Carbon Capture Readiness Report for Keadby 2 CCGT · Carbon Capture Readiness Report for Keadby 2 CCGT Technical Report No: TR-GEN-AM-KEAD2-003 ... Following the retrofit of CCS the

Carbon Capture Readiness Report for

Keadby 2 CCGT

Technical Report No: TR-GEN-AM-KEAD2-003

Prepared and Issued by: James Bowers, Technology Engineer Ronnie Glen, Process Engineer John Ross, Thermal Development

Checked by: Paul Kieran, Process Engineering Manager

Approved by: Andrew Underwood, Project Design Lead

Date Issued: 26/10/2015

Rev: 1.0 Information Classification: Confidential

TR-GEN-AM-KEAD2-003

engineering centre page 2 of 38

Document Distribution

Copy Distribution 1 Jim Lawrie, Project Development Manager 2 Alasdair MacSween, Head of Gas Developments 3 Steven Brooker, Project Design Development Manager 4 John Ross, Thermal Development 5 Ronnie Glen, Process Engineer 6 Paul Kieran, Process Engineering Manager 7 Andrew Underwood, Project Design Lead 8 Mark Birley, Head of Project Engineering 9 John Downes, Director of Engineering 10 Engineering Centre Document Library

Document Change History

Revision Date Author Section Change Description 0.1 15/10/2015 James Bowers ALL First Issue 1.0 26/10/2015 James Bowers 5.3 Edited section regarding

COMAH regulations

Key Words: CCGT, CCS

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Summary

This paper has been prepared in relation to Keadby Generation Ltd.’s application under Section 36C of the Electricity Act 1989 to vary an existing consent to construct and operate Combined Cycle Gas Turbine (CCGT) power plant (Keadby 2) with a gross generated capacity of up to 810MW at Keadby in North Lincolnshire. This report has been prepared on behalf of Keadby Generation Ltd as a CCR assessment in order to demonstrate that the CCR conditions1 are met in relation to the combustion plant at Keadby 2 based on current assumptions as to technology and future legislative requirements.

An assessment of CO2 pipeline routing from Keadby 2 to potential CO2 sinks has shown that a pipeline would be feasible. Potential CO2 sinks have also been identified for a future project.

Adequate space and utilities are available on the Keadby 2 site to accommodate a future CO2 capture plant.

The CCGT design will incorporate extraction design features to enable steam and flue gas to be directed to a CO2 capture plant should CCS be retrofitted in future.

Following the retrofit of CCS the impacts on the gas turbine and heat recovery steam generator would be minimised by installing a booster fan downstream of the CCGT plant to overcome the pressure losses associated with the CO2 capture plant. This would be done in such a way to ensure the HRSG ductwork could not be over pressurised in the event of fan trip.

Based upon of the conclusions of this study there are no known technical or economic barriers to retrofitting CCS to Keadby 2 in future, with the appropriate market and regulatory conditions.

Keadby Generation Ltd will review and report on the effective maintenance of the plants CCR status within three months of the station starting the supply of electricity to the grid and periodically every two years thereafter.

1 As defined in regulation 2(2) of the Carbon Capture Readiness (Electricity Generating Stations) Regulations

2013

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Contents

Abbreviations ............................................................................................................................. 6

1. Introduction ....................................................................................................................... 7

2. Transportation ................................................................................................................... 8

3. Suitable CO2 Storage Sites ................................................................................................. 9

4. Technical Feasibility of Retrofitting ................................................................................. 10

4.1. Oxyfuel ..................................................................................................................... 10

4.2. Pre-Combustion CO2 Capture .................................................................................. 10

4.3. Post-Combustion CO2 capture ................................................................................. 10

5. CCGT Design Considerations ............................................................................................ 12

5.1. Power Plant Location ............................................................................................... 12

5.2. Space Requirements ................................................................................................ 12

5.2.1. CO2 Capture Plant .............................................................................................. 12

5.2.2. Gas Turbine ........................................................................................................ 12

5.2.3. Boiler and Auxiliaries ......................................................................................... 13

5.2.4. Steam Turbine and Auxiliaries ........................................................................... 13

5.2.5. Water - Steam - Condensate Cycle .................................................................... 14

5.2.6. Cooling Water System ........................................................................................ 14

5.2.7. Raw Water Pre-treatment Plant ........................................................................ 14

5.2.8. Waste Water Treatment Plant ........................................................................... 14

5.2.9. Compressed Air System ..................................................................................... 15

5.2.10. Electrical ......................................................................................................... 15

5.2.11. Plant Pipe Racks and Ducting ......................................................................... 15

5.2.12. Control and Instrumentation ......................................................................... 15

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5.2.13. Additional vehicle movement ........................................................................ 15

5.2.14. Storage and handling of solvent and CO2 ...................................................... 16

5.3. Safety ....................................................................................................................... 16

5.3.1. CO2 Pipeline ....................................................................................................... 16

5.3.2. CO2 Capture Plant .............................................................................................. 16

5.4. Fire Fighting and Fire Protection System ................................................................. 17

6. Suitability of Associated Infrastructure ........................................................................... 18

7. CCS Retrofit Economic Assessment ................................................................................. 19

7.1. Introduction ............................................................................................................. 19

7.2. Assumptions and Parameters .................................................................................. 19

7.3. The modelling approach .......................................................................................... 20

7.3.1. Risk ..................................................................................................................... 20

7.3.2. Capital Costs ....................................................................................................... 20

7.3.3. Operating Costs .................................................................................................. 21

7.4. Valuation Method .................................................................................................... 22

7.5. Results ...................................................................................................................... 23

7.6. Economic Assessment Conclusions ......................................................................... 23

8. Conclusions ...................................................................................................................... 25

9. References ....................................................................................................................... 26

Appendix I – CO2 Pipeline Corridor

Appendix II – CO2 Capture Plant Location

Appendix III - CO2 Capture Plant Process Description

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Abbreviations

CCGT - Combined Cycle Gas Turbine CCR - CO2 Capture Readiness CCS - CO2 Capture and Storage COMAH - Control of Major Accident Hazards Regulations 1999 DCC - Direct Contact Cooler DECC - Department of Energy & Climate Change EPC - Engineer Procure and Construct FEED - Front End Engineering Design GT - Gas Turbine HRSG - Heat Recovery Steam Generator HSE - Health and Safety Executive IEA - International Energy Agency IP - Intermediate Pressure LP - Low Pressure MEA - Monoethanolamine PSR - Pipelines Safety Regulations 1996 SCR - Selective Catalytic Reduction ST - Steam Turbine TSN - Transport and Storage Network

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1. Introduction

This paper has been prepared in relation to Keadby Generation Ltd.’s application under Section 36C of the Electricity Act 1989 to vary an existing consent to construct and operate Combined Cycle Gas Turbine (CCGT) power plant (Keadby 2) with a gross generated capacity of up to 810MW at Keadby in North Lincolnshire. This report has been prepared as a CCR assessment of the modified plant, and has been prepared on behalf of Keadby Generation Ltd as a study to demonstrate the readiness of the plant for the installation of CO2 Capture and Storage (CCS) capability at Keadby 2 based on current assumptions as to technology and future legislative requirements.

Keadby Generation Ltd has undertaken project specific studies to provide the required evidence for CO2 Capture Readiness (CCR) feasibility as set out in the Department of Energy & Climate Change (DECC) CCR Guidance Note (Ref1). A pre-conceptual process description has been developed to provide estimates of required utilities and infrastructure. This design will require re-validation in a Front End Engineering activity as part of the preparations for any future investment decision. Such detailed design would also take into account the relevant developments in technology and appropriate environmental and Health and Safety Executive (HSE) guidelines at the time.

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2. Transportation

After the CO2 is captured, it would most likely be transported to a storage site by pipeline. For the purpose of this study two provisional pipeline corridors are suggested. The pipeline corridors and key features along them are detailed in Figure 1 in Appendix I. These corridors run along mainly agricultural land with low levels of residential and industrial occupancy. The suggested routes would be a sufficient distance away from residential areas, Special Areas of Conservation and Sites of Special Scientific Interest within a 10km radius of the Keadby site (Ref2). Both of the corridors cross major and minor roads and rivers.

A detailed risk assessment would be carried out in advance to assess the safety of CO2 pipeline routes. A cost benefit analysis alongside an environmental impact assessment conducted during the design stages of the CCS project would determine the optimum pipeline routing and cost implications for the project. This level is of detail is not considered appropriate at this stage of planning but such an assessment would follow current guidance from the HSE (Ref3). However, no barriers or environmentally protected areas along these routes have been identified that would prevent the development of a CO2 pipeline in future.

The pipeline options are assumed to connect to the proposed the National Grid Yorkshire and Humber CCS Cross Country Pipeline project (Ref4), as shown in Figure 2 in Appendix I. The National Grid pipeline would have the capacity to transport 17 million tonnes of CO2 per year. There should therefore be sufficient capacity within the pipeline to accommodate captured CO2 emissions from Keadby 2 and it is assumed that their operators will permit access on agreeable terms. .

In the event that the National Grid pipeline is not be developed in future, a similar route to that proposed is likely to be the most feasible option for the Keadby 2.

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3. Suitable CO2 Storage Sites

A CO2 capture plant, operating at 90% capture, retrofitted to the Keadby 2 CCGT would capture approximately 6 thousand tonnes of CO2 per day with the plant continuously operating at maximum output. This equates to an upper limit of 33 million tonnes over a 15 year lifetime. The National Grid pipeline proposes to transport CO2 to Barmston, south of Bridlington. An offshore pipeline will then transport the CO2 a further 60 miles to saline aquifer 5/42 within a Bunter Sandstone formation in the Southern North Sea, which has a storage capacity estimated as 837 million tonnes of CO2 (40% pore density) (Ref5). Should the National Grid project not go ahead an alternative saline aquifer, 2/48 could be used for CO2 storage, which has an estimated storage capacity of 3169 million tonnes of CO2 (Ref5). The CO2 pipeline routes to both CO2 sink options are shown in Figure 3 in Appendix I.

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4. Technical Feasibility of Retrofitting

Three common approaches have been proposed for abating CO2 emissions from CCGT plant, as described below.

4.1. Oxyfuel

Fuel is fully combusted in high purity oxygen, previously separated from air. A stream with a relatively high concentration of CO2 is produced. This can be stored with minimal further purification. This technology is not suitable for retrofits to CCGTs as the working fluid thermodynamic properties and the turbine’s temperature profile are very different, so a bespoke turbine would be required.

4.2. Pre-Combustion CO2 Capture

Hydrogen replaces natural gas as the fuel for the gas turbine (diluted with nitrogen or steam to control flame temperatures). The hydrogen can be produced from reforming natural gas to produce synthesis gas (H2, CO, CO2). This is then fed to a shift reactor, which converts the CO into H2 over a catalytic bed in the presence of steam. The CO2 is removed by physical solvent absorption.

The main challenge for the retrofit of pre-combustion to CCGTs, is the ability of the gas turbine to combust hydrogen. The new fuel has a significantly lower volumetric heating value with a flame speed approximately eight times higher than methane, so a different burner design may be required and the gas turbine may require de-rating. Much of the experience gained in high hydrogen firing has been applied to older ‘E’-Class gas turbines, so commercial guarantees may not be available for the higher efficiency machines.

The hydrogen plant is expected to produce large quantities of intermediate pressure steam. However, superheating of this steam is difficult within the hydrogen plant and may not be easily integrated into an existing Heat Recovery Steam Generator (HRSG), so significant efficiency would be lost if this steam cannot be heated prior to expansion in a steam turbine.

The International Energy Agency (IEA) estimate an area of 175m x 150m (Ref1) required for the capture plant fitted to a 500MW CCGT. The area required for Keadby 2, scaled from this estimate, would be available at the Keadby Generation Ltd site.

4.3. Post-Combustion CO2 capture

Chemical absorption is used to separate the CO2 from the gas turbine exhaust gas. The exhaust gas contains very low concentrations (~4.0 mol% (Ref6)) of CO2. Therefore, absorption would require large vessels/building structures and multiple trains may be required for an 810MW (Gross) unit.

CCGT references exist for this technology at 320tpd, which is approximately 5% of the CO2 that would be captured with a 90% capture plant retrofit at Keadby 2. This plant used

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Fluor’s Econamine FG technology and has been operational at the Bellingham plant in Massachusetts, USA since late 1980’s (Ref6).

The additional pressure drop resulting from the absorber would affect the performance and stability of the gas turbine, and HRSG ductwork integrity. A booster fan would be installed to compensate. Space for tie-ins could be made for the stack, steam systems, condensate, and cooling water (feed and return). These tie-ins could be achieved during a normal maintenance turnaround taking around 6 weeks to complete (Ref7).

Post combustion CO2 capture is considered the most appropriate technology for retro-fit to a CCGT and is therefore the focus of this paper.

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5. CCGT Design Considerations

The following considerations are based on the requirements set out in the DECC CCR Guidance Note (Annex C: Environment Agency verification of CCS Readiness New Natural Gas Combined Cycle Power Station Using Post-Combustion Solvent Scrubbing) (Ref1).

5.1. Power Plant Location

The suitability of the location of the Keadby 2 CCGT for access to suitable storage reservoirs and transportation routes is discussed in Sections 2 and 3 above.

The CCGT exhaust gas stack is shown in the CCGT plant layout in Appendix II. Ducting would take the exhaust gases into the CO2 capture equipment on the adjacent plot. The exit route of the compressed CO2 would either be to the north or east of the site.

5.2. Space Requirements

The IEA report (Ref8) cited in the DECC Guidance Note (Ref1) estimates an additional plot size of 250m x 150m (37,500 m2) for post combustion capture equipment for a 500MW CCGT plant. Scaling this figure to the generation capacity of Keadby 2 gives a plot area of 61,500 m2. However, an Imperial College assessment (Ref9) concluded 36% to 50% less plot area may be required.

A CO2 capture plant consistent with this plot area requirement would be accommodated within the boundary of land owned by Keadby Generation Ltd, as shown in Appendix II layout (allocated space for Combined Heat and Power retrofit shown in separate report (Ref16). The Keadby 2 CCGT plant layout and the allotted space for the CCS plant would provide sufficient space for the following considerations:

5.2.1. CO2 Capture Plant

The CO2 capture plant is described in detail in Appendix III.

5.2.2. Gas Turbine

The layout would include a booster fan downstream of the CCGT plant, as discussed in Section 4.3. The booster fan would overcome the pressure drop resulting from the CO2 capture plant and would mitigate the gas turbine performance impact.

The Keadby 2 CCGT will be specified with dry low NOx burners. Certain CO2 capture technologies require levels of NOX below that achievable with low NOX burners in order to prevent degradation of the capture solvents used. In this case it is envisaged that a post combustion NOX abatement system would be retrofitted within the HRSG, e.g. Selective Catalytic Reduction (SCR).

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5.2.3. Boiler and Auxiliaries

A horizontal type HRSG has been proposed for the Keadby 2 CCGT, which would facilitate the extension of ducting to bypass the exhaust stack and lead to the CO2 capture plant. The ducting will be arranged to allow bypass dampers to be inserted to allow the CCGT to operate independently of the CO2 capture plant in the event of CO2 capture plant outages.

A booster fan installed downstream (as discussed in Section 4.3 and 5.2.2) of the CCGT plant would mitigate the impact of increased pressure drop due to the CO2 capture plant.

The HRSG design will allow for retrofitting of SCR, should it be required for application of CCS. The design will leave sufficient space within the structure to fit an ammonia injection grid and catalyst bed. The plant layout also has sufficient space available for ammonia storage vessels, dosing equipment and associated pipework.

The design pressure of steam turbine stages must be selected in order to ensure the flue gas temperature in the HRSG space hosting the SCR module is in the appropriate temperature range. In practice this will be straightforward as the SCR temperature zone is extensive.

5.2.4. Steam Turbine and Auxiliaries

The issue of the steam turbine design is an economic decision requiring careful consideration. The steam extraction required for CO2 capture on a CCGT would require around 40 to 50% of the steam that would normally be used in the low pressure (LP) turbine. The options are as follows:

a) A lower-sized LP cylinder installed from the outset and operated sub-optimally until CCS is implemented.

b) A standard LP cylinder is installed from the outset and operated sub-optimally after CCS is implemented.

c) Standard LP cylinder is installed from the outset, with some blade rows resized prior to CCS commencement based on economic appraisal of costs and benefits.

d) LP steam is taken from a stand-alone auxiliary boiler or Combined Heat and Power (CHP) plant instead of extracting from the CCGT steam cycle (with consequential CO2 emissions from the boilers or CHP plant to be captured).

Given the uncertainty regarding future application to CCS to Keadby 2, the preferred options would be to install a standard LP cylinder and either accept an efficiency penalty should CCS be installed at a later date or partially resize the LP stage if this is determined to be economic. Option d) is likely to result in an efficiency penalty and is not considered a preferred option.

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5.2.5. Water - Steam - Condensate Cycle

The Keadby 2 plant could supply LP steam from the steam turbine IP/LP crossover to the solvent stripper. Further integration of the water process systems could be investigated during detailed design, for example recovery of waste heat from the LP condensate.

5.2.6. Cooling Water System

The cooling duty for the amine scrubber, Direct Contact Cooler and CO2 compression plant have been considered – see Appendix III. An additional 50% cooling duty is likely to be required on top of the base CCGT requirements, although the CCGT requirement will reduce LP steam is supplied form the CCGT to the CO2 capture plant due to lower LP steam flowrates to the condenser. In this case the CO2 capture plant cooling duty may be accommodated by the existing cooling towers. In the case that LP steam from the CCGT is not supplied to the CO2 capture plant or utilisation of the existing cooling towers was found to be a non-optimal solution, modular low level cooling towers similar to those typically used for CCGTs would be installed within the CO2 capture plant area.

The make-up water requirement for the cooling water system would be significant. However, if LP steam is supplied from the CCGT there will be a reduction in CCGT cooling demand due to the reduced LP steam flow to the steam turbine. The Direct Contact Cooler is also a net producer of water, which would reduce make-up demand.

The additional make up water demand could be accommodated within the site water supply constraints.

5.2.7. Raw Water Pre-treatment Plant

The water supply to Keadby 2 is of a sufficient quality that the raw water treatment consists only of filtering for cooling water supply, which is performed close to the source. Raw water supply demand is not anticipated to increase beyond the current site constraints. Therefore no additional provision for treatment is anticipated with the installation of a CO2 capture plant.

5.2.8. Waste Water Treatment Plant

The amine scrubbing plant and Direct Contact Cooler for the post combustion CO2 capture will generate additional effluents. These effluents will be treated within a dedicated waste water treatment plant within the CO2 capture plant and recovered into the water cycle or discharged via the existing proposed sewer outfall line. The CCGT plant drains will be oversized sized in order to accommodate additional effluent produced from the CO2 capture plant. If large quantities of amine degradation products are produced (dependant to a large extent on the type of solvent used) then treatment and disposal of this waste may be done off-site.

The CO2 capture plant will require additional treated water ~3 times greater than the expected maximum demand required by the CCGT alone. The CCGT plant layout has sufficient space to accommodate additional water treatment plant capacity to supply this

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requirement to the steam cycle. Alternatively, the CO2 capture plant water treatment plant could supply this requirement.

5.2.9. Compressed Air System

The CO2 capture equipment will require additional compressed air (both service air and instrument air). These will be stand-alone utilities located adjacent to the CO2 capture equipment. There is limited benefit of integrating these with those anticipated for the base CCGT plant.

5.2.10. Electrical

The main electricity consumers of the CO2 capture plant are the booster fan, CO2 compressors, solvent pumps and cooling water pumps. The total estimated demand is approximately 50 MW. This demand will be supplied from a dedicated station import supply from the grid or potentially from a dedicated combined heat and power plant located within the CO2 capture plant area.

5.2.11. Plant Pipe Racks and Ducting

The installation of additional pipe work will require additional lengths of pipe rack and the exhaust duct to run from the CCGT stack to the inlet of the CO2 capture plant.

The next most significant length of piping would be the LP steam extraction from the steam turbine, if this were the chosen method of providing steam to the CO2 capture plant. Space for this would exist alongside the route of the exhaust ducting.

Return of condensate into the water-steam-condensate cycle and process integration of capture equipment with the water-steam-condensate cycle would be less of an issue in terms of pipe routing.

5.2.12. Control and Instrumentation

A generously sized control building has been shown on the CCGT layout and this should be sufficient for any control and instrumentation equipment required for the CO2 capture plant. Alternatively, a dedicated control room could be located within the CO2 capture plant area.

5.2.13. Additional vehicle movement

The only additional vehicle movements during plant operation would be associated with the transport of the CO2 capture solvent and possibly off-site transport of amine degradation products. The CO2 capture plant requires approximately 70-90 tonnes of aqueous solvent per month for make-up. This would be assumed to be delivered in 30 tonne tankers and therefore three deliveries per month would be required. Delivery and storage of CO2 capture solvent may require a Hazardous Substances Consent from the local authority. Given the site layout and road infrastructure and the experience of receiving chemical deliveries to the existing Keadby Power Station, this is not anticipated to represent an issue.

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5.2.14. Storage and handling of solvent and CO2

Sufficient space is available for storage of 90 tonnes of CO2 capture solvent and an unloading facility. A typical CO2 capture solvent is Monoethanolamine (MEA), which is normally purchased as an 85 wt% solution (low freeze grade) and stored in a nitrogen blanketed tank with a carbon filter on the vent. The MEA would be diluted and an inhibitor added at the solvent sump. The MEA tank would also be located in a fully bunded area capable of holding at least 110% of the volume of the tank. Unloading of road tankers could be undertaken in a covered unloading bay which could be separately drained via suitable separators in case of any spillage.

There will be no storage of CO2 on site. The compression equipment would be proposed to be located at the boundary of the site.

5.3. Safety

5.3.1. CO2 Pipeline

CO2 is not currently defined as a dangerous substance under the Control of Major Accident Hazards Regulations 2015 (COMAH) or as a dangerous fluid under the Pipelines Safety Regulations 1996 (PSR). The HSE also does not provide Land Use Planning advice for CO2 capture, transport or storage. However, the HSE considers supercritical CO2 as having a Major Accident Hazard Potential.

The CO2 pipeline routing and design of CO2 capture plant would follow HSE guidance (Ref3) and would be risk assessed, including modelling of releases and dispersions and assessment of Dangerous Toxic Load.

During detailed design of the pipeline route the following would be considered:

Installation of emergency shut-down valves;

The preparation of a Major Accident Hazard Prevention Document

Preparing appropriate emergency procedures.

5.3.2. CO2 Capture Plant

The plant would be set out with typical chemical industry separation for safety and ease of maintenance. The design of the CO2 capture plant would comply with relevant standards and codes of practice applicable to installations handling supercritical CO2 and take account of lessons learnt from SSE’s Peterhead CCS Front End Engineering Design (FEED) study.

Whilst CO2 is not currently classified as hazardous, DECC and the HSE recognise that an accidental release of large quantities of CO2 could result in a major accident (Ref1). No storage of captured CO2 is proposed in the CCS design. The only stored CO2 on site would therefore be the inventory in the capture plant and on-site pipework. CO2 may be reclassified in future within the COMAH Regulations or within the requirements for Hazardous Substances Consent. These requirements would be reviewed in detail during CCS plant design.

http://www.hse.gov.uk/landuseplanning/index.htm

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The Control of Major Accident Hazards Regulations 2015 (COMAH) is applicable to an establishment which contains named substances in sufficient quantities to be classified as either a lower tier or upper tier establishment. The only additional substance to be used as part of this process is the CO2 capture solvent, which is likely to be amine based. Amines that are typically used as CO2 capture solvents (e.g. monoethanolamine) are not explicitly named as dangerous substances. However, some of the degradation products recovered within the thermal reclaimer, such as nitrosamines, are named as dangerous substances. Therefore the COMAH regulations may apply to the CO2 capture plant depending on the type of solvent used and quantities of degradation products stored on site prior to disposal. Should COMAH apply to the CO2 capture plant, Keadby Generation Ltd has the experience to manage the requirements accordingly.

5.4. Fire Fighting and Fire Protection System

The CCGT firefighting ring main would be extended and an additional booster pump house installed in the CO2 capture utilities area. All fire detection and prevention equipment would be installed in the new CO2 capture area in accordance with best industry practice and in agreement with the HSE, as appropriate. These would be designed in accordance with the latest regulations.

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6. Suitability of Associated Infrastructure

The suitability of the water infrastructure is discussed in section 5 above.

The site is of a sufficient size to accommodate additional office buildings, stores, internal access ways and roads. The increase in traffic for construction would be significant but for operation would be negligible.

The routing of ducts, pipes and cables connecting the CCGT plant area to the CO2 capture plant area would require careful consideration during plant design. There is sufficient space around the CCGT layout to accommodate these connections, with some connections routed across the public road situated between the main CCGT plant and the CO2 stripping and compression plant and cooling towers. Additional roads and walkways around and within the CO2 capture plant would be considered together with pipe, duct and cable routings in order to optimise the layout, mitigate any safety risks, and minimise cost.

.

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7. CCS Retrofit Economic Assessment

7.1. Introduction

This section provides an indication of the cost of retrofitting CCS to a modern CCGT power station, such as the one planned for Keadby 2. This study has reviewed public domain information and considered its application to the Keadby 2 project.

The capital, operating costs and maintenance costs are significantly drawn from a study carried out by the International Energy Agency Greenhouse Gas (Ref2). The authors of this document consulted with a wide range of technology providers and construction companies to reach indicative plant costs and performance estimates.

The International Energy Agency Greenhouse Gas document also supports estimates of plant performance impacts, including reduced power output of the CCS retrofit case relative the base CCGT power station. These figures have been compared with in-house plant performance models and showed good agreement. Since the publication of this report there have been no full scale CCS plant demonstrations on CCGT plant. Therefore, the estimated costs and performance impacts are considered to have an appropriate level of detail and accuracy for the purposes of this assessment.

Information from Ref2 was scaled to match the maximum output capacity of Keadby 2 and adjusted for inflation and currency. It is also the basis of an assumption that the CCS process will capture 90% of the CO2 in the exhaust gas emerging from the CCGT power station. This 90% capture rate is assumed to incorporate all CO2 emissions required to be accounted for in relevant regulations (for example “ancillary” CO2 emissions associated with sorbent preparation and handling).

In addition, this assessment for Keadby 2 is based on a future scenario of UK CCS infrastructure which permits disposal of CO2 at a point of hand-over to an assumed operator of a CO2 transport and storage network (“TSN”).

7.2. Assumptions and Parameters

The general assumptions and parameters used for this assessment are:

(a) A modern 810MW (gross) CCGT power station with 20MW auxiliary load (with unabated CO2 emissions), performing according to design with operation either: optimised for wholesale market conditions, or operated as a baseload station;

(b) A CCS retrofit at suitable scale for the CCGT power station, performing according to design with 90% capture rate including all secondary emissions. In this scenario LP steam is supplied from the CCGT to the CO2 capture plant;

(c) No consideration of additional risks (i.e. beyond design) in relation to technical performance of the CCGT Base Case or the full chain CCS Retrofit cases.

(d) No assumptions regarding financial support for the CCS retrofit or support through the present EMR arrangements (no resulting cost or risk discounts);

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(e) A 15 year operating period for the CCGT and CCS operation, consistent with the duration of EMR contracts. This considers a CCS “retrofit” at the start of the CCGT operating life, and no additional cost is considered for CCGT life extension works;

(f) CCS capital and operating costs include the CCS capture plant, and a CO2 pipeline from Keadby 2 to a connection point at a TSN mentioned in the introduction.

(g) CCS operating costs include a tariff (£10 per tonne of CO2 abated) for CO2 transferred to the TSN at the connection point. This relies on tariff estimates produced for the Energy Technologies Institute (Ref1).

(h) All liabilities in respect of abated CO2 are handed-over to the TSN operator on payment of the tariff. There are no other provisions for the costs of CO2 abated in the CCS Retrofit Cases.

(i) The financial benefits of CCS operation include savings in the costs of Allowances under the EU Emissions Trading Scheme, and may also include savings in the UK Carbon Floor Price (if supplies of gas to CCS are exempted). These benefits are not taken into account in this assessment, and indicative CCS retrofit costs may be directly compared with the costs of CO2 under wider market and regulatory arrangements.

7.3. The modelling approach

Additional costs of CCS are estimated using a financial investment model designed for appraisal of large capital projects.

7.3.1. Risk

This assessment assumes the CCS process has been satisfactorily demonstrated at suitable scale for the power generation industry, and the capital markets are familiar with the risks of investment in abated generating assets.

Any capital investment will still have risks due to the technical performance of both the CCGT and the CCS elements (e.g. planned outages). It may also be subject to market risks, depending on the nature of any financial support under UK regulatory arrangements. Discounted cash flow techniques are deployed in the investment model to recognise these types of uncertainties and investment risks.

Risk factors are accounted for in this assessment using a 10% pre-tax real per annum discount rate.

7.3.2. Capital Costs

The capital costs considered for the CCS Retrofit cases are structured around equipment supply under an EPC (Engineer Procure and Construct) contract with an equipment supplier. Total capital spend include amounts for “owner costs”, including planning, procurement, project management, construction insurance, and costs relating to power station integration (e.g. additional CCGT power station unavailability).

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The following capital estimates are expressed in April 2015 money:

Capture Plant £281M

Compressor Plant £25M

Onshore Pipeline £27.5M

Capital costs are spread over three years and operating costs commence after this period. Using this method, there is no need to add interest during construction to the capital estimates.

7.3.3. Operating Costs

Operational costs considered included the cost of solvent replacement, cost of additional ancillary electricity consumption of the capture and compression processes, an opportunity cost for lost electricity sales due to steam supply from the power station to the capture process, and additional overheads, including CCS-specific maintenance and insurances costs.

The following operating costs estimates are expressed in April 2015 money:

Direct Consumable Cost £1/MWh (electrical export)

Variable Maintenance Cost £218/operating hour

Routine Maintenance £3.1M per annum

Capture Salaries/Admin/Insurance £2.7M per annum

Onshore Pipeline Maintenance £231k per annum

CO2 Storage Tariff £10/tonne

In addition, there is a variable cost due to electricity demand of the CCS process and opportunity cost of power exports lost if the CCGT power station provides steam to the capture plant. A total 140MWe is assumed for these elements based upon in-house plant performance models and the International Energy Agency Green House Gas report (Ref2), resulting in an annual variable cost due to annual lost export at prevailing electricity market prices.

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7.4. Valuation Method

Three cases are considered:

1) Base Case: A new entrant CCGT power station with a gross capacity of 810MW operating at design performance. Planned output is optimised to support an investment case which derives maximum expected value from the asset.

2) CCS Retrofit Case 1: A new entrant CCGT power station with CCS retrofit, with the full CCS chain operating at design performance. Maximum electrical export capacity is reduced by 160MW due to the electrical losses mentioned above in addition to the CCGT auxiliary load. Otherwise, planned output is aligned with the optimised output in the Base Case.

3) CCS Retrofit Case 2: A new entrant CCGT power station with CCS retrofit, with the full CCS chain operating at design performance. Maximum electrical export capacity is reduced by 160MW due to the electrical losses mentioned above in addition to the CCGT auxiliary load. In this case, maximum export is incentivised, resulting in planned baseload operation instead of the optimised output in the Base Case.

CCS Retrofit Case 1 considers the cost of CCS retrofit in a scenario where CCS investment does not alter the original investment case for the CCGT power station, including the optimal plan for operation. This case does not consider the practicalities of flexible capture or the impact of any financial arrangements to support the CCS investment.

CCS Retrofit Case 2 considers the cost of CCS retrofit with more regard to the practicalities of the CCS capture process, and in the context of financial support arrangements which alter the planned operation of the CCGT power station.

The Base Case and CCS Retrofit Case 1 use the optimum operation of the CCGT power station, there is no “market loss” to set off against the CCS investment in these cases. CCS Retrofit Case 2 moves away from the optimum operation of the CCGT power station, and a market loss must therefore be included in this case for sub-optimal CCGT operation. The market loss is estimated to be £112M net present value over the 15 year period of analysis in a scenario where the addition of CCS changes Keadby 2 into an inflexible “base load” operation.

Market loss is estimated on the basis that GB market prices will evolve to ensure supply responds to balance the hourly and seasonal profile of demand. This will reward flexible operation. If there is a sizeable segment of inflexible supply and scarcity of flexible generation, market rewards for flexibility may increase. On reasonable assumptions, the “market loss” for CCS will therefore tend to increase if CCS retrofitted generators are inflexible and CCS expands. The above estimate of £112M is based on Keadby 2 being the first CCS retrofit: it would be greater if Keadby 2 was assumed to be joining a sizeable segment of inflexible CCS-fitted generating capacity.

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7.5. Results

The additional cost of CCS is reported in three forms:

(i) Net Present Value of the whole-lifecycle additional costs of the CCS retrofit (expressed in £ at April 2015);

CCS Retrofit Case 1: £463M

CCS Retrofit Case 2: £977M

(ii) The same Net Present Value estimate of additional costs, expressed as a levelised £/MWh CO2-abated export from the power station (about 90% of total export);

CCS Retrofit Case 1:£39.40/MWh

CCS Retrofit Case 2:£32.30/MWh

(iii) The same Net Present Value estimate of additional costs, expressed as a levelised estimate £/tonne CO2 abated;

CCS Retrofit Case 1: £79.80/tonne

CCS Retrofit Case 2: £65.40/tonne

Ref3 contains more information on the method used to calculate levelised costs for this type of study.

These results compare well with recent CCS economic assessments (Ref13 and Ref14), which estimated CCS costs of £60/tonne to £80/tonne of CO2 captured.

These results are high level estimates, and not developed to the level of detail or cost certainty to support an investment case.

7.6. Economic Assessment Conclusions

Retrofitting of CCS would add significant cost to the operation of a new CCGT power station at Keadby 2.

CCS retrofit to Keadby 2 may achieve an economically viable carbon capture solution following a satisfactory conclusion of the CCS Demonstration Programme, but the economic case would depend on how much CCS-fitted generating capacity already exists at the time.

With this proviso, investors would need confidence that the wider market and regulatory arrangements will secure a cost of CO2 emission above the total additional cost of CCS abatement cost over the life of the investment. This study suggests that CO2 emission costs will need to be more than £60/tonne for economic viability of CCS investment.

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Failing this, CCS investment would require secure financial support to ensure costs are covered over the life of the investment.

With appropriate CO2 cost or financial support CCS technology could theoretically be retrofitted to Keadby 2.

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8. Conclusions

This report has demonstrated the technical feasibility and economic conditions for retrofitting CCS to Keadby 2 in future, given the appropriate market and regulatory conditions.

An assessment of CO2 pipeline routing from Keadby 2 to potential CO2 sinks has shown that a pipeline would be feasible. Potential CO2 sinks have also been identified for a future project.

Adequate space is available on the Keadby 2 site to accommodate a future CO2 capture plant. The CCGT plant layout will provide adequate space for the following:

Piping, cabling, and ducting connecting a future CO2 capture plant to the CCGT.

Additional water treatment plant capacity.

Additional control room equipment and facilities, if required.

The retrofit of a Selective Catalytic Reduction system, including space provided within the HRSG, if required.

Water supplies to Keadby 2 have been deemed sufficient to accommodate the additional make-up water demand following the retrofit of CCS.

No electrical modifications to the CCGT would be required as the power to the CO2 capture plant would be supplied independent from the CCGT.

The source of steam supply to the CO2 capture plant may either come from the CCGT steam turbine or from separate boilers or a Combined Heat and Power plant.

The CCGT design will also incorporate the following:

Steam extraction design features in the Low Pressure steam system to allow for the future steam requirements of the CO2 capture plant, if this option is chosen.

Provision on the HRSG outlet duct to install a new duct to the CO2 capture plant

Following the retrofit of CCS the impacts on the gas turbine and heat recovery steam generator would be minimised by installing a blower downstream of the CCGT plant to overcome the pressure losses associated with the CO2 capture plant.

An economic assessment has demonstrated that with the appropriate market and regulatory conditions the retrofitting of CCS to Keadby 2 would be feasible in future.

In summary:

(1) Suitable storage sites are available.

(2) It is technically and economically feasible (with appropriate market conditions and

regulatory conditions) to retrofit the plant necessary to capture CO2; and

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(3) It is technically and economically feasible (with appropriate market and regulatory

conditions) to transport such captured CO2 to the identified storage sites.

(4) There is sufficient land available to allow a condition to be imposed on the granting

of the section 36C application and on the associated deemed planning permission

that suitable space is set aside for the equipment necessary to capture and compress

all of the CO2 that would otherwise be emitted from the plant.

Keadby Generation Ltd will review and report on the effective maintenance of the plants CCR status within three months of the station starting the supply of electricity to the grid and periodically every two years thereafter.

9. References

Ref1: DECC, Carbon Capture Readiness – A guidance note for Section 36 Electricity Act 1989 consent applications, URN 09D/810, November 2009.

Ref2: ERM, Keadby 2 CCGT: Section 36 and Deemed Planning Consents: EIA Screening Report, February 2013.

Ref3: Website last accessed on 06/05/2015: http://www.hse.gov.uk/carboncapture/major-hazard.htm

Ref4: Website last accessed on 06/05/2015: http://www2.nationalgrid.com/UK/In-your-area/Projects/Yorkshire-and-Humber-CCS/

Ref5: M Bentham, An assessment of carbon sequestration potential in the UK – Southern North Sea case study, Tyndall Centre for Climate Change Research, January 2006.

Ref6: IEA, Improvement in Power Generation with Post-Combustion Capture of CO2, report PH4/33, November 2004.

Ref7: EPRI, CO2 Capture Retrofit Issues: IGCC technical Discussion, Gasification Technologies, 2007.

Ref8: IEA, CO2 capture as a factor in power plant investment decisions, Greenhouse Gas Report, 2006.

Ref9: N Florin and P Fennell, Assessment of the validity of - Approximate minimum land footprint for some types of CO2 capture plant, Imperial College, October 2010.

Ref10: Element Energy and Pöyry (for the Energy Technologies Institute), CCS Sector Development Scenarios in the UK, April 2015.

http://www.hse.gov.uk/carboncapture/major-hazard.htm

http://www.hse.gov.uk/carboncapture/major-hazard.htm

http://www2.nationalgrid.com/UK/In-your-area/Projects/Yorkshire-and-Humber-CCS/

http://www2.nationalgrid.com/UK/In-your-area/Projects/Yorkshire-and-Humber-CCS/

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Ref11: Parsons Brinckerhoff (for the IEAGHG), CO2 Capture at Gas Fired Power Plants, July 2012.

Ref12: Website last accessed on 26/08/2015: https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/223940/DECC_Electricity_Generation_Costs_for_publication_-_24_07_13.pdf

Ref13: JACOBS (for Wainstones Energy), Trafford Power Section 36 Variation - Updated Carbon Capture Readiness Report Addendum, October 2014.

Ref14: URS (for SSE Seabank Land Investment Ltd), Seabank 3 Carbon Capture Ready Report, October 2013.

Ref15: National Grid, Proposed Scheme Report Ref 7.8, The Yorkshire and Humber (CCS Cross Country Pipeline) Development Consent Order, Application Reference EN070001, June 2014.

Ref16: Ramboll Environ (for SSE Generation Ltd), Keadby 2 Combined Cycle Gas Turbine Generating Station – Combined Heat and Power Assessment, UK12-21748, September 2015.

https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/223940/DECC_Electricity_Generation_Costs_for_publication_-_24_07_13.pdf

https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/223940/DECC_Electricity_Generation_Costs_for_publication_-_24_07_13.pdf

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Appendix I: CO2 Pipeline Corridor

Potentially feasible CO2 pipeline corridors have been produced for the Keadby 2 CCGT. Up to 21km from the Keadby 2 site, two potential options have been identified, as shown in Figure 1. Key features along the pipeline options are summarised below. No barriers, unavoidable safety obstacles or environmentally protected areas along these routes have been identified that would prevent the development of a CO2 pipeline in future.

Option 1: Exit Keadby 2 site in a North Easterly direction – Key Features

Along 10km length: Keadby wind farm, agricultural areas, small farm/residential

buildings within a 1 km zone. Roads: A161.

From 10km to 21km length: Dutch River and canal, M62, Rawcliffe Road, River Aire,

A645, railway line (south of Goole).

Special Areas of Conservation, Special Protection Areas or Sites of Special Scientific

Interest are located around Humberhead Peatlands National Nature Reserve to the

south of the potential pipeline route (Ref2).

Option 2: Exit Keadby 2 site in a Northerly direction – Key Features

Along 10km length: Keadby wind farm, agricultural areas, small farm/residential

buildings within a 1 km zone. Roads: B1392, A161 (not crossing but within a 1km

zone).

From 10km to 21km length: Main Street (Pennyhill Cottages), River Ouse, Main

Street (Gilberdyke), M62, Eastrington, and two railways lines (near Gilberdyke).

No Special Areas of Conservation, Special Protection Areas or Sites of Special

Scientific Interest (Ref2).

Figure 2 shows the CO2 pipeline corridor from the end of pipeline corridor options 1 and 2 up to the UK coast at Barmston, south of Bridlington. This pipeline route has been based on that proposed by the National Grid Yorkshire and Humber CCS Cross Country Pipeline project (Ref4).

Key features along corridor from 21km to Barmston

A detailed description of the National Grid Yorkshire and Humber CCS pipeline is

presented in a publically available document (Ref15).

Special Areas of Conservation, Special Protection Areas, Sites of Special Scientific

Interest and archaeology sites exist within the 10km corridor. An optimised route

could minimise routing through these areas (Ref15).

Figure 3 shows the CO2 pipeline route from the coast to two potential CO2 storage sites 5/42 or 2/48 (Ref5).

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Figure 1: Option 1 and Option 2 CO2 pipeline corridors up to 21km from the Keadby 2 CCGT.

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Figure 2: CO2 pipeline corridor from 21km away from Keadby 2 to the UK coast at Barmston, south of Bridlington.

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Figure 3: CO2 pipeline corridor from Barmston, south of Bridlington to two potential CO2 storage sites 5/42 or 2/48 (Ref5).

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Appendix II: CO2 Capture Plant Location

The amount of land owned by Keadby Generation Ltd adjacent to the proposed Keadby 2 CCGT is sufficient to accommodate a CO2 capture plant, as shown in Figures 4. The layout avoids affords adequate spacing from power lines, avoids obstructing existing public roads, and makes use of space currently occupied by liquid fuel handling facilities and storage tanks, which are no longer in use.

Figure 4: CO2 Capture Plant location with CCGT plant layout.

Rich Solvent Pump

Rich Solvent Pump

Absorber

Booster Fan

Gas-Gas Heater

Direct Contact Cooler

DCC Pump

DCC Pump

DCC Pump

DCC Pump

Wash Water

Circulat

ing Pump

Wash Water

Cooler

DCC Water Cooler

Wash Water

Circulat

ing Pump

DCC Water

Filter

Wash Wate r Filter

Lean Solvent Filter

Activa

ted Carbo n Filte

r

Anti-Foam System

Rich Solvent Pump

Rich Solvent Pump

Absorber

Booster Fan

Gas-Gas Heater


DCC Pum

p

DCC Pum

p

DCC Pum

p

DCC Pum

p

Wash Water Circulating Pump

Wash Water Cooler

DCC Water

Cooler

Wash Water Circulating Pump

DCC Water Filte

r

Wash

Wate r Filter

Lean Solvent Filter

Activa ted Carbo n Filter

Anti-Foam System

Solvent Make-Up Pump

Reflux Pump

Lean Solvent Pump

Waste Water Sump Pump

Solvent Sump Pump

H2SO4 Solution Pump

Condensate Pump

Solvent Cross Exchanger

Lean Amine Cooler

Reclaimer

Stripper Condensor

Reboiler


Lean Solvent Pump

Reflux Pump

Condensate Pump


Solvent Sump Pump

H2SO4 Solution Pump

NaOH Solution Pump

NaOH Solution Pump

Am

ine Storage

Overhead A

ccum

ulator

Steam C

ondensate

Dru

m

Waste Water Sump

Solvent Sump

H2SO4 Solution Tank

NaOH Solution Tank

Stripper

Solvent

Sump Filter

Waste

Water Sump

Filter

Instrument Air System

Nitrogen Blanketing System

Compre

ssor St

age 1 In

tercool

er

Compre

ssor St

age 2 In

tercool

er

Compre

ssor St

age 3 In

tercool

er

Compre

ssor St

age 4 In

tercool

er

Compre

ssor St

age 5 In

tercool

er

Compressor

Compressor Stage 1 Drum



Compressor

Stage 4 Drum

Compressor

Stage 5 Drum

Compre

ssor


Reflux Pump

Lean Solvent Pump


Solvent Sump Pump

H2SO4 Solution Pump

Condensate Pump

Solvent Cross Exchanger

Lean Amine Cooler

Reclaimer

Stripper Condensor

Reboiler


Lean Solvent Pump

Reflux Pump

Condensate Pump


Solvent Sump Pump

H2SO4 Solution Pump

NaOH Solution Pump

NaOH Solution Pump

Am

ine Storage

Overhead A

ccum

ulator

Steam C

ondensate

Dru

m

Waste Water Sump

Solvent Sump

H2SO4 Solution Tank

NaOH Solution Tank

Stripper

Solvent

Sump Filter

Waste

Water Sump

Filter

Instrument Air System

Nitrogen Blanketing System

Compre

ssor St

age 1 In

tercool

er

Compre

ssor St

age 2 In

tercool

er

Compre

ssor St

age 3 In

tercool

er

Compre

ssor St

age 4 In

tercool

er

Compre

ssor St

age 5 In

tercool

er

Compressor




Compressor

Stage 4 Drum

Compressor

Stage 5 Drum

Compre

ssor

HTC Reciculation Pump

Hybrid Cooling Tower










HTC Recirculation Pump

HTC Reciculation Pump











HTC Recirculation Pump

Cooling towers

for CO2 capture

plant

CO2 Pipeline

Stripping section

and CO2

compression

Flue gas cooling

and CO2

absorption

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Appendix III: CO2 Capture Plant Process Description

Overview

In a post-combustion CO2 capture plant CO2 is captured just before the flue gas is emitted from the stack. To achieve this, a CO2 scrubbing column is used to absorb CO2 from the flue gas stream into a solvent, typically amine based. The solvent is then regenerated in a stripping column which releases concentrated CO2.

The challenges inherent to post combustion capture solutions (particularly on a gas plant) include:

• The low CO2 concentration (~4% wet) of the flue gas stream

• The volume of ambient pressure gas to be processed which leads to very wide columns

• The high energy (steam) demand of the stripping column

• Degradation of the solvent over time

• Materials compatibility with the solvent and carbonic acid

• The flexibility of the CO2 capture plant in comparison to grid demand

There are numerous solvents available but the most mature are based on mono ethanol amine (MEA) with corrosion inhibitors. Other solutions are based on more advanced amines or ammonia.

A typical advanced technology GT exhaust flow at base load would require the absorption of around 6,000 tonnes or more per day of CO2. Consequently, a layout with multiple absorber trains would likely be required.

Each absorption train requires a Direct Contact Cooler (DCC), blower, absorber and associated filters, heat exchangers and pumps. There can be several absorptions trains all linked to a single regeneration and CO2 compression section.

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Process Description

The Process Flow Diagram for a single train unit is shown in Figure 6.

Figure 6: Process flow diagram for an amine absorber train

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The flue gas exiting the Absorber (C-101) is requires cooling prior to entering the Absorber. This can be achieved in a Direct Contact Cooler (DCC), C-100, which quenches the flue gas to ~38°C to maintain CO2 recovery and minimise solvent degradation.

A small slipstream of the circulating water is extracted and routed through the DCC Water Filter (F-100) to remove particulates. A portion of this particulate free stream is returned to the DCC.

Cool, saturated flue gas from the DCC is extracted through the Blower (BL-100) which is required to overcome the frictional losses in the ducting, DCC and Absorber.

Absorber, C-101

The cooled flue gas from DCC is fed to the bottom of the counter current Absorber (C-101) where CO2 in the flue gas is absorbed by the solvent.

Flue gas enters near the bottom of the Absorber and flows upward through packed beds. CO2 reacts chemically with solvent and is absorbed into the bulk solution. Rich solvent leaves the bottom of the Absorber and is transferred to the Stripper (C-102) by the Rich Solvent Pump (P-103).

CO2 absorption by MEA (a probable solvent) is an exothermic reaction. The heat produced from these reactions will result in a very small portion of the MEA and water solution being vaporized. Stripped flue gas, vaporized MEA and water travel through the chimney tray and enter another packed bed. This packed bed is the wash section of the column, where wash water is used to recover the vaporized MEA and water. A Wash Water Circulating Pump (P-102) circulates the wash water between the Absorber and Wash Water Cooler (E-101).

Flue gas is vented to atmosphere via the stack on top of each Absorber at a temperature of 40-50°C. The low temperature and water saturated nature of this post-capture flue gas will have an impact on plume visibility and dispersion; which will require scrutiny in the event of CO2 capture retrofit.

Prior to the DCC some of the waste heat contained within the HRSG exit gas can be recovered by heat exchanging with the absorber exit gas in a Gas-Gas Heater. Heating the absorber exit gas would aid dispersion once it exits the stack. However, some gas leakage can occur within a Gas-Gas-Heater, potentially transferring CO2 from the HRSG exit gas into the cleaned absorber exit gas. An alternative solution would be to supply the required heat from the stripper reboiler condensate. This option would also reduce the HRSG exit gas temperature by reducing the HRSG feed water temperature (supplied partially from the reboiler condensate) and hence the economiser outlet temperature.

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Stripper C-102

Rich solvent leaves the bottom of the Absorber at ~44°C and is routed to a common rich amine header. The combined rich amine flows to a Lean/Rich Cross Exchanger (E-102). The Lean/Rich Cross Exchanger increases the efficiency of the process by heating the rich amine to >100°C using the heat in the lean amine stream from the Stripper.

The preheated rich amine enters the Stripper below the wash section of the column through a liquid distributor and flows down through the packed beds counter-current to the vapour from the Reboiler (E-104) releasing the absorbed CO2.

The lean amine from the bottom of the Stripper is routed to the Lean/Rich Cross Exchanger, where it is cooled to ~50°C against the rich amine from the absorber train.

To remove impurities from the amine system, ~10% of the cooled amine is routed to the Amine Filter Package (F-102). This removes suspended solids and high molecular weight amine degradation products.

Reflux Condenser

The overhead vapour from the Stripper at ~100°C and 0.8 barg is cooled to ~35°C in the Reflux Condenser (E-106), condensing some of the vapour. The two-phase flow enters the Reflux Drum (V-100) separating the product gas which is routed to the CO2

Compression/Dehydration unit.

Heat Exchangers

Associated with the Strippers are the physically large heat exchangers (E-102) which create a layout challenge. Larger single units may be built. However, the small number of fabricators with these capabilities could make the cost excessive and multiple units may be required.

Amine Reclaimer

In addition to the Amine Filter Package, the Reclaimer provides supplementary means of purifying the amine solution by removing the products of oxidative degradation of the solvent. The Reclaimer is a steam heated kettle-type re-boiler, which vaporises the volatiles, leaving the non-volatile degradation products in the Reclaimer which are then drained to the Reclaimer waste drum.

Centrifugal Compressor

The wet CO2 from the Stripper Reflux Drum is routed to a (probably electrically driven) CO2 Compressor (K-101). The compression process has multiple stages with intercooling, requiring significant quantities of cooling water. The captured CO2 is compressed to approximately 150barg to ensure it remains in dense phase during transportation.

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Dehydration Unit

Compressed gas at ~50 barg is extracted from the CO2 Compressor and routed to the Dehydration Package. This may either be mono-ethylene glycol wash or a zeolite based adsorption process. The dry vapour is then routed back to the compressor.

For a glycol wash system, the wet CO2 enters the bottom of the dryer absorber, where it is contacted with lean glycol, and water is removed from the gas. The glycol is dried by indirect gas fired heating.

For an adsorption system, the wet CO2 is passed through a fixed bed of zeolite pellets. Once the adsorption bed is saturated with water, the CO2 feed is sent to another vessel. The water is removed from the saturated bed by depressurising and passing hot nitrogen or air through it.

<50 wt ppm of water is required to prevent corrosion of the CO2 transport pipework.

Process Utility Requirements

Steam Supply Options

A supply of low pressure (~3 to 4 bara) steam will be required for the amine regeneration process. The precise quantity will depend of the capture process design – the technological development aim being to reduce as far as possible the ratio of required steam per tonne of CO2 captured.

This steam could be supplied from the steam turbine (ST) Intermediate Pressure (IP) exhaust to Low Pressure (LP) inlet ‘cross-over pipe’, i.e. internal to the cycle. Other options include a dedicated LP turbine bleed, with possible augmentation from higher grade ‘cold reheat’ steam; all with and without various ST resizing scenarios. Alternatively, auxiliary boilers or a CHP plant could be installed to provide the required steam, although they would produce additional CO2 emissions, which would need to be captured.

The simplest option would appear to be from the cross-over pipe with the addition of a downstream pressure sustaining control valve, and an unchanged ST. However, for a CCGT of this size, this steam extraction represents around 50% of the steam flow through the LP turbine and may lead to design and operational restrictions.

The overall impact on the output and efficiency on the CCGT may be around 10-15% reduction, depending on the steam consumption ‘efficiency’ of the amine process Note that a 10% loss in terms of efficiency is absolute, e.g. 60% × 0.9 = 54%, not 50%. Additionally, CO2 capture plant power requirements (CO2 compressors, solvent pumps, etc.) will reduce overall plant efficiency by a further 10%, approximately.

Ultimately, these considerations would need to be studied in detail at the design stage to balance cost and efficiency impacts; with acceptable plant operational integrity and flexibility.

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Treated Water (Process make-up and boiler feed)

Additional process water would be required, ~3 times greater than the expected maximum demand of the base CCGT alone. Methods to recover water internal to the process by cooling the flue gas below the water dew point may be practical and useful. Although this may help with plume humidity and utility water requirements, an even lower flue gas temperature (~35°C) may be problematic for gas dispersion and hence ground level concentration of NOx and CO. Reheating of the flue gas would be required to overcome this problem, possibly through heat exchange with stripper condensate or HRSG exit gas.

Cooling Medium

The cooling medium required is a clean water system with modular low level cooling towers similar to those typically used for CCGTs. It is anticipated that an additional 50% supply would be required. The make-up water requirement for the cooling water system would be significant. However, if LP steam is supplied from the CCGT there will be a reduction in CCGT cooling demand due to the reduced LP steam flow to the steam turbine. The water recovery process described above would also reduce site water demand.

In all considered scenarios the make-up water demand is considered to be within the existing site constraints.

Documents

Carbon Capture Readiness Report for Keadby 2 CCGT · Carbon Capture Readiness Report for Keadby 2 CCGT Technical Report No: TR-GEN-AM-KEAD2-003 ... Following the retrofit of CCS the