ΑΝΘΡΩΠΙΝΑ ΙΚΤΥΑ ΕΡΕΥΝΗΤΙΚΗΣ ΚΑΙ ΤΕΧΝΟΛΟΓΙΚΗΣ ΕΠΙΜΟΡΦΩΣΗΣ «ΤΕΧΝΟΛΟΓΙΚΟ ΥΝΑΜΙΚΟ ΓΙΑ ΤΗΝ ΜΕΙΩΣΗ ΤΩΝ ΕΚΠΟΜΠΩΝ ΙΟΞΕΙ ΙΟΥ ΤΟΥ ΑΝΘΡΑΚΑ ΥΝΑΤΟΤΗΤΕΣ ΠΡΟΟΠΤΙΚΕΣ ΤΩΝ ΕΛΛΗΝΙΚΩΝ ΕΠΙΧΕΙΡΗΣΕΩΝ» Φ. ΖΙΩΓΟΥ Θεσσαλονίκη, Ιούνιος 2007
Content CO2 Sources CO2 capture: Post-combustion flue gas separation Pre-combustion (decarbonisation) Oxyfuel technologies CO2 compression and transportation to storage reservoir Storage options for CO2: Types of geological storage projects How to screen reservoirs for suitability of CO2 storage Health, safety and environmental issues associated with CO2 storage Economic considerations of CO2 storage
There are three main approaches that can be used to reduce GHGs: Lowering the energy intensity of the economy by increasing the energy efficiency of energy production, conversion and end use. Lowering the carbon intensity of the energy system - by substituting lower-carbon or carbon-free energy sources, such as renewable energy. Increasing the capacity and capture rate of carbon sinks to store CO2.
It is estimated that approximately 1000 GtC of greenhouse gases may need to be prevented from entering the atmosphere over a 300-year period to keep atmospheric concentrations below 550 ppm. This would stabilize emissions at 2 times the pre-industrial level of 270 ppm. In the longer term, as the use of carbon-based fossil fuels decreases due to diminishing reserves and replacement by other renewable or carbon-free energy forms, storage of CO2 will no longer be as integral a part of the strategy.
CO2 emissions from fossil fuel use CO2 emissions (Mt/yr) 20000 16000 12000 8000 4000 0 power industry transport residential + services 2030 2002 other sectors
Large stationary sources: CO2 emissions over 0.1 MtCO2 yr-1.
Power plants Pulverised coal plants (PC) Natural gas combined cycle (NGCC) Integrated coal gasification combined cycle (IGCC) Boilers fuelled with natural gas, oil, biomass and lignite Future: fuel cells
Pulverised coal plant (PC)
Natural gas combined cycle (NGCC) Flue gas HRSG Fuel compressor Combustion Chamber Gas turbine Steam turbine Air
Integrated coal gasification combined cycle (IGCC)
Power plant overview Plant Capacity (MW e ) Efficiency (% LHV) Capital cost ( /kw e ) PC 500 1000 40-46 46 (up to 50%) 1000-1250 1250 NGCC 100-500 55-58 58 (up to 65%) 500-700 IGCC 250-350 43-45 45 (up to 52%) 1600-1700 1700 (efficiencies forecasted for 2010-2020)
Prospective areas in sedimentary basins where suitable saline formations, oil or gas fields, or coal beds may be found. Locations for storage in coal beds are only partly included. Prospectivity is a qualitative assessment of the likelihood that a suitable storage location is present in a given area based on the available information. Εθνικό Κέντρο Έρευνας και Τεχνολογικής Ανάπτυξης / Regional emission clusters with a 300 km buffer relative to world geological storage prospectivity
Methods for CO2 separation from flue gas: Sorbents/Solvents Low temperature distillation (cryogenic separation) Membrane separation
Separation with sorbents/solvents One problem of these CO2 capture systems is that the flow of sorbent between the vessels is large due to the huge flow of CO2 being processed in the power plant. Therefore, equipment sizes and the energy required for sorbent regeneration are large and tend to translate into an important efficiency penalty and added cost Good sorbent performance under high CO2 loading in many repetitive cycles is obviously a necessary condition in these CO2 capture systems.
Separation with membranes Separation membranes allow for the selective permeation of gases through thin barriers. Their advantage is that they do not require a separating agent, can be easily retrofitted and modularized for various applications, and have low maintenance. A number of solid polymer membranes are used commercially for CO2 separation. They require compression of the feed gas in order to force penetration of the membrane and compression of the separated CO2 for pipeline transport. Compression will add to the cost of this CO2 capture approach.
Separation with membranes The selectivity of the membrane to different gases depends on the nature of the material, but the flow of gas through the membrane is usually driven by the pressure difference across the membrane. High-pressure streams are usually preferred for membrane separation. There are many different types of membrane materials (polymeric, metallic, ceramic) that may find application in CO2 capture systems to preferentially separate H2 from a fuel gas stream, CO2 from a range of process streams or O2 from air with the separated O2 subsequently aiding the production of a highly concentrated CO2 stream. Not yet application for the large scale and demanding conditions in terms of reliability and low-cost required for CO2 capture systems.
Distillation of a liquefied gas stream and refrigerated separation Oxygen can be separated from air, CO2 from other gases and for CO2 removal from natural gas or synthesis gas that has undergone a shift conversion of CO to CO2 (oxy-fuel combustion and pre-combustion capture) or The key issue for these systems is the large flow of oxygen required.
Combining capture routes and technologies: CO2 capture matrix Capture method Principle of separation Membranes Adsorption Absorption Post-combustion decarbonisation Membrane gas absorption Polymeric membranes Ceramic membranes Facilitated transport membranes Carbon molecular sieve membranes Lime carbonation/calcinations Carbon based sorbents Improved absorption liquids Novel contacting equipment Improved design of processes Pre-combustion decarbonisation CO 2 /H 2 separation based on: Ceramic membranes Polymeric membranes Palladium membranes Membrane gas absorption Dolomite, hydrotalcites and other carbonates Zirconates Improved absorption liquids Improved design of processes Denitrogenated conversion O 2 -conducting membranes Facilitated transport membranes Solid oxide fuel cells Adsorbents for O 2 /N 2 separation, perovskites Chemical looping Absorbents for O 2 /N 2 separation Cryogenic Improved liquefaction CO 2 /H 2 separations Improved distillation for air separation
Cement production Εθνικό Κέντρο Έρευνας και Τεχνολογικής Ανάπτυξης / Emissions of CO2 from the cement industry account for 6% of the total emissions of CO2 from stationary sources At present, CO2 is not captured from cement plants, but possibilities do exist. The concentration of CO2 in the flue gases is between 15-30% by volume, which is higher than in fluegases from power and heat production (3-15% by volume). The post-combustion technologies for CO2 capture could be applied to cement production plants, but would require the additional generation of steam in a cement plant to regenerate the solvent used to capture CO2. Oxy-fuel combustion capture systems may also become a promising technique to recover CO2 An emerging option would be the use of calcium sorbents for CO2 capture as calcium carbonate (limestone) is a raw material already used in cement plants.
Post-combustion Capture Systems Absorption processes based on chemical solvents are currently the preferred option for post-combustion CO2 capture. High capture efficiency and selectivity The lowest energy use and costs when compared with other existing postcombustion capture processes. Schematic of a pulverized coal-fired power plant with an amine-based CO2 capture system and other emission controls.
Post-combustion Capture Systems Chemical absorption involves one or more reversible chemical reactions between CO2 and an aqueous solution of an absorbent, such as an alkanolamine. Upon heating the product, the bond between the absorbent and CO2 can be broken, yielding a stream enriched in CO2. The chemical absorption process for separating CO2 from flue gas is widely applied in the gas processing industry. Amine based processes have been used commercially for the removal of acid gas impurities (CO2 and H2S) from process gas streams. Proven and well-known technology.
Typical Chemical Absorption Unit for CO2 Recovery from Flue Gas During the amine absorption operation the waste gas stream and liquid amine solution are contacted by countercurrent flow in an absorption tower
Types of Alkanolamines There are three groups of alkanolamines: primary (RNH2) - one hydrogen molecule has been replaced; secondary(r2nh) - two hydrogen molecules have been replaced; and tertiary(r3n) all three hydrogen molecules have been replaced. MEA (a primary amine) is the solvent of choice because (CO2 + 2RNH2 = RNHCOO- + RNH3+) Is the least expensive of the alkanolamines; Has good reaction kinetics; and Works well at low pressure and low CO2 concentration. There are several disadvantages with MEA: High heat of reaction, hence high energy consumption; Absorptivity with CO2 is not great; LowMEA concentrationinaqueoussolution; High corrosivity; and Foaming problems
There is considerable industrial experience with MEA and most systems at present use an aqueous solution with only 15-25-wt% MEA, mainly due to corrosion issues. Corrosion inhibitors may be added to MEA solution, and this results in an increase in solution strength. However, the packing in the absorber (contactors, to facilitate efficient mass transfer) represents a significant cost, and its energy consumption is also significant for CO2 capture from flue gas. In addition, the stripping temperature should not be too high (~ 150oC). The purity and pressure of CO2 typically recovered from an aminebased chemical absorption process are: CO2 purity: 99.9% by volume or more (water saturated conditions) and CO2 pressure: 50 kpa
Limitations of Amine-based Processes Low pressure. CO2 is absorbed much more easily into solvents at high pressure. The only commercially available solvents that can absorb a reasonable amount of CO2 from dilute atmospheric pressure gas are primary and sterically hindered amines, such as MEA, DGA and KS-1, KS-2 and KS-3 series of solvents These solvents can absorb CO2 at low pressures because they have high reaction energies. This results in high-energy requirements to regenerate the rich solvent. However, energy costs may be reduced if the process can be fully integrated with a power plant where significant amount of low-grade heat may be available.
Limitations of Amine-based Processes Oxygen. Most solvents applicable for flue gas systems degrade to varying degrees in oxidizing atmospheres. This leads to either high solvent losses or expensive reclaiming processes. Oxygen also causes corrosion problems in the process equipment, which can lead to failures or more expensive materials of construction. The use of inhibitors in the solvent to reduce degradation and corrosion appears to work well and produces very good results.
Limitations of Amine-based Processes Sulfur oxides (SO2, SO3) react with MEA to form heat-stable corrosive salts that cannot be reclaimed. Some commercial MEA processes require a sulfur oxides limit of less than 10 ppm level. It is generally accepted that installing a flue gas desulfurization unit before the absorber is the best way to overcome the problem. Nitrogen oxides. A typical flue gas contains some amount of NOx. NOx generally consists of NO and NO2 in a ratio of from 95:5 to 90:10. The main component NO performs as inert gas and will not affect the solvent. However, NO2 will partially lead to the formation of a heat stable salt. Generally some solvent degradation is acceptable in order to avoid the cost of removing the NO2. Particulate matter. Fly ash in the flue gas can cause foaming and degradation of the solvent, as well as plugging and scaling of the process equipment. A wash operation has been recommended to reduce the fly ash content to appropriate levels to abate the aforementioned problems.
Commercially available absorption processes for CO2 capture in post-combustion systems The Kerr-McGee/ABB Lummus Crest Process - This process recovers CO2 from coke and coal-fired boilers. It uses a 15-20% by weight aqueous MEA (Mono-Ethanolamine) solution. The Fluor Daniel ECONAMINE Process - This process was acquired by Fluor Daniel Inc. from Dow Chemical Company in 1989. It is a MEA-based process (30% by weight aqueous solution) with an inhibitor to resist carbon steel corrosion and is specifically tailored for oxygen-containing gas streams. The Kansai Electric Power Co., Mitsubishi Heavy Industries, Ltd., KEPCO/MHI Process - The process is based upon sterically-hindered amines and already three solvents (KS-1, KS-2 and KS-3) have been developed. In this process, low amine losses and low solvent degradation have been noted without the use of inhibitors or additives.
As the CO2 concentration in the flue gas increases, the cost of producing a tonne of CO2 decreases. Figure shows one such relationship using an economic model developed at the Alberta Research Council, Alberta, Canada, based on the Mitsubishi Heavy Industries KS-1 solvent. The cost is in constant 2000 Canadian dollar / tn CO2 captured, and not including any compression cost. Εθνικό Κέντρο Έρευνας και Τεχνολογικής Ανάπτυξης /
Post-combustion capture: Impact on capital costs
Post-combustion capture: Impact on capture costs
Efficiency reference plant P η reference = E η reference = efficiency of plant without CO 2 capture = net power output (MW e ) P = net power output ( E = fossil fuel input (MW( MW th ) Considering fossil energy consumption, CO 2 capture might best be performed at power plants with high electric efficiency
Post-combustion capture: Impact on efficiency
Pre-combustion CO2 Capture Pre-combustion capture is accomplished through the gasification of a hydrocarbon fuel with oxygen to produce a syngas. Syngas is a gas mixture consisting predominantly of hydrogen (H2), carbon monoxide (CO) and CO2. The syngas is an intermediate product, which can then be converted to produce: Hydrogen; Integrated electric power; or Polygeneration wherea range of energy products including power, heat, hydrogen and chemicals. Simplified schematic of a gasification process showing options with CO2 capture and electricity, hydrogen or chemical production.
A pre-combustion capture process typically comprises a first stage of reaction producing a mixture of hydrogen and carbon monoxide (syngas) from a primary fuel. The two main routes are to add steam (reaction 1), in which case the process is called steam reforming, or oxygen (reaction 2) to the primary fuel. In the latter case, the process is often called partial oxidation when applied to gaseous and liquid fuels and gasification when applied to a solid fuel, but the principles are the same. Steam reforming CxHy + xh2o xco + (x+y/2)h2 H +ve (1) Partial oxidation CxHy + x/2o2 xco + (y/2)h2 H ve (2) Water Gas Shift Reaction CO + H2O CO2 + H2 H -41 kj mol-1 (3) Finally, the CO2 is removed from the CO2/H2 mixture. The concentration of CO2 in the input to the CO2/H2 separation stage can be in the range 15-60% (dry basis) and the total pressure is typically 2-7 MPa.
Pre-combustion capture: Integration in IGCC
Pre-combustion capture: Integration in NGCC additional components
Pre-combustion capture: Impact on efficiency 14% 12% efficiency penalty (%) 10% 8% 6% 4% 2% min max 0% IGCC dry IGCC slurry NGCC
Pre-combustion capture: process integration Le Chatelier principle: by removing one of the products (CO2 or H2), the equilibrium will shift to the product site. Membrane shift reactor: integration WGS with H2 separation. Membrane reforming: integration reforming, WGS and H2 separation. Sorption enhanced shift reactor: integration WGS and CO2 separation by adsorbents Sorption enhanced reforming: integration reforming, WGS and CO2 separation Membranes/adsorbents allow high temperature separation
Pre-combustion capture: Membrane reforming Feed stream Sweep High-pressure side Reaction Membrane H 2 H 2 H 2 H 2 Catalyst particles Residual gas CO 2, H 2 O, Permeate hydrogen Low-pressure side H 2 In order to sustain this endothermic reaction, heat is supplied by burning natural gas (or hydrogen) in a furnace
Pre-combustion capture: Membrane reforming integrated in CC (1)
Pre-combustion capture: Membrane reforming integrated in CC (2)
Pre-combustion capture: Sorption enhanced reforming CH 4 + H 2 O H 2 + CO 2 Principle CO 2CO 2CO2CO2CO2 catalyst adsorbent catalyst adsorbent H 2 + steam Integration in CC steam natural gas SERP reactor in adsorption mode air gas turbine steam generator water knock out SERP reactor in desorption mode CO 2
Advantages and disadvantages of pre-combustion Advantages CO2 separation via solvent absorption or PSA is proven. The exhaust gas comes at elevated pressures and high CO2 concentrations will significantly reduce capture costs; The compression costs are lower than post-combustion sources as the CO2 can be produced at moderate pressures; The technology offers low SOx and NOx emissions; The main product is syngas, which can be used for other commercial applications or products; A wide range of hydrocarbon fuels can be used as feedstock, such as gas, oil, coal petroleum coke, etc. Disadvantages The feed fuel must convert fuel to syngas first; Gas turbines, heaters, boilers must be modified for hydrogen firing; Major modifications to existing plants for retrofit.
Oxyfuel combustion: State-of-the-art configuration Oxy-fuel combustion is an emerging novel approach to near zero-emission and cleaner fossil fuel combustion. No commercial unit has been built, but small-scale test rigs have demonstrated the technology. The fuel is burning in pure oxygen instead of air. This creates a flue gas stream composed mainly of CO2. High purity CO2 can then be recovered by condensation. Conventional material construction must be improved or flame heat lowered to accommodate the high temperature combustion.
Advantages Very high-purity CO2 stream that is produced during combustion. After trace contaminants are removed, this CO2 stream is more easily purified and removed than post-combustion capture. With 70% recycle of the predominantly CO2 flue gas back to the combustor, NOx formation is reduced by up to 80%. This is possible because of the reduction in thermal NOx due to the absence of N2 in the flame and also part of the recycled NO is reduced to molecular nitrogen in the flame. When burning oil or coal, only two unit operations are needed for the combined removal of all other pollutants: an electrostatic precipitator (ESP) and a condensing heat exchanger (CHX)/reagent system The CHX increases the thermal efficiency of the boiler depending on the type of fossil fuel combusted, being the lowest for high rank bituminous coal and highest for natural gas.
Oxyfuel combustion: Improvements for NGCC Disadvantages oxyfuel combustion in NGCC: high energy requirements ASU developing turbines with CO 2 /H 2 O as working fluid Advanced concepts: Alternative oxygen production technologies (membranes or oxygen carriers) Allow for the use of conventional turbines using N 2 as main working fluid
Oxyfuel combustion: Advanced concepts (AZEP)
Oxyfuel combustion: Chemical looping combustion CLC is based on fuel combustion by means of two separate reactors in order to separate nitrogen from the combustion products. In the fuel reactor, fuel is oxidised by an oxygen carrier, generally a metal oxide such as iron/nickel oxide. The reduced metal oxide is then returned to the oxidation reactor, where it is oxidised. The oxidation of the metal is highly exothermic and provides high temperature exhaust air (mainly nitrogen) for power generation. Additionally, the metal oxide supplies heat to the endothermic reduction reaction.
Oxyfuel combustion: Impact on efficiency The efficiency penalty for oxfuel combustion schemes is mainly caused by the energy consumption of the air separation unit and to a lesser extent CO2 compression. Note that the efficiency penalty for oxyfuel PC is comparable to postcombustion capture. For oxyfuel NGCC the efficiency penalty is higher than for post-combustion capture, as the required quantity of oxygen is relatively higher. efficiency penalty (%) 14% 12% 10% 8% 6% 4% 2% min max 0% PC NGCC
Technology comparison: efficiency with CO2 capture net electric efficiency (% LHV) 70% 60% 50% 40% 30% 20% PC-post max min PC-oxy IGCC-pre NGCC-post NGCC-pre NGCC-oxy ATR-SEWGS MR AZEP CLC SOFC-GT
Technology comparison: CO 2 mitigation costs Target: Reduce the cost of CO2 capture from 50-60 to 20-30 per tonne of CO2 captured, whilst aiming at achieving capture rates above 90%. CO2 mitigation costs ( /t CO2) 60 50 40 30 20 10 0 state-of-the-art PC-post PC-oxy IGCC-pre advanced NGCC-post NGCC-pre NGCC-oxy PC-post adv IGCC-pre adv NGCC-post adv ATR-SEWGS MR AZEP CLC SOFC-GT
Technology comparison: electricity production costs 7 state-of-the-art advanced 6 5 4 3 2 1 0 PC-post PC-oxy IGCC-pre NGCC-post NGCC-pre NGCC-oxy PC-post adv. IGCC-pre adv. NGCC-post adv. ATR-SEWGS MR AZEP CLC SOFC-GT electricity costs ( ct/kwh) capital fuel O&M
CO2 captured versus avoided CO 2 avoidance costs = (COE cap -COE ref )/(E ref E cap ) The amount of CO2 avoided is the difference in emission between the reference plant without capture and the remaining emission of the capture plant. Reference Plant Emitted Captured The amount of CO2 captured is larger than the amount of CO2 avoided due to the additional energy requirements (and hence CO2 production) caused by capturing CO2. Capture Plant CO 2 avoided CO 2 captured 0 0.2 0.4 0.6 0.8 1 CO 2 produced (kg/kwh)
Choice of reference system electricity costs ( ct/kwh) 6.50 6.00 5.50 5.00 4.50 4.00 3.50 With CCS No CCS PC IGCC NGCC 3.00 0.00 0.20 0.40 0.60 0.80 1.00 CO2 emission (kg/kwh)
Summary: Post-combustion capture Chemical absorption is currently most feasible technology Technology is commercially available, although on a smaller scale than envisioned for power plants with CO2 capture (>500 MWe) Energy penalty and additional costs are high with current solvents. R&D focus on process integration and solvent improvement. CO2 capture between 80-90% Power cycle itself is not strongly affected (heat integration, CO2 C recycling) Retrofit possibility
Summary: Pre-combustion capture Chemical/physical absorption is currently most feasible technology Experience in chemical industry (refineries, ammonia) Energy penalty and additional costs physical absorption are lower r in comparison to chemical absorption CO 2 capture between 80-90% Need to develop turbines using hydrogen (rich) fuel No retrofit possibility Advanced concepts to decrease energy penalty/costs: sorption enhanced WGS/reforming membrane WGS/reforming
Summary: Oxyfuel combustion (1) Cryogenic air separation is currently most feasible technology Experience in steel, aluminum and glass industry Energy penalty and additional costs are comparable to post- combustion capture Allows for 100% CO2 capture NOx formation can be reduced FGD in PC plants might be omitted provided that SO2 can be transported and co-stored with CO2
Summary: Oxyfuel combustion (2) Boilers require adaptations (retrofit possible). R&D issues: combustion behaviour, heat transfer,, fouling, slagging and corrosion. Application in NGCC: new turbines need to be developed with CO2 as working fluid (no retrofit) R&D focus on development of new oxygen separation technologies. Advanced concepts to decrease energy penalty/costs: AZEP (separate combustion deploying oxygen membranes) Chemical looping combustion (separate combustion deploying oxygen carriers).
CO2 capture routes: summary Post-combustion capture: separation CO 2 -N 2 Pre-combustion capture: separation CO 2 -H 2 Oxyfuel combustion: separation O 2 -N 2 Post-comb. (flue gas) Pre-comb. (shifted syngas) Oxyfuel comb. (exhaust) p (bar) ~1 bar 10-80 ~1 bar [CO 2 ] (%) 3-15% 20-40% 75-95%
CO2 Compression and transport CO2 compression uses the mature technologies and techniques that are used by the natural gas industry worldwide. Centrifugal compressors are the preferred compressor for large volume applications. The main additional operating issues for CO2 are avoiding corrosion and hydrate formation. CO2 compression is required to make it more efficient for transport. A phase diagram is used to determine the amount of compression required for CO2 storage. It is typical to compress CO2 to above 7.38 MPa for efficient transport
Phase Diagram of CO2 Above the critical pressure of 7.38 MPa and at temperatures lower than 20oC, CO2 would have a density between 800 to 1,200 kg/m3. A higher density is favourable when transporting liquid CO2, as it is easier to move a dense liquid than a gas. Therefore it is typical to compress CO2 to above 7.38 MPa for efficient transport.
CO2 Compression When transporting CO2 via pipelines, frictional loss must be accounted for. This can be achieved by maintaining inlet pressure to the pipeline to maintain an overall pressure of 7.38 MPa or install booster stations every 100 to 150 km to make up the pressure losses. Industry preference is to operate the pipeline at greater than 10.3 MPa at the inlet to maintain CO2 at the supercritical phase during transport.
CO2 Transport Pipelines are most feasible for large-scale CO2 transport Transport conditions: highh igh-pressure (80-150 bar) to guarantee CO2 is in dense phase Alternative: Tankers (similar to LNG/LPG) Transport conditions: liquid (14 to 17 bar, -25 to -30 C) Advantage: flexibility, avoidance of large investments Disadvantage: high costs for liquefaction and need for buffer storage. This makes ships more attractive for larger distances.
Pipeline versus ship transport The turning point of transporting 6.2 Mt CO2/yr is about 700 km offshore; beyond that point ship transport becomes economically more attractive than transport by pipeline. Onshore the turning point lies lower: at 700 km.
Pipeline optimisation Small diameter: large pressure drop, increasing booster station costs (capital + electricity) Large diameter: large pipeline investments Optimum: minimise annual costs (sum of pipeline and booster station capital and O&M costs plus electricity costs for pumping). Offshore: pipelines diameters and pressures are generally higher as booster stations are expensive
USA: > 95 mol% CO2 CO2 quality specifications Water content should be reduced to very low concentrations due to t formation of carbonic acid causing corrosion Concentration of H2S, O2 must be reduced to ppm level N2 is allowed up to a few %
CO2 GEOLOGICAL STORAGE - Immobilization and trapping options: Physical Physical blocking by structural traps (anticlines, unconformities or faults) stratigraphic traps (change in type of rock layer) Hydrodynamic trapping by extremely slow migration rates of reservoir brine Residual gas trapping by capillary forces in pore spaces Negative buoyancy in case CO 2 is denser than its host rock
Folding and anticlines Εθνικό Κέντρο Έρευνας και Τεχνολογικής Ανάπτυξης / Physical blocking: structural traps Faults and unconformities Fault consists of different material
CO2 GEOLOGICAL STORAGE-Immobilization and trapping options: Chemical Adsorption onto coal: permanently reduced mobility Mineralization into carbonate mineral phases: permanently reduced mobility Solubility trapping: CO2 dissolved in formation waters forming one single phase: greatly reduced mobility
CO2 GEOLOGICAL STORAGE- CO2 trapping forms in aquifers Physical trapping Dense supercritical CO2 phase (> 31 C at 73 bars) Chemical trapping Solubility trapping: CO2(aq), HCO3-,, CaHCO3+, MgHCO3+, NaHCO30, Mineral trapping: CaCO3 (calcite), FeCO3 (siderite), NaAlCO3(OH)2 (dawsonite( dawsonite),... Increasing importance with time
CO2 GEOLOGICAL STORAGE- Contribution of physical and chemical trapping options over time Right after the injection, structural and stratigraphic blocking contribute most to the trapping of CO2. Adsorption is also contributing significantly to CO2 trapping quickly after injection, in case CO2 is injected into a coal seam. After 10 to 100 years after injection has stopped this amount is for a large part replaced by residual and solubility trapping. After a period of roughly 1000 to 10000 years mineral trapping starts to contribute significantly. In time the change in contribution of different trapping mechanisms results in an increased storage security.
VALUE-ADDED CO2 STORAGE Enhanced Oil Recovery (EOR); Enhanced Gas Recovery (EGR); and Enhanced Coalbed Methane Recovery (ECBM).
Enhanced Oil Recovery (EOR) EOR is likely the first and most economic line of carbon dioxide mitigation processes, though other methods will become more viable as technology develops. There is a global potential of 20 65 Gt C for EOR. It permits 10-12% of additional oil reserves to be tapped. However, the return on investment for EOR is highly dependent on the price of oil, the price of CO2 and individual reservoir characteristics.
Schematic of a miscible CO2 flood for EOR Εθνικό Κέντρο Έρευνας και Τεχνολογικής Ανάπτυξης / By injecting CO2 (alternated with water, WAG) into oil reservoirs, oil is mobilized through miscible or immiscible displacement, which may increase oil recovery. The average retention of the injected CO2 in several reservoirs is around 60% while 140-280 m3 of CO2 is required to produce 1barrel of oil. Enhanced Oil Recovery (EOR The US oil industry has many years of experience with CO2 compression, transport and injection into oil fields Currently about 43 million tonnes/year of CO2 is being injected; the majority (~ 75%) being CO2 from geological reservoirs and the remaining part from industrial sources. The motivation of these projects was to maximize economic recovery from oil production with minimum CO2 quantities (as CO2 is valuable resource)
Advantages of EOR are: It provides an opportunity to increase existing hydrocarbon production; It is a cost effective means of financing a CO2 storage project; Hydrocarbon reservoirs are often ideal storage sites for CO2; Supporting infrastructure often exists, decreasing the cost of the CO2 storage project.