Carbon Capture And Storage Operations Research Articles

Guidelines Assist Selection of Corrosion-Resistant Alloys for CCS and CCUS Injection Wells

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 217664, “Selection of Corrosion-Resistant Alloys for CCS and CCUS Injection Wells,” by Adam C. Rowe, SPE, Stress Engineering Services, and Bruce D. Craig, SPE, MetCorr. The paper has not been peer reviewed. _ Currently, few test data are available for determining the most suitable corrosion-resistant alloys (CRAs) for downhole injection equipment in carbon capture and storage (CCS) and carbon capture, use, and storage (CCUS) wells. The complete paper provides a guideline for such selections based on the composition of the CO2 stream, including impurities and the composition of the saline formation into which the CO2 will be injected. Introduction For those CCS and CCUS systems where water is expected to be present at some point, such as injection into a saline formation or by virtue of incomplete dehydration, carbon steel will corrode and CRAs must be considered. Because carbon steel pipelines are standard practice for transport of supercritical CO2 and have a long, successful history, this paper is strictly focused on the selection of CRAs for injection wells. While the selection of CRA material can be, and often is, based on common practices, each application requires an in-depth review of the complete system to determine the best materials for the job. In the case of storage, service life is ostensibly forever, so even otherwise minor pitting rates may not be tolerable in permanent equipment. The most important factors to consider for CRA corrosion are temperature, pH of the water phase, formation-water composition (typically chloride content), and stream impurities. With respect to temperature, this paper is focused on corrosion within CCS and CCUS wells and, therefore, considers only elevated temperature resulting from downhole geothermal gradients. Stream impurities have a significant effect on potential CRA selection, especially when certain species such as oxygen are present. However, hydrogen sulfide (H2S) and nitrogen and sulfur oxides also can be important to this selection. Technical Review of CCS and CCUS Injection Conditions Much of the CRA experience from the oil patch cannot be applied directly to CCS and CCUS well design. Multiple sources are susceptible to significant residual H2S in the injectate. Currently, no standards or guidelines exist relating to the effect of H2S in supercritical CO2 on materials. Therefore, the industry default at the time of writing is to apply the industry standard NACE MR0175/ISO 15156-3, though it is important to note that environmentally assisted cracking resistance has not been established for many CRAs at pH 3 and lower. It also is important to recognize that this standard is specifically applicable to production of oil and gas, and it remains to be determined whether CCS and CCUS operations are similar enough to apply this guide, or if supercritical CO2 warrants different limits, particularly when O2 is present. The presence of O2 in supercritical-CO2 streams presents a significant problem for the selection of CRAs. The corrosivity from O2 is defined by the dissolved oxygen concentration in the water phase, which is difficult to model in complex systems. Currently, these data are not readily available for supercritical-CO2 streams commingled with formation brines. As a guide, albeit a qualitative one, use of the pitting resistance equivalent number (PREN) is helpful for ranking resistance to pitting and crevice corrosion in aerated brine.

Progress in carbon dioxide capture, storage and monitoring in geological landform

Carbon Capture and Storage (CCS) is recognized as a potent strategy for managing the accumulation of human-generated CO2 in the atmosphere, helping to alleviate climate change’s effects. The CO2 gas is captured from the point source through methods such as pre-treating fossil fuels, oxy-fuel combustion, or post-combustion capture; thereafter; it is transported to a storage location and injected into geological formations. This article provides an overview of carbon dioxide capture and sequestration, focusing on its key principles, technologies, associated risks, and challenges. Direct Air Capture (DAC) and Scalable Modelling, Artificial intelligence (Al), Rapid Theoretical calculations SMART technologies are detailed as emerging and promising approaches to CO2 capture. Numerous pilot and commercial projects commissioned to manage carbon dioxide emissions are presented. Additionally, the paper explores approaches combining geological, geophysical, geochemical, and environmental monitoring techniques to ensure the secure and sustainable storage of CO2 underground. These are essential to address uncertainties, minimize risks, and build public confidence in CCS as a viable climate mitigation strategy. The successful deployment of these technologies on a global scale will require continued innovation, particularly in the areas of monitoring, risk management, and public engagement. Emerging technologies such as AI and SMART systems could play a crucial role in enhancing the efficiency and safety of CCS operations. However, the integration of these advancements with existing infrastructure and regulatory frameworks remains a challenge. Ultimately, a multi-disciplinary approach, combining technological, economic, and regulatory perspectives, will be vital to realizing the full potential of CCS in combating climate change.

Integrated modelling of CO2 plume geothermal energy systems in carbonate reservoirs: Technology, operations, economics and sustainability

The rising CO2 content in the atmosphere calls for urgent decarbonization efforts. Carbon capture and storage (CCS) have proven effective in storing large volumes of CO2 in geological reservoirs. Nevertheless, challenges persist in identifying sustainable energy sources and efficient storage sites, especially in carbonate reservoirs. This study aims to characterize the Miocene carbonate reservoir in the Jintan Megaplatform, for CO2 storage and geothermal energy utilization. By integrating advanced technologies such as CO2 Plume Geothermal (CPG) with 3D seismic techniques, borehole analysis and numerical modelling, the study reveals the distribution of critical reservoir characteristics, including architecture, heterogeneity, karstification, fractures, porosity, permeability, temperature and pressure that are paramount for CO2 plume and energy production. The reservoir is estimated to store over 31 Gt of CO2, produce 3.824 × 1018 J of geothermal energy and ⁓44.3 GW of power. This power output can be utilized for electrification of the CCS operations, industrial and municipals, potentially generating over $1.4 billion in revenue. A flow-through model has been proposed to improve energy efficiency, reservoir management, and risk mitigation. This study advances to achieving net-zero targets and the United Nations Sustainable Development Goals on clean energy, climate action and sustainable communities.

Optimization of Well Placement in Carbon Capture and Storage (CCS): Bayesian Optimization Framework under Permutation Invariance

Carbon Capture and Storage (CCS) stands as a pivotal technological stride toward a sustainable future, with the practice of injecting supercritical CO2 into subsurface formations being already an established practice for enhanced oil recovery operations. The overarching objective of CCS is to protract the operational viability and sustainability of platforms and oilfields, thereby facilitating a seamless transition towards sustainable practices. This study introduces a comprehensive framework for optimizing well placement in CCS operations, employing a derivative-free method known as Bayesian Optimization. The development plan is tailored for scenarios featuring aquifers devoid of flow boundaries, incorporating production wells tasked with controlling pressure buildup and injection wells dedicated to CO2 sequestration. Notably, the wells operate under group control, signifying predefined injection and production targets and constraints that must be adhered to throughout the project’s lifespan. As a result, the objective function remains invariant under specific permutations of the well locations. Our investigation delves into the efficacy of Bayesian Optimization under the introduced permutation invariance. The results reveal that it demonstrates critical efficiency in handling the optimization task extremely fast. In essence, this study advocates for the efficacy of Bayesian Optimization in the context of optimizing well placement for CCS operations, emphasizing its potential as a preferred methodology for enhancing sustainability in the energy sector.

DECARBONIZING A THAI COAL POWER PLANT: EFFECT OF FLUE GAS LOADS ON CARBON CAPTURE PERFORMANCE AND ECONOMICS

Abstract: The objectives of this study are to evaluate the technical and cost implications of retrofitting post-combustion Carbon Capture and Storage (CCS) in existing coal-fired power plants in Thailand, with a special focus on the Mae Moh plant managed by the Electricity Generating Authority of Thailand (EGAT). We undertake a detailed analysis using AspenPlus simulation models to determine the optimum capture cost per ton of CO2 and to examine the effects of various flue gas loads on CO2 capture performance and cost-effectiveness. The research reveals a key operational insight: as the flow rate of flue gas increases, the cost to capture a ton of CO2 decreases, indicating economies of scale in CCS operations. Furthermore, the study explores the potential for integrating solar photovoltaic (PV) technology as a renewable energy source, which shows promise in lowering Thailand's power sector emissions and operational costs. By comparing the levelized cost of electricity (LCOE) for solar PV against conventional coal-fired power generation and considering the country's favorable geographic and climatic conditions, solar PV emerges as an economically viable and environmentally sustainable alternative. The findings of this research aim to inform strategic energy policy decisions in Thailand, advocating for a transition to more sustainable energy systems and emphasizing the balance between environmental responsibility and economic feasibility.

Long range acoustic detection of gas bubbles in a shallow water coastal environment

As the world economy moves to net zero carbon dioxide (CO2) emissions, carbon capture and storage (CCS) is recognised a mitigation mechanism in the suite of technology options. Liquified CO2 injection into offshore subsea reservoirs will be one of the CCS strategies used. Despite being improbable, CO2 leaks could occur and impact the effectiveness of this CO2 mitigation option and undermine confidence in its use as part of the suite of tools to combat climate change. To satisfy public safety expectations and environmental regulatory requirements, long-term measurement, monitoring, and verification (MM&V) plans that are affordable will be needed as part of any commercial CCS operation. Active acoustic methods are a well-suited technique as they can detect gas bubbles in the water column at extremely low flow rates. A bespoke detection system, the Echosounder Detection of Gas Events (EDGE) was developed with the goals of long-duration monitoring and detection of low flow gas bubble releases at long ranges; the literature suggests flow rates of <2 L min−1 will be readily detectable using active acoustics, well below the upper limits of a release of 1 % of stored CO2 over a 1000 year timeframe proposed by IPCC (2005). The EDGE system was housed on a seafloor lander with a battery powered scientific echosounder connected to a narrow-beam horizontally orientated transducer mounted on a turret that rotates through 360 deg. The effectiveness of the EDGE system was tested in a range of weather conditions during two six-month deployments in ∼ 20 m depth at a proposed CCS storage site, CarbonNet, situated off the coast of Victoria, Australia. Separate experiments with controlled gas releases were conducted at a local site at Hobart, Australia to establish the detection capability at range for low flow rates. These experiments found very small gas-releases (< 2 L min−1) could be detected at ranges of up to 378 m. The ability of long-term deployment of the EDGE at the proposed CCS site and the local experiments establishing range-detection ability have demonstrated that active acoustic systems can meet the dual objectives of sustained and wide-area monitoring as a key part of an aquatic based MM&V framework.

Modeling Self-Sealing Mechanisms in Fractured Carbonates Induced by CO2 Injection in Saline Aquifers.

In the future, there will be competition among natural gas, CO2, and hydrogen for suitable geological storage sites. Therefore, it is crucial to evaluate all of the potential storage options. One promising option is the utilization of fractured carbonate rocks, which offer significant opportunities for gas sequestration in depleted reservoirs and saline aquifers. The objective of this study is to assess the feasibility of using carbonate matrix rocks in saline aquifers for carbon capture and storage (CCS) projects. Although carbonate reservoirs are currently not ranked highly for carbon storage due to the risk of CO2 leakage, their matrix rock with reactive minerals like calcite and dolomite, along with the possibility of natural fractures, presents an interesting opportunity. This research proposes a reassessment of the role of fractures, which are typically viewed as a risk factor, within a novel and integrated context. It combines geochemical modeling with numerical models that incorporate two distinct density levels of natural fractures. The interactions between the carbonate matrix, the formation brine, and the injected CO2 can lead to water vaporization and the deposition of evaporite minerals, known as the halite scale, within the porous medium. These minerals can be transported within highly conductive fractures that possess a permeability 100 times greater than the matrix. The study findings indicate that the fractures become filled, creating a natural seal that prevents CO2 leakage through what was previously considered a potential pathway in both models and different initial pH values. Furthermore, the results demonstrate the formation of secondary minerals through the reaction of CO2 and its aqueous counterparts with rock matrix minerals. These minerals, including Dawsonite, are then deposited within fracture apertures, compensating for the dissolution of calcite from the matrix and reducing the risk of enhanced fracture conductivity during CCS operations. The deposition of halite scales in initially acidic-brine saturated aquifers and/or Dawsonite scales in initially alkaline-brine saturated aquifers serves to partially counterbalance the permeability enhancement resulting from calcite dissolution. This phenomenon makes carbonate rocks a more secure option and highlights their potential suitability for CCS projects. The existence of these scales acts as a protective barrier, reducing the risk of increased permeability and enhancing the integrity of the storage reservoir.

Review on Geopolymers as Wellbore Sealants: State of the Art Optimization for CO2 Exposure and Perspectives.

Wellbores used in underground production and storage activities, including carbon capture and storage (CCS), are typically sealed using sealants based on Ordinary Portland Cement (OPC). However, leakage along these seals or through them during CCS operations can pose a significant threat to long-term storage integrity. In this review paper, we explore the potential of geopolymer (GP) systems as alternative sealants in wells exposed to CO2 during CCS. First, we discuss how key parameters control the mechanical properties, permeability, and chemical durability of GPs based on different starting materials as well as their optimum values. These parameters include the chemical and mineralogical composition, particle size, and particle shape of the precursor materials; the composition of the hardener; the chemistry of the full system (particularly the Si/Al, Si/(Na+K), Si/Ca, Si/Mg, and Si/Fe ratios); the water content of the mix; and the conditions under which curing occurs. Next, we review existing knowledge on the use of GPs as wellbore sealants to identify key knowledge gaps and challenges and the research needed to address these challenges. Our review shows the great potential of GPs as alternative wellbore sealant materials in CCS (as well as other applications) due to their high corrosion durability, low matrix permeability, and good mechanical properties. However, important challenges are identified that require further research, such as mix optimization, taking into account curing and exposure conditions and available starting materials; the development of optimalization workflows, along with building larger data sets on how the identified parameters affect GP properties, can streamline this optimization for future applications.

ESG Poster ESG7: Marine measurement, monitoring and verification for offshore carbon storage projects – learnings from a coastal Gippsland setting

Poster ESG7 Designing cost-effective methods for implementing measurement, monitoring and verification (MM&amp;V) plans for subsea CO2 storage is an active area of research globally. Despite some preliminary research and examples overseas, there remains a lack of established protocols and configurations for offshore carbon capture and storage (CCS) monitoring overlying storage sites and an absence of methods to establish environmental impact in the event of leakage. Over the last 4 years, CSIRO in collaboration with ANLEC R&amp;D and CarbonNet have been undertaking research in the Gippsland region to inform the development of assurance monitoring approaches for subsea CCS operations to address three key technical assurance monitoring challenges: The ‘signal-to-noise’ problem: distinguishing CO2 release signatures from similar naturally occurring variability to reduce false alarm rates in future baseline monitoring design; characterising impact: determining the level of CO2 release that would be associated with environmental impact at a range of scales; and attributing impact: distinguishing changes resulting from other drivers and pressures in multiple-use zones (e.g. climate change) from the activities of CCS operations. The research has included a wide variety of approaches and technologies including the development and testing of fixed and mobile autonomous monitoring systems, chemical and acoustic sensing and the collection of biological datasets. These data have been used in the development of biogeochemical models and to define possible integrated MM&amp;V frameworks. This paper will summarise this research and identify how it could be applied for offshore CO2 storage projects around Australia. To access the poster click the link on the right. To read the full paper click here

Marine measurement, monitoring and verification for offshore carbon storage projects – learnings from a coastal Gippsland setting

Designing cost-effective methods for implementing measurement, monitoring and verification (MM&amp;V) plans for subsea CO2 storage is an active area of research globally. Despite some preliminary research and examples overseas, there remains a lack of established protocols and configurations for offshore carbon capture and storage (CCS) monitoring overlying storage sites and an absence of methods to establish environmental impact in the event of leakage. Over the last 4 years, CSIRO in collaboration with ANLEC R&amp;D and CarbonNet have been undertaking research in the Gippsland region to inform the development of assurance monitoring approaches for subsea CCS operations to address three key technical assurance monitoring challenges: The ‘signal-to-noise’ problem: distinguishing CO2 release signatures from similar naturally occurring variability to reduce false alarm rates in future baseline monitoring design; characterising impact: determining the level of CO2 release that would be associated with environmental impact at a range of scales; and attributing impact: distinguishing changes resulting from other drivers and pressures in multiple-use zones (e.g. climate change) from the activities of CCS operations. The research has included a wide variety of approaches and technologies including the development and testing of fixed and mobile autonomous monitoring systems, chemical and acoustic sensing and the collection of biological datasets. These data have been used in the development of biogeochemical models and to define possible integrated MM&amp;V frameworks. This paper will summarise this research and identify how it could be applied for offshore CO2 storage projects around Australia.

Quest CCS facility: Time-lapse seismic campaigns

In August 2015, CO2 injection commenced at the Quest Carbon Capture and Storage (CCS) Facility located near Fort Saskatchewan, Alberta, Canada. Quest is a fully integrated CCS operation with a capture target of just over one million metric tonnes of CO2 per year. CO2 is injected into a deep saline aquifer, the Basal Cambrian Sandstone (BCS), at a depth of about two kilometers below ground.In order to demonstrate containment and conformance of the injected CO2, a Measurement, Monitoring and Verification (MMV) plan has been implemented. Multiple domains are monitored as part of the plan, including the atmosphere, biosphere, hydrosphere, geosphere, and wells. Time-lapse seismic methods are utilized primarily for conformance monitoring and secondarily for containment monitoring of the CO2 plume within the Geosphere domain. These methods currently include 3D surface seismic (SEIS3D), 2D surface seismic (SEIS2D) and 2D multi-azimuth walk-away borehole vertical seismic profiles with distributed acoustic sensing (VSP2D).The first goal of this paper is to summarize the role of seismic, subsurface modeling efforts and the different baseline and monitor datasets that have been acquired at the Quest CCS Facility. The second goal is to describe the current Quest time-lapse strategy. Five key seismic acquisition campaigns have occurred at Quest through the pre- and post-start of injection periods, including an initial SEIS3D acquisition, a pre-injection baseline VSP2D acquisition, and three monitor VSP2D acquisitions. SEIS2D acquisitions have also been acquired as part of two of the most recent monitor campaigns. All campaigns have occurred over the winter season, to facilitate surface access, minimize impact on the land and farming/harvest activities, and to ensure maximum repeatability. Time-lapse seismic methods yield an image of the CO2 that is injected into the BCS pore space, displacing some of the brine in the saline aquifer. Since the injected CO2 is more compressible and less dense than brine, the velocity of seismic primary-waves traveling through the BCS is reduced in those places containing CO2 and remain unchanged elsewhere.Petrophysical data from the injection wells (IWs) were used to calculate the acoustic properties of the BCS. Gassmann fluid substitution was used to model the effect of CO2 saturation on the expected seismic response. Modeling showed that differences in the seismic images of the BCS obtained before and during CO2 injection should be seen in two characteristics ways:1) Travel-times across the BCS increase due to the slower primary-wave velocity inside the BCS.2) Reflections from the base of the BCS become stronger as the impedance contrast with the underlying granite basement increases. The contrast between the BCS and underlying basement is much larger than between the BCS and the overlying sediments. The large contrast between the BCS and basement produces a prominent reflection which is easily mapped during baseline and monitor surveys and is more practical for amplitude extractions.Modeling also indicated that, while the acoustic changes are sufficient to define the CO2 front qualitatively, it is unlikely that they can be used to quantify the distribution of CO2 saturations within the plume.The initial time-lapse seismic strategy called for SEIS3D to be employed after a few years of injection. Borehole distributed acoustic sensing (DAS) VSPs were proposed as a cost-effective and flexible alternative to SEIS3D while injection volumes are small. With the optical fiber cemented in place behind the casing, data can be acquired at any time without suspending injection, something not achievable with conventional VSPs that use retrievable downhole geophone arrays. The effectiveness of VSPs is inherently dependent upon the injection volume, plume offset from the IWs and acquisition geometry. After evaluating the concentric plumes predicted from dynamic modeling results and considering the acquisition logistics at the Quest CCS well sites, a VSP2D program was executed.In 2017 and 2019, SEIS2D was recorded in addition to the VSP2D surveys. Surface geophones were deployed along the VSP2D shot locations, recording a pseudo-3D or cross-spread survey. SEIS2D will be evaluated as another seismic method to potentially monitor CO2 plume development in the BCS.

Potential of CO2-enhanced oil recovery coupled with carbon capture and storage in mitigating greenhouse gas emissions in the UAE

The potential of adopting CO2-Enhanced Oil Recovery (EOR) coupled with Carbon Capture and Storage (CCS) at a large scale is significant for major oil exporters like the United Arab Emirates. We develop a system dynamics model of the interactions between the demand of CO2-EOR to sustain oil output as reservoirs age, the country's production targets, and the required carbon prices to accelerate the adoption of CO2-EOR with CCS. We simulate 12 scenarios that represents different pathways for oil production, CO2 emissions growth and performance of CO2-EOR. The scenarios consider the sensitivity to key parameters: net utilization factor of CO2 for the marginal barrel of oil produced, the time it takes for injected CO2 to reach the production well (breakthrough time), and the share of EOR wells going to CO2-EOR operation. We find that a carbon price of 10–15 $/t CO2 in the first decade is needed in order to offset the cost of the CCS operations with the potential of breaking even by 2030. The large-scale adoption of CO2-EOR with CCS in the UAE can help in meeting 2.2–39.2% of the UAE 2nd national committed reduction target, i.e., 72.85 million tons of CO2 reduction per year by 2030, depending on CO2 breakthrough time and its net utilization factor. It may also help in freeing natural gas that could supply 12–20% of local energy needs extending its use with the CCS system. This study demonstrates a systematic modeling approach that quantifies complex interactions at the system level towards cleaner production practices.

Carbon Storage Resource Assessment of the Mid-Atlantic U.S. Offshore Region

Carbon capture and storage (CCS) is a critical technology for ensuring a range of clean energy options are available to meet future energy demands. Offshore storage can be linked to large point-sources of carbon dioxide (CO2) while avoiding many of the logistical difficulties and potential risks encountered when siting onshore projects, especially in densely populated areas of the East Coast of the United States. Offshore storage along mid-Atlantic region was studied under the U.S. Department of Energy (DOE) funded Mid-Atlantic U.S. Offshore Carbon Storage Resource Assessment Project (MAOCSRAP) and as a subtask under the Midwest Regional Carbon Sequestration Partnership (MRCSP). The assessment was conducted as a technical collaboration between Battelle, Rutgers University, Lamont-Doherty Earth Observatory at Columbia University, state geological surveys of Delaware, Maryland and Pennsylvania, United States Geological Survey-Woods Hole Coastal and Marine Science Center, and Harvard University. Major objectives were to complete a systematic carbon storage resource assessment of the of the mid-Atlantic offshore coastal region from the Georges Bank Basin (GBB) through the Long Island Platform (LIP) to the southern Baltimore Canyon Trough (BCT), examine offshore storage risk factors, and engage industry and regulatory stakeholders through development of a Road Map to assist future project planning and implementation. Various publicly available data sets, such as seismic data, well-logs, and core data, were integrated to define geologic characteristics of candidate storage sites and calculate prospective CO2 storage resources for Cretaceous- and Jurassic-age sandstone sequences of the mid-Atlantic offshore sub-regions. The combined dataset helped to identify and map potential storage zones within sequences of the Logan Canyon, Missisauga, and Mohawk formations, as well as the regionally extensive caprock comprised of the Dawson Canyon shale. Prospective storage resource estimates and formation-specific storage efficiency values were calculated with static volumetric and dynamic methods. Regional-scale estimates range from 150 to 1136 gigatonnes (Gt) for the combined storage zones, with high estimated storage resource (≥ 2.4 megatonnes [Mt] CO2/km2) occurring in the northern BCT near the Great Stone Dome (GSD) structure. Results of local scale simplified dynamic reservoir simulation in the GSD indicate that injection rates of 1 Mt CO2/year may be sustained within the time and pressure constraints assumed for a commercial storage project. An initial, qualitative assessment of technical risk factors present in mid-Atlantic offshore areas was conducted. Overall, the mid-Atlantic offshore area benefits from the large spatial extent, thick sequences of sands, lack of previous oil and gas wellbores, and distance from populated development. Geomechanical stability, reservoir variability, and soft sediment deformation were identified as moderate risk factors in some areas. No highly critical risk factors were identified that would impede CO2 storage along the study areas. Input and participation from government, industry, and environmental groups helped to address next steps needed for future CCS project planning and implementation in the study region. Recommended near-term actions are to develop site screening through advanced geologic modeling, implement stakeholder outreach and risk mitigation strategies, identify industry and research goals, and develop regulatory pathways. Recommended mid-term actions are to validate subsurface properties with new data, conduct a cost-benefit analysis, and develop a monitoring, verification, and accounting (MVA) plan. Long term-recommended actions are to implement a plan for large-scale CCS operations using the previous findings, conduct site design, permitting, and construction, and upscale infrastructure. This project represents an important first step by completing a high-level CO2 storage resource assessment and building the knowledge infrastructure necessary to support the development of full-scale offshore carbon storage.

Tools and options for hydrogen and CCS cluster development and acceleration – UK case study, ELEGANCY project

Development of hydrogen and Carbon Capture and Storage (CCS) in the United Kingdom is investigated for the UK by research in the ELEGANCY Project to accelerate carbon dioxide (CO2) emissions reduction. Industry plans and concepts including large-scale production of hydrogen with CCS (H2-CCS) are used to estimate the potential magnitude and rate of CO2 supply for the Grangemouth and Teesside industrial sites. Annual emissions reductions from these two sites by CCS operations could exceed 30 million tonnes (Mt) by 2035 and 50 Mt by 2045. Implementation of carbon-negative technologies would increase these estimated reductions. The application of the H2-CCS chain tool to Great Britain has identified the resource and technology needs for scaling up the H2 economy. It has also highlighted challenges to overcome such as the increased costs, magnitude of H2 and CO2 storage requirements, reduction in upstream emissions, etc. Importantly, there is an urgent need for policy makers, regulators, suppliers, and consumers to coordinate their efforts to achieve timely progress towards net-zero in a socially responsible manner. An application of the business model and business case assessment methodology and tools to the delivery of large-scale H2-CCS infrastructure for decarbonising residential heating in the north of England is presented. A resulting high-level system business model which allows the removal of the investment barriers and addresses major business risks to investment is defined through realistic risk allocation and collaboration between the public and private sectors. A conceptual business case is articulated with a strategic rationale consistent with support for UK energy system decarbonisation and the UK government’s legal 2050 net-zero emissions target. Recommendations for achieving the first phase of infrastructure development ensuring low regrets outcomes and flexible real options are described.

Properties of Rising Multiple CO2 Droplets under Contamination of SO2: Understanding Scenarios of Leakage to Seawater

Nguyen, T.H.T.; Park, S.W., and Ahn, J., 2020. Properties of rising multiple CO2 droplets under contamination of SO2: Understanding scenarios of leakage to seawater. Journal of Coastal Research, 36(4), 805–811. Coconut Creek (Florida), ISSN 0749-0208.Research on impacts of impurities on the rising of liquid droplets in other liquids is still quite limited, especially when it comes to the behavior of multiple particles. The properties of rising multiple CO2 droplets under contamination of SO2 are investigated in a scenario in which they may leak to the seawater from a pipeline or facility in a Carbon Capture and Storage (CCS) project. The interaction between droplets and their rising properties such as velocity were examined. The results of numerical simulation show that the presence of SO2 changes particles' shape and their rising velocities significantly compared with the single droplet case. This SO2 contamination also caused the repulsion of impure particles even when they were placed close to each other, which was observed as coalescence in the pure CO2 case. Results will help in understanding the impacts of contamination on the rise of multiple CO2 droplets such as that leaked by future CCS operations.

The use of environmental tracers to characterize a leaky CO2 CCS natural analogue site, Soda Springs, Idaho, USA

AbstractLarge‐scale global adoption of carbon capture and storage (CCS) as a means of minimizing atmospheric CO2 emissions requires an unprecedented effort to store gigatons of anthropogenic emissions in the earth's subsurface. Critical to the adoption and ultimate success of CCS is the protection of valuable water resources that may be impacted by leaking CO2 from CCS operations. Therefore, appropriate technical tools and societal controls will need to be developed and evaluated to maximize the atmospheric benefits of CCS while limiting potential deleterious effects of its implementation. Here, we utilize a naturally leaking CO2 system located at Soda Springs, Idaho, USA, as an analogue for industrial‐scale CCS deployment. This site is particularly relevant and useful for studying the consequences of CCS because it allows the examination of geologic systems at temporal and spatial scales not accessible by laboratory and field experiments.The Soda Springs system is an ideal CCS natural analogue site with the source of CO2 occurring at depths and temperatures expected for large‐scale CCS systems. Soda Springs also provides long‐term examples of at least three potential failure modes for CCS systems, including direct migration of CO2 charged brine to the surface via faulting or wells, upward movement of CO2 from the injection‐horizon into over lying shallow aquifers, and the displacement of reservoir brine into shallower aquifers. These failure mechanisms were differentiated and characterized utilizing variations in water chemistry including rare earth elements providing a framework for delineating the movement of CO2‐influenced fluids migrating from deep CCS reservoirs into overlying aquifers. © 2020 Society of Chemical Industry and John Wiley &amp; Sons, Ltd.

CO2 injectivity behaviour under non-isothermal conditions – Field observations and assessments from the Quest CCS operation

Commercial-scale deployment of Carbon Capture and Storage (CCS) as a viable greenhouse gas (GHG) emissions reduction technology requires that the CO2 be continuously injected at predictably significant and cost-efficient rates into geological formations (e.g. deep saline aquifers).The Quest CCS operation (located in Alberta, Canada) is a fully integrated carbon capture, transport and storage facility operated by Shell Canada. Quest continuously captures and stores about 1.1 Mt of CO2 per year, and it’s expected to continue until 2040. Quest is a dedicated geological storage project (no EOR component) with multiple injectors and monitoring wells. Injection operations started in August 2015 and by mid-October 2018, more than 3.45 Mt of CO2 has been stored using only 2 out of 3 planned injection wells. To date Quest has observed significant injectivity variability relating to seasonal variation in injected CO2 and bottom-hole temperatures.The high-resolution time-series data from the Quest operations gathered over the first 3 years of CO2 injection indicate the standard models of CO2 injectivity leave out some important physics. Prior to the start of injection, theoretical CO2 injectivity at the CO2 injector wells was initially modelled and calculated to decrease by ∼5% - 8% with decreasing CO2 bottom-hole temperature within the temperature range 20 °C–60 °C at the wellbore largely due to increased fluid viscosity at lower temperatures. However, field observations made to date at the Quest CCS site indicate an inverse relationship between CO2 injectivity and bottom-hole temperature, where injectivity increases of up to 10% due to colder CO2 have been observed in the bottom-hole temperature range of 21 °C–33 °C. This paper presents the field observations of injectivity compared to the theoretically expected and modelled 3D isothermal and non-isothermal conditions of injectivity at various CO2 bottom-hole temperatures, together with an assessment of the dominant controlling mechanisms and parameters that could influence CO2 injectivity under non-isothermal conditions. The assessment results indicate that the seasonal CO2 injectivity correlating inversely with bottom-hole temperature (BHT), cannot be explained by CO2 PVT behaviour under non-isothermal conditions. The inverse correlation is driven by near-wellbore permeability (k), relative permeability (kr) and (non-darcy) dynamic skin factor parameters varying in an inverse relationship with bottom-hole temperature through reversible temperature-driven mechanism(s) such as fluid flow regime changes, fluid-rock interactions and thermally-induced micro-fractures leading to increases in dynamic injectivity at lower CO2 bottom-hole temperatures.A full understanding of the non-isothermal processes and their relative impacts on CO2 injectivity are not only crucial for successful deployment of CCS projects but can also have wider beneficial applications in CO2-EOR modelling and operations cost optimisation.

Utilization of CO2 to reduce environmental impact of diluted bitumen transportation and improve economics of CCS operations

Environmental impact and economics of Carbon Dioxide (CO2) and bitumen transportation are among the major challenges of oil sands operations. We propose and assess a new approach to address these important challenges by using diluted bitumen (DilBit) as a carrier for large-scale CO2 transportation. The proposed approach provides a unique prospect to significantly reduce the cost of CO2 transportation from the carbon capture and storage (CCS) value chain, facilitate more efficient detection of DilBit spills from pipelines, utilize CO2, and improve public perception of both oil sands and CCS operations. These opportunities will offer the possibility of sustaining access to oil resources while reducing environmental impact and improving the economics of CCS and oil sands operations. Through experimental measurements, we have shown that 80–200 kg of CO2 per m3 of DilBit can be dissolved and transported. We also report simulation results from the simultaneous transportation of DilBit and CO2 and DilBit spill detection through monitoring concentration of leaked CO2.

Application of three-dimensional fault stress models for assessment of fault stability for CO2 storage sites

Carbon Capture and Storage (CCS) is a key technology for a low-carbon energy future and will have an important role on the economic future of the UK Continental Shelf (UKCS). The East Irish Sea Basin (EISB) is a prospective area for CCS in the western UKCS. 3D seismic from the EISB were used in this study to characterise the fault network and potential fault reactivation risks associated with CO2 injection. Two main structural domains are present: a Northern domain with NW-SE faults, and a Southern domain with faults following a N-S orientation. The main storage sites consist of structural closures in Triassic strata of the Sherwood Sandstone Formation (SSF), overlain by alternations of mudstones and evaporites of the Triassic Mercia Mudstone Group (MMG). The closures occur predominantly at fault-bounded horsts, with adjacent grabens filled by thick sequences of the Triassic Mercia Mudstone Group (MMG). The fault framework was used to test, in 3D, the stress model published for the EISB and assess the fault reactivation risk associated with CO2 storage. Slip tendency values were predominantly below 0.6, suggesting the presence of stable structures in the EISB. Under the tested conditions, faults are capable of withstanding pressure increases between 3 MPa and 10 MPa before the onset of slip. The limited fault reactivation risk suggests CCS operations are suitable prospects for the EISB. This work demonstrates the additional value gained from integration of accurately constrained fault geometries in 3D stress models.

Integrative assessment of sediment quality in acidification scenarios associated with carbon capture and storage operations

Efforts to stem global change include the application of new technological developments that aim to reduce atmospheric carbon dioxide (CO2) through the carbon capture and storage (CCS) of this greenhouse gas in stable geological structures. In this paper, we assess the potential risks related to the application of CCS technology and the acidification of aquatic ecosystems through CO2 enrichment. We use the multiple lines of evidence approach (LOEs) to characterize the effects of the acidification with contamination in aquatic sediments. We highlight and discuss the effects of acidification on the LOEs including contamination and mobility of contaminants in sediments, toxicity, macrobenthic community structure, in situ effects, and bioaccumulation–biomagnification processes. We further assess the results of acidification on the toxicity of organic contaminants such as antibiotics or illicit drugs like the freebase form of cocaine (crack). The main goal of using the LOE approach is to distinguish between adverse effects that are associated with contaminants and those related to acidification by enrichment of CO2 as a result of CCS technology. Previous assessments were not designed or conducted to incorporate an integrative point of view, nor did they employ a weight of evidence approach (WOE) in risk characterization and management of CCS operations and other situations related to acidification by enrichment of CO2 in the aquatic ecosystem. Based on the findings of this review, the WOE can identify the effects of the acidification on the different LOEs used for sediment quality: contaminant mobility, the adverse effects in organism under laboratory and field conditions, and the bioaccumulation–biomagnification of contaminants. The main strength in using the WOE is the ability of this method to discriminate between LOE responses associated with contamination by different organic and inorganic substances from those related to CO2 acidification itself. The WOE will significantly improve the risk assessment in areas affected by potential leakages of CO2 during CCS operations.