Proceedings of the BIAPWS 2012 Symposium on Power Plant

292 PowerPlant Chemistry 2012, 14(5)

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INTRODUCTION

The 14th Power Plant Chemistry Symposium, organisedby the British and Irish Association for the Properties ofWater and Steam (BIAPWS) and supported by the RoyalSociety of Chemistry (RSC) Water Sciences Forum, washeld on 28–29 March 2012 at the Village Hotel, Chilwell,Nottingham. BIAPWS is the National Committee for theUK and Ireland of the International Association for theProperties of Water and Steam (IAPWS) and is also theindustry representative body for power plant chemistry.

The symposium consisted of two sessions: the first session on 'Power Plant Chemistry Fundamentals' wastargeted at developing chemists and also engineers withan interest in chemical operations and described the prin-ciples of cycle chemistry and boiler chemical cleaning.The second session consisted of more detailed technicalpresentations on 'Environmental and Water TreatmentIssues' and 'Power Plant Chemistry and Corrosion'.

This annual event continues to be very popular, with overeighty delegates attending the first session and over onehundred delegates attending the second session. Thisdemonstrated not only the continued interest in the UK indevelopments in cycle chemistry and water treatment, butalso the interest in more fundamental aspects. The pro-ceedings of the symposium are summarised in this report(Figure 1).

BIAPWS AWARD

The annual BIAPWS award helps to support a universitystudent during a placement with one of the sponsoringcompanies as a means of promoting awareness of thetopics of interest to BIAPWS and their industrial applica-tion and to provide a valuable opportunity for a student toexperience the industry. A number of past award winners

have since gone on to full time employment in power gen-eration, demonstrating significant success for the award inattracting high calibre individuals to the industry.

In 2011, the award recipient was David Docherty fromImperial College, who spent ten weeks with EDF EnergyNuclear Generation in Gloucester working on techniquesto access look-up tables for steam/water properties whenrunning computer simulations of transients in advancedgas-cooled reactors (AGRs) (Figure 2). The results of thestudy were presented at the symposium.

SYMPOSIUM PROCEEDINGS

Power Plant Chemistry Fundamentals

Power Plant Cycle Chemistry Geoff Bignold, Consultant, and Mark Robson, RWE npower

The presentation started with a clear and detailed exami-nation of Pourbaix diagrams, how they are constructedand their detailed application to corrosion in the water cir-cuit. This was followed by a review of the various ironoxides and how their stability and solubility control manyof the corrosion and deposition processes in the boiler.The application of these fundamental processes led into adiscussion of the control of feed and boiler pH and thatcontrolling these to an alkaline pH minimises the corrosionof iron alloys.

Various chemistry regimes for both feedwater and boilerwater were reviewed and included the use of eitherammonia or amines to control the pH in the feed water.For boiler water, the use of sodium hydroxide (causticsoda) or tri-sodium phosphate was detailed and the prosand cons for each treatment were outlined.

Proceedings of the BIAPWS 2012 Symposium on Power Plant Chemistry

Proceedings of the BIAPWS 2012 Symposium on PowerPlant Chemistry

© 2012 by Waesseri GmbH. All rights reserved.

ABSTRACT

The British and Irish Association for the Properties of Water and Steam held its annual Symposium on Power PlantChemistry on 28–29 March 2012 in Chilwell, Nottingham. Summaries of the event proceedings are provided.

Paul McCann and Mark Robson

293PowerPlant Chemistry 2012, 14(5)

PPChemProceedings of the BIAPWS 2012 Symposium on Power Plant Chemistry

Figure 1:

Symposium proceedings.

Figure 2:

The BIAPWS Award presentation, showing from left to right, Paul McCann, BIAPWS chair, Andrew Bull, EDF Energy, David Docherty,the BIAPWS Award recipient, Richard Harries, BIAPWS, and Andy Rudge, EDF Energy.

Finally, the importance of steam purity was discussed withthe recognition that due to the very low solubility of themajority of solutes in steam, in most cases well below thesteam quality limits, the principle controlling factor fordeposition in the steam turbine is kinetically driven andnot thermodynamics.

Boiler Chemical CleaningBill Lawson, Alstom Thermal Services, Ray Clarke andGeoff Darlow, ESB International, and Andrew Mosley andRichard Geatrell, RWE npower

The reasons and justifications for chemically cleaning anewly constructed boiler in preference to carrying out onlyan alkaline flush and steam blow were detailed. The differ-ences between a pre-operational and operational chemi-cal clean were discussed and the rationale for deciding tochemical clean was highlighted.

For pre-operational chemical cleans, the impact on thelength of steam blows is important, though some manu-facturers do not offer the chemical clean as a standard. Itis believed by most UK utilities that pre-operationalchemical cleans are beneficial in reducing the length of thesteam blows and forming a good protective oxide layer foroperation.

The importance of achieving an iron and free acid plateauduring the chemical clean was outlined and, if this is notachieved, the cause needs to be understood before pro-gressing to the next stage of the clean.

With the larger modern design of heat recovery steamgenerators (HRSGs), it was noted that it is important tosplit the circuit up into a number of sections to achieve asatisfactory clean. This needs to be supported by adetailed method statement where valve operations andcleaning steps are specified.

The importance of complying with safety and environmen-tal requirements was highlighted by all speakers, and thelimitations this puts on hydrofluoric acid strength andquantity to comply with COMAH regulation (Control ofMajor Accident Hazards) requirements were discussed.

Power Plant Chemistry and Corrosion

A Chemistry Survey of the Steam/Water Circuit of aModern CCGT Power StationShauna Concannon, ESB International, and John Greene,Consultant

To fully understand the cycle chemistry performance andbehaviour at a modern 400 MW combined cycle gas turbine

plant (CCGT) owned and operated by ESB International, acomprehensive chemistry survey was carried out. The sta-tion has a triple pressure, vertically tubed, drum type HRSG,with normal circuit operating pressures of high pressure(HP) 116 bar, intermediate pressure (IP) 24 bar and lowpressure (LP) 4 bar. As the LP circuit includes a combinedLP drum/deaerator, an all-volatile feedwater treatment withammonia is used. The HP and IP boiler waters are dosedwith tri-sodium phosphate. No oxygen scavenger is dosed.The purpose of the survey was to validate steam purity,establish boiler drum carryover rates and to identify any evi-dence of phosphate hideout.

For the assessment, on-line ion chromatography was usedto measure the concentrations of sodium, phosphate,chloride and sulphate in steam and boiler water during loadchanges. Different chromatography systems were set up toenable the measurement of concentrations in the µg · L–1

range in steam and mg · L–1 range in boiler water.

The survey showed that excellent steam purity is beingmaintained at all times (Table 1). In the IP and LP steams,the concentrations of salts were almost all less than0.1 µg · L–1 (though noting that the LP boiler water is notdosed with phosphate). In the HP steam, concentrationswere slightly higher, but still only a maximum of0.5 µg · kg–1. This also confirmed the exceptional steamafter cation conductivities of < 0.1 µS · cm–1 that are typi-cally measured at the plant. From measurements ofsodium and phosphate in the HP and IP boiler waters andsaturated steams, carryover rates were calculated of0.012 % for the HP drum and 0.008 % for the IP drum,which are also extremely low.

In investigating phosphate hideout, sodium to phosphatemolar ratios were determined of 3.8 for the HP boiler waterand 3.0 for the IP boiler water. As the molar ratio of sodiumto phosphate should be 3.0 with tri-sodium phosphate,this showed the presence of free sodium hydroxide in theHP boiler water.


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Steam SampleMean Concentration [µg · kg–1]

Na Cl SO4 PO4

HP Saturated Steam 0.346 0.514 0.458 0.080

IP Saturated Steam 0.060 0.007 0.064 0.201

IP Superheated Steam 0.054 0.019 0.074 0.019

LP Saturated Steam 0.007 0.010 0.042 n.d.

LP Superheated Steam 0.074 0.006 0.049 n.d.

Table 1:

Steam purity results.

n.d. not detected


In the LP steams, a slight increase in after cation conduc-tivity was noted from 0.13 µS · cm–1 in the saturated steamto 0.21 µS · cm–1 in the superheated steam. Ion chro-matography measurements showed that this differencewas due to an increase in carbonate concentrations (i.e.carbon dioxide), suggesting some degradation of organicspecies across the LP superheater.

Breakdown of Organic Amines in AGR Steam/WaterCircuitsAndrew Bull, EDF Energy

Hartlepool is one of EDF Energy's fleet of advanced gas-cooled reactor (AGR) nuclear power stations in the UK. AtHartlepool, the helical 'pod' boilers are of once-throughhigh pressure design with typical final steam conditions of170 bar and 500–540 °C. The boilers must provide a highlevel of reliability against tube leaks for nuclear safety rea-sons, whilst also lasting the lifetime of the station as theirdesign means that there is limited ability for inspection,repair and replacement. Because of circuit design andmetallurgy, the cycle chemistry is based on ammonia all-volatile treatment with combined oxygen and hydrazinedosing. However, magnetite deposition in the once-through evaporator stages has resulted in rising pressuredrops across the boilers. This has caused problems withboiler instability, reduced generation due to feedwaterpressure limits and reduced steam temperatures, as wellas increased stress corrosion risks resulting from wettingof austenitic superheater sections.

To counteract the increases in boiler pressure drop, theuse of an organic amine as a better high-temperature basethan ammonia was investigated to reduce magnetite solu-bility. Other potential chemistry options that were not suit-able included the use of a fully oxygenated chemistry dueto the partial wetting of austenitic stainless steel super-heaters and raising the pH with ammonia due to the effecton the condensate polishing plant.

Following an evaluation of potential amine products,dimethylamine (DMA) was selected for further trials due toits basicity and limited predicted thermal degradation.After initial test work with DMA at the Wythenshawe BoilerRig in Manchester proved successful, full scale plant trialswere carried out in Reactor 2 at Hartlepool from January2011 onwards. An initial DMA concentration of 450 µg · L–1

was dosed, which was increased progressively to thedesired target of 900 µg · L–1.

Monitoring during the trial period showed that the averagerate of increase in boiler pressure drop was up to 2.6 timeslower with DMA dosing than with ammonia. Much of thisimprovement coincided with a DMA dosed concentrationof half or two-thirds of the target concentration. Iron levelsin the feedwater system also reduced from around

4 µg · L–1 to less than 1 µg · L–1, indicating that two-phaseflow-accelerated corrosion had been reduced in the bal-ance of plant. There has been no evidence to date thatDMA dosing affects the operation or performance of thecondensate polishing plant.

During the trial, the percentage of DMA decomposingdecreased with time, possibly as a result of the surfacesbecoming conditioned. Analysis showed that the degra-dation products of DMA were methylamine, ammonia,formic acid, carbon dioxide and neutral organic products(probably methanol and formaldehyde). At the boiler out-let, formic acid levels of 40 µg · L–1 were measured insteam, which were significantly higher than expected,though these also decreased with each operationalperiod. Due to the potential for formic acid to concentratein the early steam turbine condensate, additional assess-ment work was completed to demonstrate that the DMApresent maintains a sufficiently alkaline environment tominimise the risk of stress corrosion cracking in the LPturbine steels.

Corrosion Protection in Modern Power PlantsBrian Coles, Lake Technical Specialities

In the power industry, vapour phase corrosion inhibitors(VpCIs) may be considered as an option to currentlyestablished methods for plant and component preserva-tion. To date, most power industry applications have beenfor long-term gas side boiler preservation. VpCIs havebeen used with some success in preventing corrosionduring shutdown periods at plants that have previouslyhad problems with environmental emissions when corro-sion debris has been released from the stack during sub-sequent start ups.

VpCIs can be supplied in many types of carrier, includingwater and oil. If chosen correctly, VpCIs can protectvapour phases, liquid phases and liquid-vapour inter-faces. When fogged into the boiler, they adsorb to metalsurfaces to form a mono-molecular layer that acts as abarrier to oxygen and water. VpCIs can migrate up to threemetres from the point of application to protect recessedareas and cavities. For long-term preservation, re-applica-tion is normally required within 2–3 years to minimise cor-rosion for the full period required. Badly fouled surfacesrequire initial cleaning before the VpCI is applied. Whenthe boiler is re-started, VpCIs decompose at high tem-perature to oxides of carbon and nitrogen.

In the UK, VpCIs have been used successfully at CCGTplants owned by Centrica to prevent gas side corrosionduring plant shutdowns. Examples include:

• Peterborough Power StationThe station has had issues with rust particles being


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emitted from the HRSGs when they have been returnedto service after long and short outages. To try to pre-vent further occurrences, an HRSG was treated withVpCIs after initial shutdown. At the end of the outage,visual inspections confirmed that the tubes, fins andother surfaces were free from corrosion, which was asignificant improvement in condition compared to pre-vious outages. The unit was then returned to servicewith no environmental problems reported. VpCIs arenow applied at the station at every planned unit outage.

• South Humber Bank Power StationThe station has had problems with dew point deposi-tion at the back end of the HRSG which has resulted inboiler tube failures. Following experience at Peter -borough, the HRSGs have been fogged with VpCIs during outages. Since VpCI application started, thenumber of similar tube failures has decreased.

• Kings Lynn Power StationVpCIs have been used to preserve the HRSG during anextended shutdown and will be used for future plantpreservation.

Water side preservation may also be performed in eitherwet or dry conditions using different VpCI chemicals,though there has been much less practical experiencewith this in power plant. The potential impact of residualconcentrations requires consideration.

Rapid Return of High-Accuracy Steam Properties forAGR Thermal-Hydraulic AnalysisBIAPWS Award Lecture, David Docherty, Imperial College

David Docherty was the recipient of the 2011 BIAPWSStudent Award. As described, his work placement waswith EDF Energy Nuclear Generation investigating tech-niques to access look-up tables for steam/water propertieswhen running computer simulations of AGR transients.

The design of AGRs is such that, in most instances,access for maintenance or addition of internal monitoringinstrumentation is not possible. Therefore, computer simulations of plant performance are an extremely impor-tant part of the safety case. This project supported workactivities that aimed to produce fast access to the lateststeam/water properties routines to improve the speed andaccuracy of transient analysis.

The AGR plant modelling codes currently used by EDFEnergy can optionally obtain steam properties by directaccess to a previous release of the steam properties formulation, IAPWS 84. However, as this already results inrelatively long simulation times, the use of the more accu-rate, but potentially much slower, IAPWS 95 release wasnot deemed practical. Therefore, an alternative approachwas investigated to access IAPWS 95 in the form of look-

up tables. This approach is based on an in-house softwarepackage initially developed some 20 years ago to gener-ate look-up tables from previous steam properties poly -nomials. At that time, table interrogation was based ontwo-dimensional bi-linear interpolation with routines written in FORTRAN for general interpolation and also forerror checking.

To generate new IAPWS 95 look-up tables, both manualand automatic approaches were investigated to developtables of all the properties to a specified accuracy. Initially,the table mesh size was determined to provide a maxi-mum error of 1 %. Manual tables were developed by run-ning the IAPWS 95 routines, exporting the results, testingthe accuracy at each intermediate point and reducing themesh size in areas where the accuracy was not consid-ered adequate. Automatic tables were generated by creat-ing tables of a specified mesh size, using an error check-ing routine to evaluate their accuracy and then halving themesh size of the entire table if required.

Using these approaches, tables were successfully pro-duced for all properties of water (not steam) with thedesired functionality and accuracy. Manual tables wereproduced of variable mesh size, whilst the automatic tableroutine produced tables of regular mesh size. Table inter-polation proved to be around eight times faster than running the IAPWS 95 code whilst remaining within therequired error tolerance.

Environmental and Water Treatment Issues

Severn Power Condensate Polishing PlantJoe Woolley, Watercare International

Severn Power Station is a new 842 MW CCGT plant con-sisting of two single shaft combined cycle units. TheHRSGs are of triple pressure design with a once-throughHP circuit and drum type IP and LP circuits. The stationalso has air-cooled condensers.

To maintain the feedwater purity required for the once-through HP stages, a condensate polishing plant wasspecified to treat the full condensate flow of up to440 m3 · h–1 in each generating unit. The treated conden-sate purity required was: conductivity ≤ 0.1 µS · cm–1, totaliron ≤ 5 µg · L–1, sodium ≤ 2 µg · L–1 and silica ≤ 5 µg · L–1.As the feedwater would be conditioned with ammonia toachieve a pH of 9.6, the polishing plant was also requiredto operate in ammonia form to reduce the frequency ofregenerations. During the transition from hydrogen toammonia form operation, the sodium target was relaxedto ≤ 10 µg · L–1. In addition, the IP and LP drum blowdownwas to be recovered to the polishing plant for treatment tooptimise site water use.



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To meet these requirements, the condensate polishingplant supplied consisted of two units, each with a capac-ity of 440 m3 · h–1 and each consisting of two streams ofcartridge filters and mixed beds. In ammonia form, themixed beds were designed to achieve runs of up to 30days (156 000 m3) between regenerations. To minimisesodium slippage during conversion to ammonia formoperation, the mixed bed resins are regenerated externallyto separate the cation and anion resins as effectively aspossible. The regeneration system is common and con-sists of an initial resin separation vessel in which the resininterface is retained, separate cation and anion regenera-tion vessels and a final mixing tank. The resins are trans-ferred hydraulically between vessels and chemical regen-erants are transferred by pumps. Depth cartridge filterswere provided for commissioning and replaced withpleated cartridge filters for normal operation. Due to sitedischarge restrictions, the ammoniated wastewater frac-tion from mixed bed regeneration is segregated andtankered off-site for disposal.

At present, the polishing plant is performing within expec-tations and meeting design guarantees with blowdownrecovery. Mixed bed throughputs are around 150 000 m3

between regenerations. Treated condensate after cationconductivity is ≤ 0.07 µS · cm–1 during both hydrogen andammonia form operation. During the transition to ammo-nia form operation, some initial problems with resin sepa-ration contributed to sodium peaks of up to 10 µg · L–1 inthe treated condensate. These issues were resolvedquickly and sodium concentrations in the treated con -densate now peak at around 2–4 µg · L–1, falling to0.8–1.5 µg · L–1 during normal operation in ammonia cycle.By comparison, sodium concentrations in hydrogen formoperation are < 0.1 µg · L–1. The percentage Na on cationresin was found to be 0.03–0.05 % by the end of the commissioning period, compared to up to 0.6 % whenthere were problems with resin separation.

During commissioning, particles in the unfiltered conden-sate were found to be mainly within a size range of2–5 µm, with particle counts of 500–2 500 per mL of sample. After the pleated cartridge filters were installed,particle counts were reduced to only 65–234 per mL, indicating effective removal. Although still early in theoperation of the system, later data showed that particlecounts in the unfiltered condensate had reduced to lessthan 100–300 per mL.

Troubleshooting Polishing Mixed Bed SystemsBrian Windsor and David Hayhurst, Purolite

This paper looked back at the historical problems that arestill being frequently encountered on polishing mixedbeds, these being typically apparent as very long rinse

times to quality after regeneration, or consistently poortreated water quality (high conductivity).

At all times, the treated water quality from a power plantpolishing mixed bed should have a conductivity between0.06–0.10 µS · cm–1, sodium < 10 µg · L–1 and reactive silica < 20 µg · L–1. To achieve this, mixed beds shouldnever be run to exhaustion and the service cycle shouldbe stopped on time or throughput well before any increasein conductivity or reactive silica. This premature regenera-tion adds little to plant operating costs.

If an issue is identified, a double regeneration is normallyrecommended, during which operators should check thatresin levels and chemical regenerant quantities are correctand that valve sequences and air blowers are working cor-rectly. If this does not solve the issue and treated waterquality continues to be poor, this usually indicates one or acombination of the following problems during regenera-tion (note that the points relate to in-situ regeneratedmixed beds, though most also apply to externally regener-ated beds):

• Poor resin separationThe density differences between modern cation andanion resins mean that resin separation should be eas-ily achieved. However, the resin interface must belocated in the correct position to prevent acid contami-nating anion resin or sodium hydroxide contaminatingcation resin. If the interface is too low, the most likelycause of this is loss of cation resin. If the interface is toohigh, anion resin may be trapped in the cation layer,usually caused by the backwash flow rate being toolow. If the backwash flow rate is too high, anion resincan block the top strainer/collector and the flow ratewill fall. If the resin bed level is low, but the cation inter-face is in the correct position, anion resin has been lost,either because the backwash rate may be too high orresin has been lost due to damaged internals.

• Inadequate slow (displacement) rinsingAt the end of a slow rinse stage, the conductivity ofwater exiting the centre drain should be low, typicallysignificantly less than 100 µS · cm–1, showing that theregenerants have been washed from the bed. However,over time, collection/distribution systems can becomeblocked and flow rates and pressures will change,which without adjusting plant settings means thatregenerants can be left in the system. This can be con-firmed by checking the conductivity of samples at theend of the rinse stage. Any problems can often easilybe addressed by extending the rinse time.

• Poor drain down control before re-mixingWith modern resins, the re-mixing stage must work perfectly to achieve a correctly mixed resin charge. Toachieve this, the water level should be only a few centimetres above the top of the bed when starting the



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air mix. If the water level is below the top of the bed, theair will not re-mix the resins. If the water level is toohigh, the resins can start to separate again at the end ofthe air mix stage, forming a cation layer at the bottom ofthe vessel, from which small amounts of acid can bereleased. Ideally, the mixed bed vessel should be provided with a separate drain down valve from theshell to enable the water level to be controlled exactly,though this is often omitted in modern mixed beddesigns.

• Air blowersPoor bed mixing can be caused by problems with airblowers, such as blower failures, loss of flow due to lift-ing relief valves or pipework leaks, or contamination ofthe supply. There is also an increasing trend to use airfrom station compressors rather than dedicated blow-ers, which can cause problems if the infrequentdemand for mixed bed resin mixing coincides withother site demands.

Cooling Water Conditioning – The Use of Scale Inhibi -tors across the French Fleet of Nuclear Power PlantsPhilippa Lambert, EDF Energy

In France, EDF's operational nuclear power plant fleetconsists of 58 reactor units. Depending on location, plantcooling is provided by either direct cooled (once-through)systems using seawater or estuarine water (18 units),direct cooled systems using river water (10 units), or recir-culating tower cooled systems using river water (30 units).

In power station cooling systems, scale formation in con-densers and cooling towers needs to be prevented to con-trol health risks linked to the development of biofouling,maintain unit efficiency, prevent load drops due to insuffi-cient cooling and to reduce operating costs associatedwith replacing fouled or corroded equipment, e.g., fouledtower pack.

At the stations with tower cooled systems, the risk of scal-ing in the cooling circuits is site specific according to thelocal river water quality and hydrogeology. The scaling riskcan also vary seasonally due to variations in water quality,flows and temperatures. Most of the tower cooled systems were designed to operate with high feed rates ata concentration factor of only 1.5, with no initial coolingwater treatment. However, there have been a number ofimportant scaling events observed over time due tochanges in water quality, with concentrations of hardnesssalts increasing. Therefore, company guidance for scalingcontrol has been improved and arrangements for scalingcontrol reviewed at each station.

To estimate the potential for scaling under different condi-tions, operating guidance has been developed for stations

that is based on the use of the Ryznar Stability Index. Theguidance defines acceptable operating areas, areas withincreased scaling risk and areas when the scaling risk issufficiently high that operational constraints may need tobe applied at the plant. To provide inputs for the index cal-culation, stations routinely monitor make-up water andcooling water pH, calcium concentration, alkalinity, con-ductivity, temperature and cooling circuit concentrationfactor. So that the calculation methodology and guidancecan be refined, the results are collected on a fleet-widedatabase and compared to plant observations of scaling(e.g., tower pack weights). To provide early warning ofpotential scaling events, hydrogeological models are alsobeing developed with the aim of being able to predict thewater quality at a given site five days in advance.

Where cooling water chemical treatment is necessary forscaling control, conditioning with sulphuric acid is usedmost widely due to proven effectiveness, low cost andlimited environmental impact. At one site, hydrochloricacid is used, whilst a number of sites use carbon dioxide,which is effective in protecting the condenser, but not thecooling tower, where it is stripped into the air flow. In thefuture, most sites requiring chemical treatment will usesulphuric acid instead of hydrochloric acid or carbon diox-ide. Polymeric dispersants are currently used at only onesite, although there are plans to extend this to a secondsite.

Mechanical curative measures being applied includetower pack cleaning and replacement programmes and,for condenser tubes, the use of mechanical Taprogge ballcleaning systems. Ultrahigh pressure jet cleaning methodsare also being developed for condenser tubes.

Carbon Capture and Storage OverviewTony Corless, Scottish Power

To maintain clean fossil fuels as part of a balanced andsustainable energy portfolio, Scottish Power, part of theIberdrola Group, has completed extensive design and testwork on carbon capture and storage (CCS) technology.

Recently, a consortium comprising Scottish Power,National Grid and Shell completed a detailed Front EndEngineering and Design (FEED) study of a commercialscale CCS project at the existing 2 300 MW Longannetcoal-fired power station located in Fife, Scotland. Thiswas completed under the UK Government's competitionto build and operate a full-scale CCS system on powergeneration, though a satisfactory subsequent deal to pro-ceed with construction could not be met.

The project was based on capturing two million tonnes ofcarbon dioxide a year from a 300 MW unit using post-combustion amine technology. The carbon dioxide would



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then be transported to the NorthSea by changing an already largelyexisting gas pipeline before finalstorage in a depleted gas reservoirtwo kilometres below the sea bed(Figure 3).

The key components of the cap-ture plant included a direct contactcooler to cool and polish the fluegas, a carbon dioxide absorbertower, a desorber and reboiler toseparate carbon dioxide from theamine solution by heating, and areclaimer to separate impuritiesfrom the amine solution. Followingthe capture process, the carbondioxide would be pressurised,deoxygenated and dried to meetthe pipeline specification.

To improve understanding of thecarbon capture process chemistryand operating costs, Scottish Power also completed aseven month trial of a 1 MW carbon capture unit atLongannet in 2009. Most of the baseline testing usedmonoethanolamine for carbon capture, though proprietaryamines were also tested. The choice of amine and aminechemistry was critical for the process. As well as beingable to effectively capture carbon dioxide, important prop-erties for future amine products must address safety, envi-ronmental acceptability, stability and energy efficiency,where the amine regeneration must require as little energyas possible.

Experience has shown that the process chemistry andtechnology involved in CCS would work, though commer-cial incentives are less certain. Ultimately, an integratedcapture, storage and transport network for Europe is afuture possibility given the storage potential in the NorthSea.

THE AUTHORS

Paul McCann (M.S., Chemistry, University of Nottingham,UK) is a specialist in power plant steam/water cycle chem-istry, corrosion and water treatment at E.ON's New Build &Technology global unit in the UK. He has over 12 years'experience in the power industry, joining Powergen, sub-sequently E.ON, in 1999. Paul McCann is also the currentchair of the British and Irish Association for the Propertiesof Water and Steam.

Mark Robson (Ph.D., University of Leeds, United King -dom) joined the Central Electricity Generating Board(CEGB) in the North East regional laboratories in 1980 and

worked on a range of topics within the chemistry groupinvestigating plant problems for 10 years. On leaving theCEGB he carried out various chemistry-based R&D func-tions. In 2001, Mark Robson rejoined the power industry,working with various companies until joining RWE npowerin 2008. Since rejoining the power industry he has beenresponsible for plant chemistry and environmental issues,working as a station chemist and more recently as achemistry and environment engineer in the corporateengineering function of RWE npower.

CONTACTS

Paul McCannE.ON New Build & TechnologyTechnology CentreRatcliffe on SoarNottingham NG11 0EEEngland

E-mail: [email protected]

Mark RobsonRWE npowerDrax Business ParkPO Box 3SelbyNorth Yorkshire YO8 8PQEngland

E-mail: [email protected]

Figure 3:

Schematic of proposed carbon capture and storage plant at Longannet (courtesy ofScottish Power).

DCC direct contact coolerSPS steam and power supply


Documents

Proceedings of the BIAPWS 2012 Symposium on Power Plant