Dissolution sequestration mechanism of CO<Subscript>2</Subscript> at the Shiqianfeng saline aquifer in the Ordos Basin,northwestern China

This study focused on the target injection layers of deep saline aquifers in the Shiqianfeng Fm. in the Carbon Capture and Sequestration (CCS) Demonstration Projects in the Ordos Basin, northwestern China. The study employed a combination method of experiments and numerical simulation to investigate the dissolution mechanism and impact factors of CO₂ in these saline aquifers. The results showed (1) CO₂ solubility in different types of water chemistry were shown in ascending order: MgCl₂-type water < CaCl₂-type water < Na₂SO₄-type water < NaCl-type water < Na₂CO₃-type water < distilled water. These results were consistent with the calculated results undertaken by TOUGHREACT with about 5% margin of error. CO₂ solubility of Shiqianfeng Fm. saline was 1.05 mol/L; (2) compared with distilled water, the more complex the water’s chemical composition, the greater the increase in HCO₃ ^?concentration. While the water’s composition was relatively simple, the tested water’s HCO₃ ^?concentrations were in close accord with the calculated value undertaken by the TOUGHREACT code, and the more complex the water’s composition, the poorer the agreement was, probably due to the complex and unstable HCO₃ ^? complicating matters when in an aqueous solution system including both tested HCO₃ ^?concentration and calculated HCO₃ ^?concentration; (3) the CO₂ solubility in the saline at the temperature conditions of 55 °C and 70 °C were 1.17 and 1.02 mol/L. When compared with the calculated value of 1.20 and 1.05 mol/L, they were almost the same with only 1 and 3% margin of error; concentrations of HCO₃ ^? were 402.73 mg/L (0.007 mol/L) and 385.65 mg/L (0.006 mol/L), while the simulation results were 132.16 mg/L (0.002 mol/L) and 128.52 mg/L (0.002 mol/L). From the contrast between the tested data and the calculated data undertaken by the TOUGHREACT code, it was shown that TOUGHRACT code could better simulate the interaction between saline and CO₂ in the dissolution sequestration capacity. Therefore, TOUGHREACT code could be used for the inter-process prediction of CO₂ long-term geological storage of CO₂; (4) The Ca²⁺ concentration and SO₄ ^2?concentration in saline water had less effect on the solubility of CO₂ and HCO₃ ^?concentration. In addition, TDS and pH values of saline affected not only the solubility of CO₂, but also the conversion of CO₂ to HCO₃ ^? due to that they can affect the activity and acid-base balance. So in fact, we just need to consider that the TDS and pH values are main impact factors in the dissolution sequestration capacity of CO₂ geological sequestration in deep saline aquifers.     

Optimal selection of different CCS technologies under CO2 reduction targets

In China, carbon capture and storage (CCS) is recognized as one of the most promising technologies through which to achieve a large reduction in CO₂ emissions in future. The choice among different CCS technologies is critical for large-scale applications. With the aim of developing instructive policy suggestions for CCS development, this study proposed an interval programming model to select the optimal CCS technology among the different CCS technologies available in China. The analysis results indicate that the selection of CO₂ capture technologies should be based on the actual situation of the project and industry being targeted. If the government implements mandatory CO₂ emission reductions, storage in deep saline aquifers is the optimal choice for CO₂ sequestration when oil prices are low and the number of available CO₂ emission permits is large. In contrast, enhanced oil recovery is the optimal choice when oil prices increase and the availability of CO₂ emission permits decreases. It is critical that the government reduce the operating cost and the cost of CO₂ capture in particular.

     

Potential assessment of CO2 geological storage based on injection scenario simulation: A case study in eastern Junggar Basin

Carbon Capture and Storage (CCS) is one of the effective means to deal with global warming, and saline aquifer storage is considered to be the most promising storage method. Junggar Basin, located in the northern part of Xinjiang and with a large distribution area of saline aquifer, is an effective carbon storage site. Based on well logging data and 2D seismic data, a 3D heterogeneous geological model of the Cretaceous Donggou Formation reservoir near D7 well was constructed, and dynamic simulations under two scenarios of single-well injection and multi-well injection were carried out to explore the storage potential and CO₂ storage mechanism of deep saline aquifer with real geological conditions in this study. The results show that within 100 km² of the saline aquifer of Donggou Formation in the vicinity of D7 well, the theoretical static CO₂ storage is 71.967 × 10⁶ tons (P50)^①, and the maximum dynamic CO₂ storage is 145.295 × 10⁶ tons (Case2). The heterogeneity of saline aquifer has a great influence on the spatial distribution of CO₂ in the reservoir. The multi-well injection scenario is conducive to the efficient utilization of reservoir space and safer for storage. Based on the results from theoretical static calculation and the dynamic simulation, the effective coefficient of CO₂ storage in deep saline aquifer in the eastern part of Xinjiang is recommended to be 4.9%. This study can be applied to the engineering practice of CO₂ sequestration in the deep saline aquifer in Xinjiang.     

Characterization of deep saline aquifers in the Bécancour area,St. Lawrence Lowlands,Québec,Canada: implications for CO2 geological storage

The present paper provides a case study of the assessment of the potential for CO₂ storage in the deep saline aquifers of the Bécancour region in southern Québec. This assessment was based on a hydrogeological and petrophysical characterization using existing and newly acquired core and well log data from hydrocarbon exploration wells. Analyses of data obtained from different sources provide a good understanding of the reservoir hydrogeology and petrophysics. Profiles of formation pressure, temperature, density, viscosity, porosity, permeability, and net pay were established for Lower Paleozoic sedimentary aquifers. Lateral hydraulic continuity is dominant at the regional scale, whereas vertical discontinuities are apparent for most physical and chemical properties. The Covey Hill sandstone appears as the most suitable saline aquifer for CO₂ injection/storage. This unit is found at a depth of more than 1 km and has the following properties: fluid pressures exceed 14 MPa, temperature is above 35 °C, salinity is about 108,500 mg/l, matrix permeability is in the order of 3 × 10^?16 m² (0.3 mDarcy) with expected higher values of formation-scale permeability due to the presence of natural fractures, mean porosity is 6 %, net pay reaches 282 m, available pore volume per surface area is 17 m³/m², rock compressibility is 2 × 10^?9 Pa^?1 and capillary displacement pressure of brine by CO₂ is about 0.4 MPa. While the containment for CO₂ storage in the Bécancour saline aquifers can be ensured by appropriate reservoir characteristics, the injectivity of CO₂ and the storage capacity could be limiting factors due to the overall low permeability of aquifers. This characterization offers a solid basis for the subsequent development of a numerical hydrogeological model, which will be used for CO₂ injection capacity estimation, CO₂ injection scenarios and risk assessment.     

Effects of in-situ conditions on relative permeability characteristics of CO2-brine systems

Carbon dioxide capture and geological storage (CCGS) is an emerging technology that is increasingly being considered for reducing greenhouse gas emissions to the atmosphere. Deep saline aquifers provide a very large capacity for CO₂ storage and, unlike hydrocarbon reservoirs and coal beds, are immediately accessible and are found in all sedimentary basins. Proper understanding of the displacement character of CO₂-brine systems at in-situ conditions is essential in ascertaining CO₂ injectivity, migration and trapping in the pore space as a residual gas or supercritical fluid, and in assessing the suitability and safety of prospective CO₂ storage sites. Because of lack of published data, the authors conducted a program of measuring the relative permeability and other displacement characteristics of CO₂-brine systems for sandstone, carbonate and shale formations in central Alberta in western Canada. The tested formations are representative of the in-situ characteristics of deep saline aquifers in compacted on-shore North American sedimentary basins. The results show that the capillary pressure, interfacial tension, relative permeability and other displacements characteristics of CO₂-brine systems depend on the in-situ conditions of pressure, temperature and water salinity, and on the pore size distribution of the sedimentary rock. This paper presents a synthesis and interpretation of the results.     

Impacts of mineralogical compositions on different trapping mechanisms during long-term CO<Subscript>2</Subscript> storage in deep saline aquifers

Deep saline aquifers in sedimentary basins are considered to have the greatest potential for CO₂ geological storage in order to reduce carbon emissions. CO₂ injected into a saline sandstone aquifer tends to migrate upwards toward the caprock because the density of the supercritical CO₂ phase is lower than that of formation water. The accumulated CO₂ in the upper portions of the reservoir gradually dissolves into brine, lowers pH and changes the aqueous complexation, whereby induces mineral alteration. In turn, the mineralogical composition could impose significant effects on the evolution of solution, further on the mineralized CO₂. The high density of aqueous phase will then move downward due to gravity, give rise to “convective mixing,” which facilitate the transformation of CO₂ from the supercritical phase to the aqueous phase and then to the solid phase. In order to determine the impacts of mineralogical compositions on trapping amounts in different mechanisms for CO₂ geological storage, a 2D radial model was developed. The mineralogical composition for the base case was taken from a deep saline formation of the Ordos Basin, China. Three additional models with varying mineralogical compositions were carried out. Results indicate that the mineralogical composition had very obvious effects on different CO₂ trapping mechanisms. Specific to our cases, the dissolution of chlorite provided Mg²⁺ and Fe²⁺ for the formation of secondary carbonate minerals (ankerite, siderite and magnesite). When chlorite was absent in the saline aquifer, the dominant secondary carbon sequestration mineral was dawsonite, and the amount of CO₂ mineral trapping increased with an increase in the concentration of chlorite. After 3000 years, 69.08, 76.93, 83.52 and 87.24 % of the injected CO₂ can be trapped in the solid (mineral) phase, 16.05, 11.86, 8.82 and 6.99 % in the aqueous phase, and 14.87, 11.21, 7.66 and 5.77 % in the gas phase for Case 1 through 4, respectively.     

Hydrogeochemical and isotopic evidence for trans-formational flow in a sedimentary basin: Implications for CO2 storage

Deep saline aquifers are considered as the most promising option for geologic disposal of CO₂. One of the main concerns, however, is the integrity of the caprocks between and above the storage formations. Here, a hydrogeochemical and isotopic investigation is presented, using ionic chemistry, stable isotopes (δ¹⁸O, δ²H and ⁸⁷Sr/⁸⁶Sr) and radiocarbon dating, on five saline aquifers on a regional scale, namely: Neogene Minghuazhen, Guantao, Ordivician, Cambrian and Precambrian, all found in the Bohai Bay Basin (BBB) in North China. Groundwater recharge, flow pattern, age and mixing processes in the saline aquifers show that the Neogene Guantao Formation (Ng) in the Jizhong and Huanghua Depressions on both of the west and east sides of the Cangxian Uplift is a prospective reservoir for CO₂ sequestration, with a well confined regional seal above, which is the clayey layers in the Neogene Minghuazhen Formation (Nm). However, this is not the case in the Cangxian Uplift, where the Ng is missing where structural high and fault zones are developed, creating strong hydraulic connections and trans-formational flow to the Nm aquifer. Comparing storage capacity and long-term security between the various hydrogeologic units, the depressions are better candidate sites for CO₂ sequestration in the BBB.     

Tracers – Past,present and future applications in CO2 geosequestration

Chemical tracers have been used in various C capture and storage (CCS) projects worldwide primarily to provide information regarding subsurface migration of CO₂ and to verify CO₂ containment. Understanding the movement and interactions of CO₂ in the subsurface is a challenging task considering the variety of states in which it exists (i.e. gas, liquid, supercritical, dissolved in water) and the range of possible storage mechanisms (i.e. residual or capillary trapping, dissolved in water, structural trapping or incorporation into minerals). This paper critically reviews several chemical tracer applications and case studies for CCS projects. In many instances, there are parallels (e.g. tracer classes and applications) between tracers in the oil and gas industry and in CCS. It has been shown that chemical tracers can complement geophysical measurements (e.g. seismic) in understanding the formation behaviour of CO₂. Although tracers have been successfully used in many CCS projects, some fundamental information, for example partitioning and adsorption, about the behaviour of tracers is still lacking and this can be an issue when interpreting tracer data (e.g. determining leakage rates). In this paper the deployment and recovery of chemical tracers and their use on various CCS projects are described.     

Increased hydrocarbon recovery and CO2 management, a Croatian example

Enhanced oil recovery based on CO₂ injection is expected to increase recovery from Croatian oil fields. Large quantities of CO₂ are generated during hydrocarbon processing produced from gas and gas condensate fields situated in the north-western part of Croatia. First CO₂ injection project will be implemented on the Ivani? Oil Field. Numerical modelling based on Upper Miocene sandstone core samples testing results have shown the decrease of oil viscosity during CO₂ injection. Some of the characteristics of the testing samples are porosity 21.5–23.6 %, permeability 14–80 × 10^?15 m² and initial water saturation 28–38.5 %. Water alternating foam (WAF) and water alternating gas (WAG) simulations have provided satisfactory results. The WAF injection process has provided better results, but due to the process sensitivity and costs WAG is recommended for future application. During the pilot project 16 × 10⁶ m³ CO₂ and 5 × 10⁴ m³ of water were injected. Additional amounts of hydrocarbons (4,440 m³ of oil and 2.26 × 10⁶ m³ of gas) were produced which confirmed injection of CO₂ as a successful tertiary oil recovery mechanism in Upper Miocene sandstone reservoirs in the Croatian part of the Pannonian Basin System.     

A preliminary evaluation of carbon dioxide storage capacity in unmineable coalbeds in China

In this study, CO₂ storage capacity in unmineable coalbeds in China at depths of 1,000–2,000 m has been evaluated using the methodology recommended by CSLF. This evaluation is one part of the countrywide CO₂ storage capacity evaluations in China, initiated by the Chinese Ministry of Land and Resources. This level of CO₂ storage capacity evaluation gives a rough scale of assessment with the least site-specific detail. The results show that there is a storage capacity of 98.81 × 10⁸ t CO₂ in coalbeds buried at a depth range of 1,000–2,000 m and 4.26 × 10¹² m³ additional coalbed methane can be recovered by CO₂ injection. These results appear to show great potential and an attractive economic perspective of CO₂ storage in unmineable coalbeds in China. Another part of this study is to classify the potential coalbed basins based on CO₂ storage capacity and storage capacity per unit area. The study results reveal the distribution of the most potential basins for large-scale CO₂ storage and the best economic basins for early CO₂ storage in the future.     

On leakage and seepage of CO2 from geologic storage sites into surface water

Geologic carbon sequestration is the capture of anthropogenic carbon dioxide (CO₂) and its storage in deep geologic formations. The processes of CO₂ seepage into surface water after migration through water-saturated sediments are reviewed. Natural CO₂ and CH₄ fluxes are pervasive in surface-water environments and are good analogues to potential leakage and seepage of CO₂. Buoyancy-driven bubble rise in surface water reaches a maximum velocity of approximately 30 cm s⁻¹. CO₂ rise in saturated porous media tends to occur as channel flow rather than bubble flow. A comparison of ebullition versus dispersive gas transport for CO₂ and CH₄ shows that bubble flow will dominate over dispersion in surface water. Gaseous CO₂ solubility in variable-salinity waters decreases as pressure decreases leading to greater likelihood of ebullition and bubble flow in surface water as CO₂ migrates upward.     

Evaluation of chemical immobilization treatments for reducing arsenic transport in red mud

Red mud (RM) was produced during alumina production from bauxite known as the Bayer process. Arsenic was detected in the solid phase of RM (RMsf) which was disposed in the disposal area. This study investigates the effectiveness of using Zero-valent iron (ZVI), ferrihydrite, ferrous sulfate (FeSO₄), waste acid (WA) or CO₂ for immobilization of arsenic in the RMsf. To test the effect of the amendments on the arsenic leachability, the RMsf samples were amended with the iron-based materials or acidifiers at various w/w (weight/weight) ratios (1–10 %) for 30 days. The leachability of arsenic in the RMsf was evaluated by a 4-step water elusion process. After 30-day treatment of the RMsf, the leachability of As decreased from an initial (12.7 %) to (7.0 %) with a w/w ratio of 5 % ZVI (0 %) with 5 % FeSO₄·7H₂O, (3.4 %) with 5 % ferryhydrite, (2.0 %) with 6 % WA and (11.8 %) with 6 % CO₂. FeSO₄·7H₂O and WA showed more effectively than other amendments for immobilizing arsenic. Arsenic fractionation with a sequential extraction procedure was used to evaluate the arsenic migration potential in the RMsf. FeSO₄ and WA were effective in increasing the hydrous oxide combined arsenic in the RMsf. The leachable Cl^? and SO₄ ^2? in the RMsf increased from 2.9 to 14.1 mg/g and 19.9–44.4 mg/g with 6 % WA and 5 % FeSO₄·7H₂O added, respectively. The estimated cost of the FeSO₄ and WA treatment was 0.47 and 0.49 USD per ton, respectively.     

Using distributed temperature sensing (DTS) technology in acid gas injection design

The use of slickline distributed temperature sensing (SL-DTS) technology is becoming widespread due to its ease of operation and ability to acquire real-time multiple temperature traces inside the wellbore. Injection of treated acid gas (TAG)—a mixture of CO₂ and H₂S—into geologic formations has become an attractive technical and economic option for oil and gas producers and processors who are faced with regulations concerning excess sulfur and greenhouse gas emissions. Acid gas injection (AGI) into geologic formations is more economical and more flexible in dealing with varying TAG compositions than sulfur recovery units (SRUs) using the Claus process. SRUs do not achieve air quality standards and have high operation and maintenance costs. In addition, there is low demand for sulfur and sulfur disposal costs are high. The results of the analysis of SL-DTS data acquired in conjunction with step rate and pressure falloff (PFO) tests are presented in this paper. These tests were conducted to evaluate the injection potential of geologic formations. The injection zone consisted of a carbonate formation characterized by Karst features, vugs, and natural fractures. The SL-DTS data during the initial injection flow rate for the step rate test (SRT) indicated that high permeability zones accepted fluid at lower injection rates. An increasing number of discrete zones began to accept fluid as the injection rate was increased. The results of the SRT provided the fracture pressure of the formation. This information was used to design an AGI program that would avoid fracturing the formation while allowing for the required volume of TAG to be injected. The results of the PFO test provided information on the reservoir pressure and permeability and also indicated the presence of one or more hydraulic fractures. This case study of SL-DTS measurements made during a SRT and a PFO test for the design of an AGI well provides valuable insights into the potential of DTS technology and its use in AGI and carbon capture/sequestration (CCS) operations. Its findings could be applied to analyze injection potential of geological formations not only for AGI projects but also for CCS, and CO₂ enhanced oil recovery opportunities.     

Assessment of greenhouse gas emissions from coal and natural gas thermal power plants using life cycle approach

The importance of mitigation of climate change due to greenhouse gas (GHG) emissions from various developmental and infrastructure projects has generated interest at global level to reduce environmental impacts. Life cycle assessment may be used as a tool to assess GHG emissions and subsequent environmental impacts resulting from electricity generation from thermal power plants. This study uses life cycle approach for assessing GHG emissions and their impacts due to natural gas combined cycle (NGCC) and imported coal thermal power plants using the IPCC 2001 and Eco-Indicator 99(H) methods in India for the first time. The total GHG emission from the NGCC thermal power plant was 584 g CO₂ eq/kWh electricity generation, whereas in case of imported coal, it was 1,127 g CO₂ eq/kWh electricity generation. This shows that imported coal has nearly ~2 times more impacts when compared to natural gas in terms of global warming potential and human health as disability-adjusted life years from climate change due to GHG emissions such as carbon dioxide (CO₂), methane (CH₄) and nitrous oxide (N₂O).     

Appraisal of CO2 storage potential in compressional hydrocarbon-bearing basins: Global assessment and case study in the Sichuan Basin (China)

Carbon capture and storage (CCS) has been proposed as a potential technology to mitigate climate change. However, there is currently a huge gap between the current global deployment of this technology and that which will be ultimately required. Whilst CO₂ can be captured at any geographic location, storage of CO₂ will be constrained by the geological storage potential in the area the CO₂ is captured. The geological storage potential can be evaluated at a very high level according to the tectonic setting of the target area. To date, CCS deployment has been restricted to more favourable tectonic settings, such as extensional passive margin and post-rift basins and compressional foreland basins. However, to reach the adequate level of deployment, the potential for CCS of regions in different tectonic settings needs to be explored and assessed worldwide. Surprisingly, the potential of compressional basins for carbon storage has not been universally evaluated according to the global and regional carbon emission distribution. Here, we present an integrated source-to-sink analysis tool that combines comprehensive, open-access information on basin distribution, hydrocarbon resources and CO₂ emissions based on geographical information systems (GIS). Compressional settings host some of the most significant hydrocarbon-bearing basins and 36% of inland CO₂ emissions but, to date, large-scale CCS facilities in compressional basins are concentrated in North America and the Middle East only. Our source-to-sink tool allows identifying five high-priority regions for prospective CCS development in compressional basins: North America, north-western South America, south-eastern Europe, the western Middle East and western China. We present a study of the characteristics of these areas in terms of CO₂ emissions and CO₂ storage potential. Additionally, we conduct a detailed case-study analysis of the Sichuan Basin (China), one of the compressional basins with the greatest CO₂ storage potential. Our results indicate that compressional basins will have to play a critical role in the future of CCS if this technology is to be implemented worldwide.     

A sensitivity analysis of factors affecting in geologic CO2 storage in the Ordos Basin and its contribution to carbon neutrality

To accelerate the achievement of China’s carbon neutrality goal and to study the factors affecting the geologic CO₂ storage in the Ordos Basin, China’s National Key R&D Programs propose to select the Chang 6 oil reservoir of the Yanchang Formation in the Ordos Basin as the target reservoir to conduct the geologic carbon capture and storage (CCS) of 100000 t per year. By applying the basic theories of disciplines such as seepage mechanics, multiphase fluid mechanics, and computational fluid mechanics and quantifying the amounts of CO₂ captured in gas and dissolved forms, this study investigated the effects of seven factors that influence the CO₂ storage capacity of reservoirs, namely reservoir porosity, horizontal permeability, temperature, formation stress, the ratio of vertical to horizontal permeability, capillary pressure, and residual gas saturation. The results show that the sensitivity of the factors affecting the gas capture capacity of CO₂ decreases in the order of formation stress, temperature, residual gas saturation, horizontal permeability, and porosity. Meanwhile, the sensitivity of the factors affecting the dissolution capture capacity of CO₂ decreases in the order of formation stress, residual gas saturation, temperature, horizontal permeability, and porosity. The sensitivity of the influencing factors can serve as the basis for carrying out a reasonable assessment of sites for future CO₂ storage areas and for optimizing the design of existing CO₂ storage areas. The sensitivity analysis of the influencing factors will provide basic data and technical support for implementing geologic CO₂ storage and will assist in improving geologic CO₂ storage technologies to achieve China’s carbon neutralization goal.©2022 China Geology Editorial Office.     

Assessing the potential consequences of CO2 leakage to freshwater resources: A batch-reaction experiment towards an isotopic tracing tool

The assessment of the environmental impacts of CO₂ geological storage requires the investigation of potential CO₂ leakages into fresh groundwater, particularly with respect to protected groundwater resources. The geochemical processes and perturbations associated with a CO₂ leak into fresh groundwater could alter groundwater quality: indeed, some of the reacting minerals may contain hazardous constituents, which might be released into groundwater. Since the geochemical reactions may occult direct evidence of intruding CO₂, it is necessary to characterize these processes and identify possible indirect indicators for monitoring CO₂ intrusion. The present study focuses on open questions: Can changes in water quality provide evidence of CO₂ leakage? Which parameters can be used to assess impact on freshwater aquifers? What is the time scale of water chemistry degradation in the presence of CO₂? The results of an experimental approach allow selecting pertinent isotope tracers as possible indirect indicators of CO₂ presence, opening the way to devise an isotopic tracing tool.The study area is located in the Paris Basin (France), which contains deep saline formations identified as targets by French national programs for CO₂ geological storage. The study focuses on the multi-layered Albian fresh water aquifer, confined in the central part of the Paris Basin a major strategic potable groundwater overlying the potential CO₂ storage formations. An experimental approach (batch reactors) was carried out in order to better understand the rock–water–CO₂ interactions with two main objectives. The first was to assess the evolution of the formation water chemistry and mineralogy of the solid phase over time during the interaction. The second concerned the design of an isotopic monitoring program for freshwater resources potentially affected by CO₂ leakage. The main focus was to select suitable environmental isotope tracers to track water rock interaction associated with small quantities of CO₂ leaking into freshwater aquifers.In order to improve knowledge on the Albian aquifer, and to provide representative samples for the experiments, solid and fluid sampling campaigns were performed throughout the Paris Basin. Albian groundwater is anoxic with high concentrations of Fe, a pH around 7 and a mineral content of 0.3 g L⁻¹. Macroscopic and microscopic solid analyses showed a quartz-rich sand with the presence of illite/smectite, microcline, apatite and glauconite. A water–mineral–CO₂ interaction batch experiment was used to investigate the geochemical evolution of the groundwater and the potential release of hazardous trace elements. It was complemented by a multi-isotope approach including δ¹³C_DIC and ⁸⁷Sr/⁸⁶Sr. Here the evolution of the concentrations of major and trace elements and isotopic ratios over batch durations from 1 day to 1 month are discussed. Three types of ion behavior are observed: Type I features Ca, SiO₂, HCO₃, F, PO₄, Na, Al, B, Co, K, Li, Mg, Mn, Ni, Pb, Sr, Zn which increased after initial CO₂ influx. Type II comprises Be and Fe declining at the start of CO₂ injection. Then, type III groups element with no variation during the experiments like Cl and SO₄. The results of the multi-isotope approach show significant changes in isotopic ratios with time. The contribution of isotope and chemical data helps in understanding geochemical processes involved in the system. The isotopic systems used in this study are potential indirect indicators of CO₂–water–rock interaction and could serve as monitoring tools of CO₂ leakage into an aquifer overlying deep saline formations used for C sequestration and storage.     

Assessment of groundwater quality in and around Vedaraniyam,South India

Groundwater from 47 wells were analyzed on the basis of hydrochemical parameters like pH, electric conductivity, total dissolved solids, Ca²⁺, Mg²⁺, Na⁺, K⁺, Cl^?, CO₃ ^2?, HCO₃ ^?, NO₃ ^?, PO₄ ^3? and F^? in the Cauvery delta of Vedaraniyam coast. Further, water quality index (WQI), sodium percentage (Na %), sodium absorption ratio, residual sodium carbonate, permeability index and Kelley’s ratio were evaluated to understand the suitability of water for drinking and irrigation purposes. The result shows significant difference in the quality of water along the coastal stretch. The order of dominance of major ions is as follows: Na⁺ ≥ Mg²⁺ ≥ Ca²⁺ ≥ K⁺ and Cl^? ≥ HCO₃ ^? ≥ CO₃ ^2? ≥ PO₄ ^3? ≥ F^?. Na/Cl, Cl/HCO₃ ratio and Revelle index confirmed that 60–70 % of the samples were affected by saline water intrusion. WQI showed that 36 % of the samples were good for drinking and the remaining were poor and unsuitable for drinking purpose. The degradation of groundwater quality was found to be mainly due to over-exploitation, brackish aquaculture practice, fertilizer input from agriculture and also due to domestic sewage.     

Geochemical detection of carbon dioxide in dilute aquifers

Background  

Carbon storage in deep saline reservoirs has the potential to lower the amount of CO₂ emitted to the atmosphere and to mitigate global warming. Leakage back to the atmosphere through abandoned wells and along faults would reduce the efficiency of carbon storage, possibly leading to health and ecological hazards at the ground surface, and possibly impacting water quality of near-surface dilute aquifers. We use static equilibrium and reactive transport simulations to test the hypothesis that perturbations in water chemistry associated with a CO₂ gas leak into dilute groundwater are important measures for the potential release of CO₂ to the atmosphere. Simulation parameters are constrained by groundwater chemistry, flow, and lithology from the High Plains aquifer. The High Plains aquifer is used to represent a typical sedimentary aquifer overlying a deep CO₂ storage reservoir. Specifically, we address the relationships between CO₂ flux, groundwater flow, detection time and distance. The CO₂ flux ranges from 10³ to 2 × 10⁶ t/yr (0.63 to 1250 t/m²/yr) to assess chemical perturbations resulting from relatively small leaks that may compromise long-term storage, water quality, and surface ecology, and larger leaks characteristic of short-term well failure.     

Development of detection and monitoring techniques of CO2 leakage from seafloor in sub-seabed CO2 storage

Carbon dioxide capture and storage (CCS) in sub-seabed geological formations is currently being studied as a potential option to mitigate the accumulation of anthropogenic CO₂ in the atmosphere. To investigate the validity of CO₂ storage in the sub-seafloor, development of techniques to detect and monitor CO₂ leaked from the seafloor is vital. Seafloor-based acoustic tomography is a technique that can be used to observe emissions of liquid CO₂ or CO₂ gas bubbles from the seafloor. By deploying a number of acoustic tomography units in a seabed area used for CCS, CO₂ leakage from the seafloor can be monitored. In addition, an in situ pH/pCO₂ sensor can take rapid and high-precision measurements in seawater, and is, therefore, able to detect pH and pCO₂ changes due to the leaked CO₂. The pH sensor uses a solid-state pH electrode and reference electrode instead of a glass electrode, and is sealed within a gas permeable membrane filled with an inner solution. Thus, by installing a pH/pCO₂ sensor onto an autonomous underwater vehicle (AUV), an automated observation technology is realized that can detect and monitor CO₂ leakage from the seafloor. Furthermore, by towing a multi-layer monitoring system (a number of pH/pCO₂ sensors and transponders) behind the AUV, the dispersion of leaked CO₂ in a CCS area can also be observed. Finally, an automatic elevator can observe the time-series dispersion of leaked CO₂. The seafloor-mounted automatic elevator consists of a buoy equipped with pH/pCO₂ and depth sensors, and uses an Eulerian method to collect spatially continuous data as it ascends and descends.Hence, CO₂ leakage from the seafloor is detected and monitored as follows. Step 1: monitor CO₂ leakage by seafloor-based acoustic tomography. Step 2: conduct mapping survey of the leakage point by using the pH/pCO₂ sensor installed in the AUV. Step 3: observe the impacted area by using a remotely operated underwater vehicle or the automatic elevator, or by towing the multi-layer monitoring system.