CO2 Capture And Storage System Research Articles

Carbon Storage Tanker Lifetime Assessment.

CO2 capture and storage (CCS) is an important strategy to reduce global CO2 emissions. This work presents both cutting-edge carbon storage tanker design, as well as novel reliability method making possible to extract useful information about the lifespan distribution of carbon capture systems from their recorded time history. The method outlined may be applied on more complex sustainable systems that are exposed to environmental stresses throughout the whole period of their planned service life. The latter is of paramount importance at the design stage for complex engineering systems. Novel design for CCS system is discussed and accurate numerical simulation results are used to apply suggested novel reliability methodology. Furthermore, traditional reliability approaches that deal with complex energy systems are not well suited for handling high dimensionality and cross-correlation between various system components of innovative dynamic CO2 storage subsea shuttle tanker. This study has two distinctive key features: the state of art CCS design concept, and the novel general purpose reliability method, recently developed by authors, and particularly suitable for operational safety study of complex energy systems.

Modeling the development of a carbon capture and transportation infrastructure for Swedish industry

This work presents and applies a mixed integer programming (MIP) optimization model that minimizes the net present costs for CO2 capture and storage (CCS) systems for cases with defined emissions costs and/or capture targets. The model covers capture from existing large point sources of CO2 emissions in Sweden, liquefaction, intermediate storage and transportation using trucks to hubs on the coast, followed by ship transport to a storage location (excluding storage cost). The results show that the capture and transportation infrastructure, in terms of both the sites chosen for capture and the associated transportation setup, differs depending on whether the system is incentivized to capture biogenic or fossil CO2, or both. Waste-fired combined heat and power (CHP) plants are only chosen for capture at scale when biogenic capture targets and fossil emissions costs are combined, since the emissions from these sites comprise a combination of biogenic and fossil CO2. The value for the system in mitigating the costs from fossil CO2 emissions exceeds the increased cost of BECCS at waste-fired CHPs compared to larger pulp mills given the fossil emissions cost development assumed in this work. Although the cost for capture and liquefaction dominates the total cost of the CCS system, it is not the only factor determining the choice of sites for capture. Proximity to transport hubs with short offshore transportation distances to the final storage location is also an important factor. For the transportation infrastructure, it is shown that the cost for ships is the main cost driver.

CO2 Sequestration Overview in Geological Formations: Trapping Mechanisms Matrix Assessment

This review focuses on the consequences of the early and rapid deployment of carbon dioxide (CO2) capture and storage (CCS) technologies, which is currently recognized as a critical problem in fulfilling climate change mitigation objectives and as a viable alternative for countries throughout the world. Currently, the geological storage of CO2 is the most effective and, in many cases, the only viable short- to medium-term alternative for considerably moving towards CO2 sequestration in geological sinks and, thus, lowering net carbon emissions into the atmosphere. Furthermore, this review explores the global and environmental measurements of CO2 emissions, as well as the emphasis behind more efficient energy usage. The components of the CCS system are briefly examined, with an emphasis on the technologies that have been developed by previous scholars to support carbon capture, as well as the kinds of carbon geological formations that are suitable sinks for CO2. Additionally, the importance of carbon interaction and sequestration in unconventional formations are examined through case studies that are applied to coalbed seams and shale gas reservoirs. Numerous trapping processes are grouped and introduced in a constructive matrix to easily distinguish the broad trapping mechanisms, which are (1) chemical, (2) physicochemical, and (3) physical trapping, and each of these categories are further classified in depth based on their contribution to CO2 storage.

China’s coal power decarbonization via [formula omitted] capture and storage and biomass co-firing: A LCA case study in Inner Mongolia

In this study, a membrane-based CO2 capture and storage (CCS) chain and a co-firing system of coal and biomass were virtually implemented in an existing coal power plant in Inner Mongolia. Three life cycle assessment (LCA) models were developed to evaluate the environmental performance of the power generation system under business-as-usual (BAU) conditions and with the implementation of the selected technologies. The CCS system reduced CO2 emissions from the power plant by about 90%, but significantly increased upstream emissions, limiting the LCA mitigation potential to 37%–48% of the 1.14 kg CO2/kWh estimated for the BAU scenario. Combining biomass co-firing with CCS achieved negative emissions from the power generation stage and reduced the total CO2 emitted under the LCA scope by 57%–67%. However, both technologies had negative impacts on the local environment, which were quantified by a range of indicators such as eutrophication potential (+13%–37%), toxicity for both aquatic (+12%–33%) and terrestrial (+35%–68%) ecosystems, and consumption of freshwater (+46%–61%). The major factors preventing a more significant mitigation of CO2 emissions and shifting the environmental burden to local ecosystems were the increased electricity and coal consumption for implementing CCS and the reliance on diesel and artificial fertilizers in the biomass supply chain.

Review on Carbon Capture in ICE Driven Transport

The transport sector powered by internal combustion engines (ICE) requires novel approaches to achieve near-zero CO2 emissions. In this direction, using CO2 capture and storage (CCS) systems onboard could be a good option. However, CO2 capture in mobile sources is currently challenging due to the operational and space requirements to install a CCS system onboard. This paper presents a systematic review of the CO2 capture in ICE driven transport to know the methods, techniques, and results of the different studies published so far. Subsequently, a case study of a CCS system working in an ICE is presented, where the energy and space needs are evaluated. The review reveals that the most suitable technique for CO2 capture is temperature swing adsorption (TSA). Moreover, the sorbents with better properties for this task are PPN-6-CH2-DETA and MOF-74-Mg. Finally, it shows that it is necessary to supply the energy demand of the CCS system and the option is to take advantage of the waste heat in the flue gas. The case study shows that it is possible to have a carbon capture rate above 68% without affecting engine performance. It was also found that the total volume required by the CCS system and fuel tank is 3.75 times smaller than buses operating with hydrogen fuel cells. According to the review and the case study, it is possible to run a CCS system in the maritime sector and road freight transport.

The Carbonation of Wollastonite: A Model Reaction to Test Natural and Biomimetic Catalysts for Enhanced CO2 Sequestration

One of the most promising strategies for the safe and permanent disposal of anthropogenic CO2 is its conversion into carbonate minerals via the carbonation of calcium and magnesium silicates. However, the mechanism of such a reaction is not well constrained, and its slow kinetics is a handicap for the implementation of silicate mineral carbonation as an effective method for CO2 capture and storage (CCS). Here, we studied the different steps of wollastonite (CaSiO3) carbonation (silicate dissolution → carbonate precipitation) as a model CCS system for the screening of natural and biomimetic catalysts for this reaction. Tested catalysts included carbonic anhydrase (CA), a natural enzyme that catalyzes the reversible hydration of CO2(aq), and biomimetic metal-organic frameworks (MOFs). Our results show that dissolution is the rate-limiting step for wollastonite carbonation. The overall reaction progresses anisotropically along different [hkl] directions via a pseudomorphic interface-coupled dissolution–precipitation mechanism, leading to partial passivation via secondary surface precipitation of amorphous silica and calcite, which in both cases is anisotropic (i.e., (hkl)-specific). CA accelerates the final carbonate precipitation step but hinders the overall carbonation of wollastonite. Remarkably, one of the tested Zr-based MOFs accelerates the dissolution of the silicate. The use of MOFs for enhanced silicate dissolution alone or in combination with other natural or biomimetic catalysts for accelerated carbonation could represent a potentially effective strategy for enhanced mineral CCS.

Multi-stage Stochastic Optimisation of a CO2 Transport and Geological Storage in the UK

Deterministic whole system multi-stage optimisation frameworks provide valuable insights into the cost effective design and operation of CO2 capture and storage (CCS) systems. However commercial deployment of CCS faces significant technical and economic uncertainties, which necessitate flexibility in system development strategies as well as coordination of all aspects of a CCS system across both time and space. This paper builds on a whole system dynamic CCS optimisation tool developed at Imperial College and presents a mixed integer linear programming approach for multi-stage multi-scenario stochastic optimisation of a spatially explicit integrated CCS system under uncertainty. The model provides great advantages through flexible strategies for all potential system state changes at every stage and early one-fit-for-all investment solutions that minimise financial loss and offer operational flexibility. The model is showcased through a case study set in the UK between 2015-2050 focusing on the techno-economic performance of the CCS value chain and considering uncertainties in the financial market and the storage capacity within a portfolio of Southern North Sea saline aquifer and depleted oil and gas fields.

CCS on Offshore Oil and Gas Installation - Design of Post-Combustion Capture System and Steam Cycle

Most of the released CO2 on offshore oil and gas installation originates from the gas turbines that power the installations. For certain offshore installations, CO2 capture and storage (CCS) could be an alternative to decrease the CO2 emissions. When opting for a chemical absorption CO2 capture system, a heat source for the stripper reboiler is needed. Since most offshore installations are powered by simple cycle GTs, there is typically no steam available that could be used for stripper reboiler heat. A compact steam bottoming cycle could, in addition to providing the reboiler steam, partly or fully provide power from a steam turbine generator to the equipment in the CCS system, including CO2 compressors, pumps, and flue gas booster fan. Three different steam cycle configurations were designed, modeled, and simulated. The design of the post-combustion CO2 capture system is also presented but the main focus in the paper is on the steam cycle design. In addition to the energy and mass balance results, a weight assessment of the major equipment was done with the objective to come up with a simplified weight relationship for changes in the oil and gas installation size in terms of changes in total mass flow from the gas turbines. A steam cycle with a back-pressure steam turbine was ultimately selected. The back-pressure option was able to provide all necessary steam and power (with some margin) to the CO2 capture and compression system.

Performance Modeling of Integrated Chemical Looping Air Separation and IGCC with CO2 Capture

A new power cycle system composed of chemical looping air separation (CLAS) and integrated gasification combined cycle (IGCC) with CO2 capture and storage (CCS) is presented and analyzed. Key issues of the CLAS-IGCC–CCS system and corresponding solutions are proposed and explained in this work. A conceptual CLAS-IGCC–CCS system is set up, and its performance is modeled and validated. In the CLAS-IGCC–CCS system, the CLAS subsystem is used to supply O2 for the coal gasification in the IGCC subsystem, and Mn2O3/Mn3O4 is selected as the suitable oxygen carrier. The temperature of the reduction reactor (TRR) should be kept at 850 °C to obtain high cold gas efficiency (CGE) and high system efficiency (SE). The oxygen to coal mass ratio (OTCR) and the water to coal mass ratio (WTCR) should be kept around 0.7 and 0.06, respectively, to achieve high CGE and SE. The clean syngas from the coal gasification process then burns with air in the gas turbine combustor. The heat recovery boiler with three-pressure reheat is chosen to recover the waste heat from the gas turbine. Chemisorption using monoethanolamine (MEA) is used for CO2 capture in the CCS subsystem. With the optimized parameters, the CGE of 82.55% and the SE of 46.22% can be reached for the CLAS-IGCC–CCS system.

Can CCS save coal fired power plants – The European perspective

The purpose of this paper is to evaluate the carbon dioxide (CO2) emission costs of a coal fired independent power producer (IPP) operating in the European Union (EU). To meet its CO2 emission obligations the IPP has to choose between purchasing emission unit allowances (EUA) through EU Emission Trading Scheme and installing a CO2 capture and storage system (CCS). Since there are significant differences and inconsistencies in the existing studies, our goal is to clearly identify the key drivers behind CCS costs and to analyze the technical and economic viability of coal fired IPPs. An important question tackled in this paper is: at what EUA price level does an IPP with CCS technology become competitive in the current market?In this paper, we expand the existing equations for calculating cost metrics by directly accounting for the chemical properties of the feedstock. Instead of using a deterministic or a scenario-based approach, we apply parametric estimation of relevant variables. Our Monte Carlo simulations show that under the current regime of electricity and EUA price level, an EU based coal fired IPP is, at best, only marginally profitable while an identical IPP with CCS technology is completely unviable.

Interdependent ranking of sources and sinks in CCS systems using the analytic network process

CO2 capture and storage (CCS) is widely regarded as an important low-carbon technology for reducing greenhouse gas emissions from large industrial point sources. It entails the capture of a relatively pure CO2 from exhaust gases using different techniques, and then storing this captured gas in various geological sinks. Large-scale deployment of CCS requires the comprehensive evaluation of candidate sources and sinks present in a given geographical region. In this study, we propose an analytic network process (ANP) approach to rank simultaneously the potential CO2 sources and sinks in a CCS system. Such ranking can be used to identify sites for CCS demonstration projects. This ANP decision model allows us to incorporate the feedback dependency that exist in the preference ranking of sources and sinks due to the importance of geographic proximity as a decision criterion. A case study is then solved to demonstrate the proposed model.

The improved ChinaCCS decision support system: A case study for Beijing–Tianjin–Hebei Region of China

Wide employment of CO2 capture and storage (CCS) technology is of great importance to the sustainable development of China thanks to its contributions to climate change mitigation. Considering the fact that coal accounts for over 65% in the primary energy consumption mix of China, commensurate infrastructure should be built up to transport CO2 to storage sinks from emission sources. The paper presents the improved ChinaCCS Decision Support System (DSS), a tool developed by the General Algebraic Modeling System (GAMS) for optimizing CO2 transportation network given a set of sources and sinks by generating a fully integrated, cost-minimizing CCS system. The improved ChinaCCS DSS assists in determining the sources, sinks and amounts for CO2 capture and sequestration, as well as the paths and sizes of pipelines, while minimizing the net present value for sequestrating a given amount of CO2. Pipeline construction costs take into account topographic conditions such as slopes, heavily populated areas, rivers, railway, highway, etc. A case study for Beijing–Tianjin–Hebei Region of China was demonstrated in the paper. The results highlighted the importance of systematic planning for CCS infrastructure.

Design of carrier-based offshore CCS system: Plant location and fleet assignment

As part of efforts to mitigate the global effects of greenhouse gases from fossil fuels, CO2 Capture and Storage (CCS) technology has drawn large attention from the engineering research community. Compared to a pipeline-based system, an offshore CCS system using Liquefied CO2 (LCO2) carrier ships and offshore oil wells is expected to offer a more flexible and efficient mode of CCS to many countries, especially nations such as Korea where a pipeline-based system is inherently infeasible. In this paper we discuss a carrier-based offshore CCS system, in which CO2 carriers may transport crude oils on inbound voyage, and seek the optimal configuration of the system including liquefaction plant location, fleet assignment, and the optimal pressure and temperature of the cargo CO2. We determine the optimal system configuration including the liquefaction plant location and CO2 carrier fleet assignment with respect to the overall transport cost of the CCS system. We use two sequential linear programming problems – plant location and fleet assignment, with the pressure and temperature state of cargo CO2 as the key CCS chain parameters. We find that the optimal state of CO2 at each stage in the system can deviate from the triple point, depending on the system's configuration and throughput. As a case study, we demonstrate that the optimal cargo state can be different from the triple point depending on the system configuration. In this case it is −39°C and 10bar and the overall transport cost of CO2 sequestration is 26.7USD/ton. This result is based on the specific scenario of the CO2 Capture and Storage system for Korea using southeastern Asian offshore oil wells.

Carbon chain analysis on a coal IGCC — CCS system with flexible multi-products

A carbon chain analysis is applied to assess a complex energy conversion system with CO2 capture and storage (CCS). A coal integrated gasification combined cycle, with CCS, which co-produces electricity and liquid fuels (IGCC–LF–CCS) is taken as a case study. A process simulation method is used to estimate the technological data, and balance the heat and electricity for the whole system. Carbon and energy flows are calculated to evaluate the mass conversion efficiency and the energy efficiency. The results show that in the case in which one third of the coal is allotted to synthesize liquid fuels, globally 60% carbon is captured for storage, 19% transferred to liquid fuels, 19% emitted to the atmosphere, while the remaining carbon is discharged as waste. For the energy flow, 28.1% of total higher heating value of coal is converted into the liquid fuels. The net electricity efficiency is 20.7% accounting for the power demands by air separation, CO2 capture and compression. Three scenarios with different ratio of resource to produce electricity and liquid fuels with or without CCS have been studied. This work will provide useful information for the coal utilization with CCS in a carbon-constrained world.

A dynamic model for optimally phasing in CO2 capture and storage infrastructure

CO2 capture and storage (CCS) is a climate-change mitigation strategy that requires an investment of many billions of dollars and tens of thousands of miles of dedicated CO2 pipelines. To be effective, scientists, stakeholders, and policy makers will have to understand how as well as when to deploy large-scale CCS infrastructure. This will require comprehensive modeling that takes into account detailed costs, engineering, and environmental concerns. We introduce a new and comprehensive model, SimCCSTIME, that is capable of spatially and temporally optimizing CO2 management—capture, transport, and storage of large quantities of CO2. The model minimizes CCS infrastructure costs while simultaneously deciding where, how much, and when to capture, transport, and store CO2. We demonstrate the SimCCSTIME model using real data from the Texas panhandle. Results show that the model minimizes CCS costs, while meeting rising demand to capture and store CO2, by gradually expanding the CCS network. The model identifies non-intuitive cost savings by overbuilding infrastructure in early time periods, and then fully utilizing this infrastructure in later years. Further, results show that there is significant benefit for planning a cooperative and integrated CCS system. Finally, we show how SimCCSTIME offers significant advantages over myopic models that cannot integrate infrastructure through time.

The Cost of Carbon Capture and Storage for Natural Gas Combined Cycle Power Plants

This paper examines the cost of CO(2) capture and storage (CCS) for natural gas combined cycle (NGCC) power plants. Existing studies employ a broad range of assumptions and lack a consistent costing method. This study takes a more systematic approach to analyze plants with an amine-based postcombustion CCS system with 90% CO(2) capture. We employ sensitivity analyses together with a probabilistic analysis to quantify costs for plants with and without CCS under uncertainty or variability in key parameters. Results for new baseload plants indicate a likely increase in levelized cost of electricity (LCOE) of $20-32/MWh (constant 2007$) or $22-40/MWh in current dollars. A risk premium for plants with CCS increases these ranges to $23-39/MWh and $25-46/MWh, respectively. Based on current cost estimates, our analysis further shows that a policy to encourage CCS at new NGCC plants via an emission tax or carbon price requires (at 95% confidence) a price of at least $125/t CO(2) to ensure NGCC-CCS is cheaper than a plant without CCS. Higher costs are found for nonbaseload plants and CCS retrofits.

HiPACT–advanced CO2 capture technology for green natural gas exploration

Abstract Tens of millions of tons per year of CO 2 are being captured from raw feed gas by natural gas plants using solvent-based technologies comprising a pair of absorber and regenerator, and this CO 2 is then being released to the environment. As interest in reducing CO 2 emissions from natural gas plants has increased in recent years, CO 2 capture and storage (CCS) has gained in importance. However, if a natural gas plant is provided with a CCS system, additional energy is required to compress the captured CO 2 . Therefore, JGC Corporation and BASF SE have started joint development of a new solvent-based CO 2 capture technology, called HiPACT (High Pressure Acid gas Capture Technology), which improves the energy efficiency of the CO 2 capture and compression units in a natural gas plant. HiPACT solvent is robust against the high temperatures associated with solvent regeneration at high pressures. Therefore, the regeneration process used in HiPACT can be operated well above atmospheric pressure, which significantly reduces the energy consumption of the CO 2 compression unit. Further, HiPACT solvent absorbs a larger amount of CO 2 per volume unit than other solvents, thus resulting in lower energy consumption for pumping and regeneration of the solvent. When compared to conventional technology, it is estimated that HiPACT can yield cost reductions of more than 25 percent. A recent pilot test has validated the key features of the HiPACT solvent, its thermal stability and CO 2 absorption performance, and it has been decided to carry out a large-scale demonstration test. This paper presents the results of a batch test and a pilot test, both of which validated the key features of HiPACT, and presents the results of a case study which shows HiPACT’s advantages over state-of-the-art technology currently used worldwide.

Carbon capture and recycle by integration of CCS and green hydrogen

CO2 capture and storage (CCS) system is necessary for drastically reduction of CO2 emission. CCS should be commercialized to prevent global warming before it is too late, but we have to remember CCS is not sustainable energy technology because of the limitation of CO2 storage capacity. CO2 capture and recycle (CCR) system using green hydrogen and current natural gas supplying system is studied in this report. There are several technologies for CO2 capture for distributed CO2 emission sites where natural gas is consumed. These technologies show very high efficiency and capturing CO2 will not lose too much energy. Green hydrogen is produced from renewable energy such as wind power, and shows very small CO2 emission intensity. Producing methane by reaction of captured CO2 and green hydrogen can be a very simple process under optimal reaction conditions. The CCR system can be a post CCS system, and the system is considered to be sustainable.

An integrated approach to CCS: A Canadian environmental superpower opportunity

Abstract The wide-scale public and governmental pressure to reduce the emissions of greenhouse gasses in developed nations has the potential to threaten the future growth and profitability of energy intensive industries. Because of this new paradigm, a group of 20 major oil & gas, power, fertilizer and chemical producers in Canada joined forces in 2005 to form the Integrated CO 2 Network (I CO 2 N) group of companies. This group recognized that developing CO 2 capture and storage (CCS) within a vision of a long -term, large-scale integrated system would ensure that the technology is developed as quickly and cost -effectively as possible, and would encourage continued economi c growth decoupled from increases in greenhouse gas (GHG) emissions. Decisions about a phased and integrated CCS system requires a long -term focus on Canada’s energy and environmental policy objectives (2020 and beyond). This paper outlines the efforts to date by I CO 2 N to move CCS for ward in Canada—through its work on the economics of deploying CCS technology in Canada, what deployment of an integrated CO 2 capture, transportation and storage network can look like and the evaluation of public private partnerships to share in the risks of early CCS adoption. Analysis is presented that quantifies the overall potential of the technology and explores the benefits and costs associated with CCS, including the associated benefits of the development of an EOR industry through the deployment o f an integrated CCS system. It also puts forward 5 key elements of deployment that are necessary to enable the widespread deployment of CCS at lowest possible cost. The I CO 2 N group of companies includes the following nineteen companies: Suncor, TransAlt a, Sherrit, Agrium, Air Products, Shell, Husky, ConocoPhillips, Syncrude, Imperial Oil, Nexen, Canadian Natural Resources Limited, Keyera, EPC OR, Total, Chevron, StatoilHydro, Opti, Devon, and BP.

JGC TO WORK ON CHINESE ETHYLENE GLYCOL PLANT

Tens of millions of tons per year of CO2 are being captured from raw feed gas by natural gas plants using solvent-based technologies comprising a pair of absorber and regenerator, and this CO2 is then being released to the environment. As interest in reducing CO2 emissions from natural gas plants has increased in recent years, CO2 capture and storage (CCS) has gained in importance. However, if a natural gas plant is provided with a CCS system, additional energy is required to compress the captured CO2. Therefore, JGC Corporation and BASF SE have started joint development of a new solvent-based CO2 capture technology, called HiPACT (High Pressure Acid gas Capture Technology), which improves the energy efficiency of the CO2 capture and compression units in a natural gas plant.HiPACT solvent is robust against the high temperatures associated with solvent regeneration at high pressures. Therefore, the regeneration process used in HiPACT can be operated well above atmospheric pressure, which significantly reduces the energy consumption of the CO2 compression unit. Further, HiPACT solvent absorbs a larger amount of CO2 per volume unit than other solvents, thus resulting in lower energy consumption for pumping and regeneration of the solvent. When compared to conventional technology, it is estimated that HiPACT can yield cost reductions of more than 25 percent.A recent pilot test has validated the key features of the HiPACT solvent, its thermal stability and CO2 absorption performance, and it has been decided to carry out a large-scale demonstration test.This paper presents the results of a batch test and a pilot test, both of which validated the key features of HiPACT, and presents the results of a case study which shows HiPACT’s advantages over state-of-the-art technology currently used worldwide.