubility, mineral and residual trapping, are much slower and have a much longer timeframe for operating than primary trapping mechanisms. Knowledge regarding storage capacity in saline formations is highly uncertain due to their poor characterisation, heterogeneity and trapping mechanisms operating at different timeframe scales, which pose a huge challenge to establish a reliable methodology for storage capacity estimates. The potential cost of storage in saline aquifers is reasonably well known. However, the lack of any economic benefits makes this storage option less economically attractive than other geological sequestration strategies.

While geological sequestration of anthropogenic carbon dioxide is a technically and economically viable option for reducing emissions to the level required to avoid the predicted 2 degrees Celsius increase of atmospheric temperature by the end of this century, efficient sequestration planning is vital for the achievement of this goal.The petroleum industry has used conventional surfactants in enhance oil recovery projects aimed at prolonging the life span of a field, thereby increasing ultimate reserves. Notable among these is the use of surfactants for injected gas relative mobility control. Therefore, the potential for carbon dioxide mobility control in saline aquifers using surfactant alternating gas injection is huge, given the rich experience that can be tapped from the petroleum industry practice.Considering the expected surfactant loses in surfactant-enhanced geological sequestration similar to that encountered in the petroleum industry, this paper has used the analytical solution to advective diffusive equation that exists in the literature with a linear adsorption model where, adsorption has been used to predict trends in minimum pressure drop required for foam generation. The greatest utility of this work lies in the fact that the analytical solution is related a linear adsorption model related to a novel surfactant found from biological and hydrocarbon sources of geologic origin. This paper, therefore, extends the work of linear adsorption models for this novel surfactant aimed at exploring improved oil recovery potentials; in addition to exploring its potential for efficient geological carbon storage in saline aquifers.

The earth's temperature and climate are being affected by human activities that involve burning of fossil fuels and the clearing of forests, which release the greenhouse gases, like carbon dioxide (CO2). These fossil fuels, include coal and oil, are made of carbon that was first taken from the atmosphere by photosynthesis millions of years ago. The combustion of these fossil fuels is making up >75% of greenhouse gas emissions worldwide and almost 90% of CO2 emissions overall. Additionally, the Global Carbon Budget 2022 estimates that yearly emissions from burning fossil fuels have grown every decade since the mid-twentieth century, from about 11 billion tons in the 1960s to a 36.6 billion tons in 2022. Therefore, carbon capture and utilization (CCU) is considered an important CO2 mitigation strategy to support and compliment carbon capture and storage (CCS) objectives for the reduction and storage of CO2. CO2 geological storage (geo-storage) is a promising approach that can help to reduce greenhouse gas emissions. However, effective storage in geological underground formations requires understanding the main storage techniques and trapping mechanisms. Additionally, more research is required to enhance these techniques and understand their underlying mechanics. In light of this, this research investigates many underground and oceanic CO2 geo-storage techniques, such as saline aquifers, depleted oil and gas reservoirs, unmineable coal seams, basalt formations, and hydrates. The stability of CO2 geo-storage and its many trapping mechanisms are major areas of interest. Physical and chemical processes such as static, capillary, adsorption, solubility, mineral trapping, and ionic exchange are highlighted. Results from field research and experiments show how CO2 geo-storage technology is becoming more useful.The discussion of this review article provide observations on the future prospects and economic opportunities of CO2 geo-storage, underlining its transformative potential in combating climate change. By 2030 or late, most of the countries are actively working to increase their CO2 storage capacity. These efforts include initiatives such as additional funding, regulatory frameworks, and CCUS projects aimed at increasing their potential storage capacity.Concisely, this comprehensive review provides guidance for researchers, policymakers, and those in the industry; as understanding CO₂ geo-storage can pave the way for the development of more efficient, sustainable, and safe storage techniques, thus potentially playing a crucial role in addressing the challenge of global climate change. This review is divided into four parts: (1) an overview of the principles of CO2 geo-storage, (2) an examination of trapping mechanisms for CO2 geo-storage, (3) an analysis of experimental and field studies on CO2 geo-storage, and (4) exploration of the prospects for CO2 geo-storage.

Chapter 4 - Geological sequestration of CO2 in deep saline aquifers

Geological CO2 sequestration in saline aquifers: Implication on potential solutions of China’s power sector

CO2 sequestration in deep geological formations has been suggested as an option to reduce greenhouse gas emissions. Saline aquifers are one of the most promising options for carbon dioxide storage. It has been shown that the dissolution of CO2 into brine causes the density of the mixture to increase. If the corresponding Rayleigh number of the porous medium is enough to initiate convection currents, the rate of dissolution will increase. Early time dissolution of CO2 in brine is mainly dominated by molecular diffusion, while late time dissolution is predominantly governed by a convective mixing mechanism. In this paper, linear stability analysis of density-driven miscible flow for carbon dioxide sequestration in deep inclined and homogeneous saline aquifers is presented. The effect of inclination and its influence on the pattern of convection cells has been investigated and the results are compared with the horizontal layer. The current analysis provides approximations for the initial wavelength of the convective instabilities and the onset of convection that helps in selecting suitable candidates for geological CO2 sequestration sites. Introduction Carbon dioxide sequestration is the capture and safe storage of carbon dioxide that would otherwise emit to the atmosphere. Sequestration refers to any storage scheme that can keep CO2 out of the atmosphere(1). In general, proposed storage sites of carbon dioxide can be divided into two categories: geological sites and marine sites. Carbon dioxide sequestration in deep geological formations has been suggested as a way of reducing greenhouse gas emissions. Geologic sequestration of CO2 is the capture of CO2 from major sources, transporting it usually by pipeline, and injecting it into underground formations such as oil and gas reservoirs, saline aquifers and unmineable coal seams for a significant period of time(2, 3). Unlike coalbed methane reserves and oil reservoirs, sequestration of CO2 in deep saline aquifers does not produce value-added by-products, but it has other advantages. While there are uncertainties regarding the scope, the world's total capacity to store CO2 deep underground is large(4). Underground formations are generally unused and are available in many parts of the world(5). It has been estimated that deep saline formations in the United States could potentially store up to 500 billion tonnes of CO2. Most existing large CO2 point sources are within easy access to a saline formation injection point and, therefore, sequestration in saline formations is compatible with a strategy of transforming large portions of the existing energy and industrial assets to near-zero carbon emissions via low-cost carbon sequestration retrofits(3). However, it is important to investigate the behaviour of CO2 injected into aquifers for effective and safe use of storage. Geological storage of CO2 as a greenhouse gas mitigation option was proposed in the 1970s(6), but little research was done until the early 1990s when the idea gained credibility through the work of individual research groups(7–10). When CO2 is injected into the formation above its critical temperature and pressure, the density of supercritical carbon dioxide is usually less than brine. This density difference causes CO2 to migrate upwards to the top of the formation under an impermeable caprock.

Growing concerns over global climate change is also increasing the interest in developing technologies to reduce the concentration of carbon dioxide (CO2) in the atmosphere. Geological Carbon Sequestration which injects CO2 into subsurface formations such as deep saline aquifers, depleted hydrocarbon reservoirs are some of the viable options to reduce CO2 emissions into the atmosphere. Deep saline aquifers are a particularly good choice due to their wide geographical distribution and proximity to emission sources that provide easy accessibility and storability of CO2. Saline aquifers, however, are data-poor systems that requires a thorough understanding of the impact of all factors and their uncertainties on long-term CO2 storage for risk assessment. This study considers a wide range of geologic and dynamic model uncertainties, including structural uncertainties, petrophysical heterogeneities, dynamic flow parameters and geochemical reactions to define the most critical parameters for different CO2 trapping mechanisms. Experimental design over stochastic modelling and sampling is used to minimize the computational cost of the study. A commercially available, compositional reservoir simulator with reactive transport modeling capability has been used in this study to account for the impact of potential geochemical reactions. Assumed reactive transport model considers the water solubility, ionization, and mineral trapping mechanisms of CO2 in saline reservoirs for a range of components of dissolved salts in the brine as well as the pH of the brine. Chemical reactions that may occur with the rock minerals (Kaolinite, Anorthite and Calcite) when adding the CO2 are prescribed as input into the simulator. Simulations also include effects of hysteresis and diffusion processes. Study shows that the most important parameter for all trapping mechanisms is the permeability since it controls the injection capacity. Beyond that, different combination of parameters with different range of uncertainties alter the ranking of factors influencing dissolution, ionization, hysteresis, mineralization and the movement of CO2 within the aquifer. There is no unique set of parameters that maximizes all storage mechanisms. There is a significant overlap and change in amount the amount of CO2 stored via different mechanisms depending on the parameter combinations. Study results also provide insights into how one can prioritize data gathering needs depending on the objectives, data uncertainties and their sensitivities for an aquifer site under consideration.

Effect of sedimentary heterogeneities in the sealing formation on predictive analysis of geological CO2 storage

Developing a method for secure sequestration of anthropogenic carbon dioxide in geological formations is one of our most pressing global scientific problems. Injection into deep-sea basalt formations provides unique and significant advantages over other potential geological storage options, including (i) vast reservoir capacities sufficient to accommodate centuries-long U.S. production of fossil fuel CO2 at locations within pipeline distances to populated areas and CO2 sources along the U.S. west coast; (ii) sufficiently closed water-rock circulation pathways for the chemical reaction of CO2 with basalt to produce stable and nontoxic (Ca(2+), Mg(2+), Fe(2+))CO(3) infilling minerals, and (iii) significant risk reduction for post-injection leakage by geological, gravitational, and hydrate-trapping mechanisms. CO2 sequestration in established sediment-covered basalt aquifers on the Juan de Fuca plate offer promising locations to securely accommodate more than a century of future U.S. emissions, warranting energized scientific research, technological assessment, and economic evaluation to establish a viable pilot injection program in the future.

With heightened concerns on carbon dioxide (CO2) emissions from coal power plants, there has been a major emphasis in recent years on development of safe and economical geological carbon sequestration (GCS) technology. However, the detailed multiphase fluid dynamics and processes of GCS are not fully understood because various CO2 trapping mechanisms in geological formations have large variations in both spatial and temporal scales. As a result, there remain many uncertainties in determining the sequestration capacity of the reservoir and the safety of sequestered CO2 due to leakage. Furthermore, the sequestration efficiency is highly dependent on the CO2 injection strategy, which includes injection rate, injection pressure, and type of injection well, and its orientation, etc. The goal of GCS is to maximize the sequestration capacity and minimize the plume migration by optimizing the GCS operation. In this paper, first the basic fluid dynamics and trapping mechanisms for CO2 sequestration are briefly discussed. They are followed by a brief summary of current GCS projects worldwide with special emphasis on those in the United States. Majority of the paper is devoted to the numerical modeling, simulation, and optimization of CO2 sequestration in saline aquifers at macro spatial scales of a few to hundreds of kilometers and macro temporal scales of a few to hundreds of years. Examples of numerical simulations of a few large industrial scale projects are presented. The optimization studies include the investigation of various injection and well placement strategies to determine the optimal approach for maximizing the storage and minimizing the plume migration.

To mitigate continued release of CO2 from anthropogenic sources, underground storage of carbon dioxide (CO2) is accepted worldwide as a promising and well-established technology. Due to increased concerns on CO2 emissions, there has been foremost importance in recent years on the development and establishment of safe, technologically feasible and economic geological carbon sequestration (GCS) technology. GCS has been practiced widely as a potentially practical climate change mitigation decision. For this purpose to dispose large amount of CO2 in economic and safe fashion for long term periods, deep ocean and geologic sequestration are considered viable options. Geologic sequestration is a potential technology to decrease released CO2 into the atmosphere through capturing CO2 from hydrocarbon emissions, transporting compressed CO2 from the source to the field, and injecting and storage of CO2 into the underground formation. While injecting CO2 into the formation, residual gas trapping and solubility trapping are the most important trapping mechanisms for CO2 storage in saline aquifers. The lack of information about the geological formation results in uncertainties in specifying the storage capacity of the formation and the safety of sequestered CO2 caused by leakage. These uncertainties influence the sequestration capacity and CO2 plume migration. Moreover, the sequestration efficiency is highly dependent on the injection strategy which includes injection rate, injection pressure, type of injection well employed and its trajectory. The goal of GCS is to maximize the sequestration capacity and minimize the CO2 plume migration by optimizing the GCS operation before progressing with its large scale deployment. Hence the objective of CO2 sequestration is to achieve a more uniform sweep efficiency and more extensive CO2 sweep of the geological formation for a fixed amount of injected CO2. To accomplish this objective, we propose a novel formulation for CO2 sequestration optimization problem to promote uniform distribution of CO2 in geological formation through minimizing the gas saturation differences in cells with the same distance to CO2 injection wells.