Project: ACT Acorn Feasibility Study
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The ACT Acorn Consortium partners reserve all rights in this material and retain full copyright. Any reference to this material or use of the material must include full acknowledgement of the source of the material, including the reports full title and its authors. The material contains third party IP, used in accordance with those third party’s terms and credited as such where appropriate. Any subsequent reference to this third party material must also reference its original source. The material is made available in the interest of progressing CCS by sharing this ACT work done on the Acorn project.
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Acorn
D03 Basis of Design for St Fergus Facilities 10196ACTC-Rep-06-01 January 2018
www.actacorn.eu
with input from
ACT Acorn, project 271500, has received funding from BEIS (UK), RCN (NO) and RVO (NL), and is co-funded by the European Commission under the ERA- Net instrument of the Horizon 2020 programme. ACT Grant number 691712. D03 Basis of Design for St Fergus Facilities Contents
Contents
Document Summary
Client Research Council of Norway & Department of Business, Energy & Industrial Strategy
Project Title Accelerating CCS Technologies: Acorn Project Title: D03 Basis of Design for St Fergus Facilities
Distribution: Classification: Client Confidential
Date of Issue: 30th November 2017 Name Role
Prepared by: Sam Gomersall Commercial Director
Approved by: Steve Murphy Finance Director Rev Date Description Issued By Checked By Approved By V01 08/01/2018 First Issue C Hartley T Dumenil S Murphy
Disclaimer:
While the authors consider that the data and opinions contained in this report are sound, all parties must rely upon their own skill and judgement when using it. The authors do not make any representation or warranty, expressed or implied, as to the accuracy or completeness of the report. The authors assume no liability for any loss or damage arising from decisions made on the basis of this report. The views and judgements expressed here are the opinions of the authors and do not reflect those of the client or any of the stakeholders consulted during the course of this project.
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D03 Basis of Design for St Fergus Facilities Contents
Table of Contents
CONTENTS ...... 3
1.0 EXECUTIVE SUMMARY ...... 10
2.0 INTRODUCTION ...... 11
3.0 SCOPE OF WORK ...... 16
4.0 THE ST FERGUS GAS TERMINAL ...... 18
5.0 METHODOLOGY ...... 26
6.0 RE-USE OF THE SAGE PLANT ...... 29
7.0 NEW BUILD CAPTURE FACILITY ...... 37
8.0 FUTURE CONSIDERATIONS ...... 47
9.0 CONCLUSIONS ...... 49
10.0 REFERENCES ...... 50
ANNEX 1 MASS AND ENERGY BALANCES...... 52
ANNEX 2 CONSENT REGISTER ...... 56
ANNEX 3 MAJOR EQUIPMENT LIST FOR CAPTURE FACILITY ...... 58
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D03 Basis of Design for St Fergus Facilities Contents
CONTENTS ...... 3
TABLE OF CONTENTS ...... 4 FIGURES ...... 8 TABLES ...... 9
1.0 EXECUTIVE SUMMARY ...... 10
2.0 INTRODUCTION ...... 11
2.1 ACT ACORN OVERVIEW ...... 11 2.2 ACORN DEVELOPMENT CONCEPT ...... 14
3.0 SCOPE OF WORK ...... 16
3.1 PURPOSE ...... 16 3.2 SCOPE ...... 16 3.3 CONTEXT ...... 16 3.4 ASSUMPTIONS ...... 17
4.0 THE ST FERGUS GAS TERMINAL ...... 18
4.1 THE ANCALA OPERATION ...... 19 4.2 THE SHELL OPERATION ...... 20 4.3 THE NSMP OPERATION ...... 21 4.4 THE NATIONAL GRID GAS OPERATION ...... 22
4.5 CO2 EMISSION POINTS FOR CAPTURE ...... 23 4.6 POTENTIAL LOCATIONS FOR A NEW BUILD CAPTURE PLANT ...... 25
5.0 METHODOLOGY ...... 26
5.1 DEVELOPING THE CAPTURE OPTIONS ...... 26 5.2 OVERALL DESIGN CONSIDERATIONS ...... 26 5.3 PROCESS DESIGN ...... 27
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D03 Basis of Design for St Fergus Facilities Contents
5.4 SAGE PLANT ...... 27
6.0 RE-USE OF THE SAGE PLANT ...... 29
6.1 INTRODUCTION ...... 29
6.2 CO2 CAPTURE MODELLING ...... 31 Process Simulation Modelling ...... 31
CO2 Capture Technology ...... 31 Process Description ...... 32 Simulation Results ...... 34 6.2.4.1 Flue Gas from Gas Turbines ...... 34 6.2.4.2 Flue Gas from Gas Heaters ...... 34 6.2.4.3 Flue Gas from Multiple Sources ...... 34 6.2.4.4 Exhaust Gas Recycling ...... 34 Capture Capacity ...... 34 6.3 UPGRADING OF EXISTING FACILITIES ...... 35 6.4 FLUE GAS CONDITIONING PRE-CAPTURE ...... 35 6.5 COMPRESSION FACILITIES POST CAPTURE ...... 36 6.6 COST ESTIMATES ...... 36
7.0 NEW BUILD CAPTURE FACILITY ...... 37
7.1 BENEFITS OF NEW BUILD ...... 37 7.2 BASIS OF DESIGN ...... 37 Throughput, Feed Gas Composition and Condition ...... 37 Required Unit Performance ...... 38 Utilities ...... 38 Plant Availability ...... 38 Site Details ...... 38 Construction Considerations ...... 38 7.3 PLANT DESCRIPTION ...... 38
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D03 Basis of Design for St Fergus Facilities Contents
Flue Gas Conditioning ...... 39
CO2 Capture ...... 39
CO2 Export ...... 40 7.4 PLANT DESIGN ...... 40 Flue Gas Conditioning ...... 40
CO2 Capture Plant ...... 41
CO2 Export ...... 43 7.5 OPERATING COST...... 44 7.6 CAPITAL COST...... 45 Project Scope ...... 45 Methodology and Assumptions ...... 45 Summary ...... 46
8.0 FUTURE CONSIDERATIONS ...... 47
8.1 CAPTURE OPTION SELECTION ...... 47 8.2 CONSENTING ...... 47 8.3 ISSUES, RISKS AND CHALLENGES ...... 48 8.4 FURTHER TECHNICAL WORK ...... 48
9.0 CONCLUSIONS ...... 49
10.0 REFERENCES ...... 50
ANNEX 1 MASS AND ENERGY BALANCES...... 52
ANNEX 2 CONSENT REGISTER ...... 56
ANNEX 3 MAJOR EQUIPMENT LIST FOR CAPTURE FACILITY ...... 58
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D03 Basis of Design for St Fergus Facilities Contents
Figures
FIGURE 2-1: ACT ACORN CONSORTIUM PARTNERS ...... 11 FIGURE 2-2: KEY AREAS OF INNOVATION ...... 12 FIGURE 2-3: ACT ACORN WORK BREAKDOWN STRUCTURE ...... 12 FIGURE 2-4: ACORN OUTLINE MINIMUM VIABLE DEVELOPMENT PLAN ...... 14 FIGURE 2-5: ACORN BUILD OUT SCENARIO FROM THE 2017 PCI APPLICATION ...... 15 FIGURE 4-1: ST FERGUS GAS TERMINAL AND PETERHEAD AREA (GOOGLE MAPS, 2017) ...... 18 FIGURE 4-2: AERIAL PHOTOGRAPH OF THE ST FERGUS TERMINAL (TOTAL, 2009) ...... 18 FIGURE 4-3: APPROXIMATE BOUNDARIES OF THE FOUR OPERATIONS (ADAPTED FROM GOOGLE MAPS, 2017) ...... 19 FIGURE 4-4: THE ANCALA / SAGE PLANT, (APACHE, 2017) ...... 19 FIGURE 4-5: SAGE TERMINAL OVERVIEW, (APACHE, 2015) ...... 20 FIGURE 4-6: THE SHELL PLANT, (SHELL, 2017) ...... 20 FIGURE 4-7: THE NSMP PHASE 2 PLANT WITH SHELL PLANT IN THE DISTANCE, (NSMP, 2017) ...... 22 FIGURE 4-8: THE DECOMMISSIONED MILLER GAS PROCESSING FACILITY, (NSMP, 2017) ...... 22 FIGURE 4-9: THE CAPPED END OF THE PRESERVED MGS PIPELINE, (NSMP, 2017) ...... 22 FIGURE 4-10: NSMP’S PHASE 2 HEATER STACKS (LEFT) AND PHASE 3 HEATER STACKS (RIGHT), (NSMP, 2017) ...... 24 FIGURE 4-11: SHELL PLANT FROM THE NSMP PLANT: THE TWO GAS TURBINE STACKS (YELLOW) AND TWO OF THE HEATER STACKS (RED), (NSMP, 2017) ...... 24 FIGURE 4-12: SHELL PLANT STACKS: THE TWO GAS TURBINES STACKS (YELLOW) AND FOUR OF THE HEATER STACKS (RED), (SHELL, 2017) ...... 25 FIGURE 4-13: AVAILABLE LAND SOUTH OF THE NSMP PHASE 3 PLANT (NSMP, 2017) ...... 25 FIGURE 5-1: METHODOLOGY FOR EVALUATING CAPTURE OPTIONS ...... 26 FIGURE 6-1: THE SOUTHER AREA GAS EVACUATION (SAGE) TERMINAL AT ST FERGUS ...... 29 FIGURE 6-2: EXISTING SAGE BLOCK FLOW DIAGRAM (BFD), (APACHE, 2015) ...... 30 FIGURE 6-3: PROCESS FLOW DIAGRAM OF EXISTING FACILITIES ...... 33 FIGURE 7-1: BLOCK FLOW DIAGRAM FOR NEW BUILD CAPTURE ...... 39
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D03 Basis of Design for St Fergus Facilities Contents
Tables
TABLE 2-1: ACT ACORN MILESTONES AND DELIVERABLES ...... 13
TABLE 4-1: CO2 EMISSIONS AND CAPTURE POTENTIAL AT ST FERGUS – 2015 DATA ...... 23 TABLE 6-1 SAGE TERMINAL NATURAL GAS ENTRY SPECIFICATION 2005, (APACHE, 2015) ...... 31 TABLE 6-2: SIMULATION RESULTS FOR SINGLE PROCESS TRAIN MODELLING ...... 35 TABLE 7-1: FLUE GAS COMPOSITION ...... 37 TABLE 7-2: ELECTRICITY CONSUMPTION AND COST ...... 44 TABLE 7-3: LP STEAM CONSUMPTION AND COST ...... 44 TABLE 7-4: COST ESTIMATE SUMMARY (THOUSAND GBP) ...... 46
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D03 Basis of Design for St Fergus Facilities Executive Summary
1.0 Executive Summary
This study considered the potential for capturing ~200,000T/yr of CO2 emissions from the St Fergus gas terminal. Existing emissions from across the four Capturing ~200,000T/yr of existing emissions from terminal sites are ~570,000T/yr making it one of the largest emissions locations
St Fergus is possible. in Scotland. CO2 emissions are created from burning natural gas used for heating and power generation during the gas processing operations. Potential exists to re-use the SAGE gas sweetening An existing gas sweetening plant has been separating CO2 from natural gas at plant to capture CO2 from flue gas emissions. the SAGE terminal for 20 years. Within the next few years it will no longer be
required for this purpose and could become available for separating CO2 from
Further work is required to confirm the viability of flue gas. This study considers the potential for re-using the SAGE CO2 plant and, SAGE re-use, especially regarding plant condition, as an alternative, considers the option of a new build capture facility.
capture rate and cost. At this stage both capture options appear possible, although without detailed information on the condition of the SAGE plant and further design studies, it is A new build capture plant could be built which would not possible to be certain about the viability of the SAGE plant re-use. Additional have the advantages of being designed for purpose, work is required especially regarding plant condition, throughput efficient, cost optimised and located to capture capacity/constraints and the cost of re-purposing the facility. emissions from multiple sources. Space exists to build a standalone capture plant, which would have the advantage of being purpose built, new and in a location to optimise collection of
Further engineering study work is required to CO2 emissions from multiple sites.
develop and then assess the two capture options More detailed technical engineering studies are required to assess the two capture alternatives, which along with other commercial, risk and regulatory factors, will enable an effective option selection prior to Front End Engineering and Design (FEED).
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D03 Basis of Design for St Fergus Facilities Introduction
2.0 Introduction
2.1 ACT Acorn Overview The research and innovation study addresses all thematic areas of the ACT Call including ‘Chain Integration’. The project includes a mix of both technical and ACT Acorn, project 271500, has received funding from BEIS (UK), RCN (NO) non-technical innovation activities as well as leading edge scientific research. and RVO (NL), and is co-funded by the European Commission under the ERA- Together these will enable the development of the technical specification for an Net instrument of the Horizon 2020 programme. ACT Grant number 691712. ultra-low cost, integrated CCS hub that can be scaled up at marginal cost. It will ACT Acorn is a collaborative project between seven organisations across move the Acorn development opportunity from proof-of-concept (TRL3) to the Europe being led by Pale Blue Dot Energy in the UK, as shown in Figure 2-1. pre-FEED stage (TRL5/6) including iterative engagement with relevant investors in the private and public sectors.
Specific objectives of the project are to:
1. Produce a costed technical development plan for a full chain CCS
hub that will capture CO2 emissions from the St Fergus Gas
Terminal in north east Scotland and store the CO2 at an offshore storage site (to be selected) under the North Sea. 2. Identify technical options to increase the storage efficiency of the selected storage site based on scientific evidence from
geomechanical experiments and dynamic CO2 flow modelling and through this drive scientific advancement and innovation in these areas. 3. Explore build-out options including interconnections to the nearby
Peterhead Port, other large sources of CO2 emissions in the UK
region and CO2 utilisation plants 4. Identify other potential locations for CCS hubs around the North Sea regions and develop policy recommendations to protect relevant
Figure 2-1: ACT Acorn consortium partners
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D03 Basis of Design for St Fergus Facilities Introduction
infrastructure from premature decommissioning and for the future infrastructure re-use; lifecycle analysis; environmental impact; economic
ownership of potential CO2 stores. modelling; FEED and development plans; and build out growth assessment. 5. Engage with CCS and low carbon economy stakeholders in Europe The project will be delivered over a 19-month period, concluding on the 28th and worldwide to disseminate the lessons from the project and February 2019. During that time, it will create and publish 21 items known as encourage replication. Deliverables. Collectively these will provide a platform for industry, local CCS is a new and emerging industry. Maturity improvements are required in the partnerships and government to move the project forward in subsequent phases. application of technology, the commercial structure of projects, the scope of It will be driven by business case logic and inform the development of UK and each development and the policy framework. European policy around infrastructure preservation. The deliverables are listed in Table 2-1. The key areas of innovation in which the project will seek insights are summarised in Figure 2-2.
Figure 2-3: ACT Acorn work breakdown structure Figure 2-2: Key areas of innovation
The project activity has been organised into 6 work packages as illustrated in
Figure 2-3. Specific areas being addressed include; regional CO2 emissions; St
Fergus capture plant concept; CO2 storage site assessments and development plans; reservoir CO2 flow modelling, geomechanics; CCS policy development;
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D03 Basis of Design for St Fergus Facilities Introduction
Milestone Deliverable D01 Kick-off Meeting Report
1) St Fergus Hub Design D02 CO2 Supply Options D17 Feeder 10 Business Case D03 Basis of Design for St Fergus Facilities D04 Site Screening Methodology 2) Site Screening & Selection D05 Site Selection Report D13 Plan and Budget for FEED 3) Expansion Options D18 Expansion Options D10 Policy Options Report D11 Infrastructure Reuse Report 4) Full Chain Business Case D14 Outline Environmental Impact Assessment D15 Economic Model and Documentation D16 Full Chain Development Plan and Budget D06 Geomechanics Report 5) Geomechanics D07 Captain X Storage Development Plan and Budget D08 Site 2 Storage Development Plan and Budget 6) Storage Development Plans D09 Eclipse Model Files 7) Lifecycle Assessment D12 Carbon Lifecycle Analysis D21 Societal Acceptance Report 8) Project Completion D19 Material for Knowledge Dissemination Events D20 Publishable Final Summary Report
Table 2-1: ACT Acorn Milestones and Deliverables
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D03 Basis of Design for St Fergus Facilities Introduction
The Consortium includes a mix of industrial, scientific and CCS policy experts in keeping with the multidisciplinary nature of the project. The project is led by Pale Blue Dot Energy along with University of Aberdeen, University of Edinburgh, University of Liverpool, Heriot Watt University, Scottish Carbon Capture & Storage (SCCS), Radboud University and The Bellona Foundation. Pale Blue
Dot Energy affiliate CO2DeepStore are providing certain input material. 2.2 Acorn Development Concept
Many CCS projects have been burdened with achieving “economies of scale” immediately to be deemed cost effective. This inevitably increases the initial cost hurdle to achieve a lower lifecycle unit cost (be that £/MWh or £/T) which raises the bar from the perspectives of initial capital requirement and overall project risk.
The Acorn development concept use a Minimum Viable Development (MVD) approach. This takes the view of designing a full chain CCS development of industrial scale (which minimises or eliminates the scale up risk) but at the lowest capital cost possible, accepting that the unit cost for the initial project may be high for the first small tranche of sequestered emissions.
Acorn will use the unique combination of legacy circumstances in North East Scotland to engineer a minimum viable full chain carbon capture, transport and offshore storage project to initiate CCS in the UK. The project is illustrated in Figure 2-4 and seeks to re-purpose an existing gas sweetening plant (or build a new capture facility if required) with existing offshore pipeline infrastructure connected to a well understood offshore basin, rich in storage opportunities. All the components are in place to create an industrial CCS development in North Figure 2-4: Acorn Outline Minimum Viable Development Plan East Scotland, leading to offshore CO storage by the early 2020s. 2
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D03 Basis of Design for St Fergus Facilities Introduction
A successful project will provide the platform and improve confidence for further low-cost growth and incremental development. This will accelerate CCS deployment on a commercial basis and will provide a cost effective practical stepping stone from which to grow a regional cluster and an international CO2 hub.
The seed infrastructure can be developed by adding additional CO2 capture points such as from hydrogen manufacture for transport and heat, future CO2 shipping through Peterhead Port to and from Europe and connection to UK national onshore transport infrastructure such as the Feeder 10 pipeline which can bring additional CO2 from emissions sites in the industrial central belt of Scotland including the proposed Caledonia Clean Energy Project, CCEP. A build out scenario for Acorn used in the 2017 Projects of Common Interest (PCI) application is included as Figure 2-5.
Pale Blue Dot Energy is exploring various ways and partners to develop the Acorn project. Figure 2-5: Acorn build out scenario from the 2017 PCI application
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D03 Basis of Design for St Fergus Facilities Scope of Work
3.0 Scope of Work
3.1 Purpose 3.3 Context
The purpose of Deliverable D03 Basis of Design for St Fergus Facilities (D03) St Fergus will be a future CCS hub: As a result of its location and current gas is to document the design basis and conceptual design options for the capture processing activities, St Fergus will become an important future CCS hub. It has and compression facilities required to capture CO2 from major point sources at existing pipeline transport links offshore (Atlantic, Goldeneye and Miller Gas
St Fergus gas terminals and prepare that CO2 for offshore transport and injection. System (MGS) pipelines) and existing onshore pipeline links (Feeder 10). It is By doing so, the project would make a significant contribution to reducing located close to the massive storage potential of the UK Central North Sea and existing CO2 emissions in Scotland and initiate a CO2 transport and storage has nearby access to a deep-water shipping port at Peterhead. Initiating CCS infrastructure hub at St Fergus which can be used by other CCS projects. at St Fergus opens up the long-term potential for CCS in Scotland. 3.2 Scope SAGE re-use: Assessment of potential re-use of existing facilities is a key aspect of the ACT Acorn project. The Scottish Area Gas Evacuation (SAGE) The scope of work includes; terminal at St Fergus has a processing facility used to strip excess CO2 from
• To review the St Fergus gas terminals and outline their CO2 natural gas prior to the methane being put into the National Transmission emissions sources and types System (NTS). D03 assesses the opportunity, risks and challenges to the re- • To outline the input assumptions and methodology used to develop purposing of the SAGE facility to separate CO2 from flue gas emissions.
conceptual options for CO2 capture at St Fergus Emerging midstream opportunities: Having a CO2 transport and storage • To provide an initial assessment of the potential re-use of the SAGE infrastructure at St Fergus opens up new ‘midstream’ opportunities. The most gas sweetening plant for CO2 capture from flue gas obvious of these are the commercial opportunity for CO2 transport and storage • To provide a conceptual design for a new build capture facility to and the production of hydrogen from natural gas. Initiating capture at St Fergus enable CO2 capture from flue gas will create technical and commercial interest in these emerging midstream areas. • To provide preliminary cost estimates for both plant options • To provide a preliminary assessment of risks and opportunities associated with capture plant development at St Fergus • To outline further work which may require to be completed in order
to progress the capture of CO2 from St Fergus
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D03 Basis of Design for St Fergus Facilities Scope of Work
3.4 Assumptions Within the boundary fence points of emission below 10kT/yr, i.e. office block boilers, flare stacks etc. have been excluded. This limits the scope of review to The assumptions detailed in this section apply to the Acorn Project under the the flue stacks for gas heaters and gas turbines. ACT ERA-NET funding package. For future Acorn project development, these Based on discussions with terminal operators, it is assumed that the current assumptions may be revised. plants at St Fergus will continue to operate as they do now for the 15-year term ACT Acorn aims to capture 200,000T/yr of CO2 from the emission sources at the of this project, and probably until 2040 or beyond. St Fergus gas terminal, transport the captured emissions through an existing pipeline for injection and sequestration in a storage location within 50km of the pipeline.
The D03 report focuses on the capture element and evaluates the feasibility of both a) the retrofitting of the existing SAGE facilities and b) a new build capture facility.
Although specific sources of CO2 will be discussed, the report will not specify which sources at which terminals will be captured to provide 200,000T/yr CO2.
Downstream Infrastructure
The choice of offshore pipeline and the connection to the pipeline has not been considered within this scope.
Data
The most recent (2015) SEPA Scottish Pollutant Release Inventory (SPRI) (SEPA, 2017) data sets are assumed as a true and accurate representation of emissions from sites across Scotland.
Exclusions
Emissions beyond the St Fergus boundary fence are excluded.
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D03 Basis of Design for St Fergus Facilities The St Fergus Gas Terminal
4.0 The St Fergus Gas Terminal
The St Fergus Gas Terminal is in North East Scotland 7km North of Peterhead, and sweetening operations to ensure the correct methane content and and circa 60km north of Aberdeen, Figure 4-1. composition of natural gas prior to National Grid Gas compression and injection into the NTS. Up to half the gas used in the UK currently flows through the St
Fergus gas terminal. It is the third largest CO2 emissions location in Scotland after Grangemouth and Mossmoran.
The site was originally developed by British Gas (now National Grid Gas). The Terminal consists of four main processing plants currently operated by Ancala, Shell, North Sea Midstream Partners (NSMP) and National Grid Gas. The Ancala, Shell and NSMP terminals receive natural gas from the Norwegian and UK sectors of the North Sea, via several pipelines.
Figure 4-2: Aerial photograph of the St Fergus Terminal (Total, 2009) Figure 4-1: St Fergus Gas Terminal and Peterhead area (Google Maps, 2017) Figure 4-2 shows an aerial photograph taken from the south east with the NSMP Gas from the North Sea is brought onshore at the St Fergus Gas Terminal. The plant in the foreground, Shell in the middle, Ancala at the top and the National terminal consists of three gas receiving plants that process and pass the gas Gas facility to the left. Figure 4-3 shows an approximate boundary for all four onto a fourth facility, National Grid Gas, connected to the National Transmission operations. System (NTS). The gas receiving plants are responsible for the gas processing
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D03 Basis of Design for St Fergus Facilities The St Fergus Gas Terminal
from the Beryl and Brae areas. The plant is more commonly referred to as the SAGE Terminal. The plant also has two other main pipelines: the Atlantic and the Britannia pipelines. The plant has capacity to supply up to 20% of UK gas demand in any one day, (Wood Mackenzie, 2017), but its throughput is now much reduced due to the decline in production from Beryl, Brae and Britannia and the end of production from Atlantic and Cromarty. Other fields connected into the SAGE system include Scott, Golden Eagle and Alvheim (Norway).
Figure 4-3: Approximate boundaries of the four operations (adapted from Google Maps, 2017) Figure 4-4: The Ancala / SAGE plant, (Apache, 2017) 4.1 The Ancala Operation The SAGE process consists of two gas sweetening trains whose main purpose This terminal was recently purchase by Ancala from Apache and was originally is to remove excess CO2 from the incoming natural gas via amine scrubbers. established and operated by ExxonMobil. The gas processing plant receives its This removal is required in order for the natural gas exported to meet the gas via the Scottish Area Gas Evacuation (SAGE) pipeline, which collects gas National Grid specification.
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D03 Basis of Design for St Fergus Facilities The St Fergus Gas Terminal
Decline in production of gas from high CO2 fields (principally Brae) has reduced 4.2 The Shell Operation the need for the gas sweetening processing facility. Consequently, one train is current shut down and its potential for future operation is unclear. The remaining The Shell plant opened in 1982 taking gas from the Brent field, via the Far North single train is still operated, although its use is expected to no longer be required Liquids and Associated Gas System (FLAGS) pipeline. FLAGS collects gas from fields including Brent, Statfjord, and Cormorant. The plant has also received gas in a few years’ time. This is because in recent years the average CO2 content within natural gas received by SAGE has continued to decline to the extent that from the Fulmar field via the Fulmar Gas pipeline and from Goldeneye via the Goldeneye pipeline. There are two processing trains at the terminal with 45 currently just circa 14,000T/yr of CO2 is being removed by the gas processing 3 3 train. million sm /d total capacity (but only 32 million sm /d wet gas modular capacity), (Shell, 2017).
Figure 4-5: SAGE terminal overview, (Apache, 2015) Figure 4-6: The Shell plant, (Shell, 2017)
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D03 Basis of Design for St Fergus Facilities The St Fergus Gas Terminal
4.3 The NSMP Operation Following cessation of production from the Frigg field in 2004 the Phase 1 processing facilities at St Fergus were decommissioned and the FUKA pipeline FUKA stands for Frigg UK Association which refers to the original development and Phase 1 reception facilities now feed the Phase 3 processing trains, with of the cross UK/Norwegian border Frigg gas field – with the 362km, 32” FUKA the FUKA pipeline, Phase 1 reception facilities and Phase 3 processing trains pipeline being constructed to transport the gas from the UK part of the Frigg field now comprising the Frigg System, which is 100% owned and operated by NSMP. to St Fergus, with a parallel pipeline constructed to transport the gas from the The FUKA system now also transports and processes gas from the West of Norwegian part of Frigg to St Fergus, the Frigg Norwegian pipeline. The Shetlands via the NSMP operated, 234 km 30” SIRGES gas pipeline. pipelines and facilities began initial operations in 1977, (NSMP, 2017). Today the FUKA system transports and processes gas for a large number of In 2001 with declining production from the Frigg field prior, the Frigg Norway key fields in the Northern North Sea, West of Shetlands, the Outer Moray Firth pipeline was reconfigured through a spur connection across the median line to and in the near future will transport and process gas from the Norwegian Sector. the Heimdal riser platform which operates as a hub for a number of Norwegian The SIRGE System Pipeline is a 234km 30" nominal bore pipeline. The system gas pipelines. The Frigg Norwegian Pipeline was then renamed Vesterled and has a nominal capacity set at 665MMsfcd. The pipeline runs from the Total in 2003 was incorporated into the Norwegian Gassled joint venture. Vesterled operated Shetland Gas Plant (SGP) at Sullom Voe on Shetland to a sub-sea tie- transports dry, sales quality gas to the NSMP St Fergus Terminal where the in on the FUKA Pipeline at the MCP01 bypass valves. The pipeline is expected Phase 2 facilities treat and meter the gas before export to the NTS. The Gassled to provide transportation services for the export of gas from the emerging West Joint Venture is the owner of the Vesterled pipeline and Phase 2 facilities at St of Shetland frontier to the UK mainland market. Fergus Gas Terminal. Gassco operates the Vesterled pipeline while NSMP operates the Phase 2 facilities, both on behalf of Gassled. The St Fergus Gas Terminal has been constructed in three phases; Phase 1 was constructed to receive and process gas from the Frigg UK pipeline before redelivery of processed gas into the NTS and came online in 1977. Phase 2 came online a year later and was essentially the same as Phase 1 but was built to receive and process gas from the Frigg Norwegian pipeline. Phase 3 was then constructed to process NGL rich gas initially from the Alwyn area (commencing production in 1987) and later also from the Bruce field (from 1993). Phase 3 consists of three parallel processing trains each of around 400 mmcsfd capacity.
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D03 Basis of Design for St Fergus Facilities The St Fergus Gas Terminal
Figure 4-8: The decommissioned Miller Gas Processing Facility, (NSMP, 2017)
Figure 4-7: The NSMP Phase 2 plant with Shell plant in the distance, (NSMP, 2017)
In the past, gas was also received via the Miller Gas System (MGS) pipeline. The Miller Field ceased production in 2007 and the receiving facilities have since been decommissioned. However, the MGS pipeline remains in place and has been preserved. Similarly, an onshore pipeline that supplied processed gas from the Miller field to SSE’s Peterhead Power Station also remains in place and is Figure 4-9: The capped end of the preserved MGS Pipeline, (NSMP, 2017) preserved. Figure 4-8 shows the decommissioned Miller Gas Processing Facility. 4.4 The National Grid Gas Operation Whilst all plant has been removed the concrete foundations and capped pipeline ends remain in place, with MGS to the left (also Figure 4-9) and the onshore The National Grid site comprises of a network of compressors, pressure vessels, pipeline just visible centre rear. pipes and valves that compress and control the flow of natural gas from the three processing plants into the NTS which transports the natural gas to the rest of Scotland via Kirriemuir in Angus and then on to Bathgate in West Lothian.
The site was originally equipped with eight gas turbine powered compressors arranged in two plants (Plants 1 and 2). One compressor has since been
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D03 Basis of Design for St Fergus Facilities The St Fergus Gas Terminal
decommissioned and two new electrically driven compressors installed in 2015 At the Ancala plant most of the emissions are also from fuel gas combustion for will eventually replace some of the gas turbine units, (National Grid, 2017). heaters. The gas sweetening emissions from the SAGE gas terminal, around 14,000T/yr, are not considered to be large enough to capture and have been not 4.5 CO2 Emission Points for Capture been included in the reported emissions.
The SEPA SPRI carbon emission data for the St Fergus Gas Terminal is shown At the National Grid plant the majority of emissions are from fuel gas combustion in Table 4-1. Industry capture potentials adapted from recent studies (Brownsort, in generators used to drive the compressors. 2016), (Pershad, 2013) have been used to calculate the captured emissions. As part of D03, Pale Blue Dot completed a visit to the NSMP plant which The 2015 data is the latest available but to avoid confusion the current operator provided greater clarity on the operation, emissions and available space for a names for each plant are shown. new capture facility and interfaces. The NSMP emissions have ranged from 35-
Name Raw CO2 Capture CO2 Quantity 45,000T/yr over the past three years. With incremental natural gas volume Quantity (T/yr) Potential (T/yr) recently secured, increased production at the plant will see emissions increase to circa 60,000T/yr. Again, almost all emissions are from fuel gas combustion Shell Plant 331,559 60.0% 198,935 for heaters with the emissions roughly split 50:50 across the two newer 17MWt Ancala Plant 135,862 67.5% 91,707 glycol heaters on Phase 2 and the two older 16.3MWt thermal oil heaters on Phase 3. National Grid Plant 59,538 67.5% 40,188
NSMP Plant 45,191 67.5% 30,504
Total 572,150 361,334
Table 4-1: CO2 Emissions and Capture Potential at St Fergus – 2015 data
For the Shell plant, almost all the emissions are associated with fuel gas combustion with eight main points of emission, two gas turbines stacks and six heater stacks. A lower capture potential is used to reflect the lack of clarity over the breakdown of emissions across the gas turbines and heaters and for a reduction in CO2 from gas sweetening.
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assumed to come from either the two gas turbines, several if not all of the six heaters or a combination of both.
• The CO2 concentration in flue gas is assumed to be 4% from the gas turbines and 9% for the heaters. • The capture design for either the repurposing of the SAGE trains or new build must include the transfer of the flue gas to the capture plant. • For now, the Reference Case does not consider emissions sources from any other source.
Figure 4-10: NSMP’s Phase 2 Heater Stacks (left) and Phase 3 Heater Stacks (right), (NSMP, 2017)
Pale Blue Dot Energy have ongoing dialogue with the operators of the operators of the three gas processing facilities at St Fergus. Discussions have indicated that existing emissions can be expected to continue well into the 2030s. Any CO capture facility has been assumed to last for 15 years once it is installed. 2
For the purposes of the ACT Acorn work, the following assumptions are made Figure 4-11: Shell plant from the NSMP plant: the two gas turbine stacks (yellow) about the magnitude of existing emissions: and two of the heater stacks (red), (NSMP, 2017)
• 200,000T/yr of CO2 is assumed straightforward to capture from the gas turbines and heaters at the Shell terminal. This is based on total emissions of 330,000T/yr, with an assumption that ~60% of this can be captured (including a 90% capture efficiency). • Thus, the Reference Case assumes the capture of 200,000T/yr of
CO2 emissions from the Shell plant starting in 2022. These are
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D03 Basis of Design for St Fergus Facilities The St Fergus Gas Terminal
NSMP have space within their fence line and potential for an “emissions gathering network” that supplies the capture plant. Sufficient land could, potentially, be made available by NSMP within their footprint for a new build capture plant including:
• • A large rectangle of land just south of the NSMP Phase 3 plant visible in Figure 4-3 and Figure 4-13. • The decommissioned and cleared Miller processing areas where concrete ground structures are retained as visible in Figure 4-8.
Figure 4-12: Shell plant stacks: the two gas turbines stacks (yellow) and four of the heater stacks (red), (Shell, 2017) 4.6 Potential Locations for a New Build Capture Plant
The ACT Acorn project seeks to evaluate the repurposing of the existing SAGE gas sweetening facility for CO2 capture whilst also assessing the option for a Figure 4-13: Available land south of the NSMP Phase 3 plant (NSMP, 2017) new build capture plant. As shown in Figure 4-3 the Shell plant is located between the SAGE facility (Ancala) and the NSMP complex, thus geographically ideally suited as the focal point for a flue gas gathering network to either head north to SAGE or south to a new build capture plant.
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5.0 Methodology
5.1 Developing the Capture Options Conceptual design and analysis will be conducted on two capture options; • Re-use of the SAGE gas sweetening plant and The methodology for evaluating the carbon capture options at the St Fergus • A new build capture facility terminal is illustrated in Figure 5-1. In addition, conceptual design for the common facilities of dehydration and compression will be completed. Capture of 200kT/yr CO2 At this stage it is intended that material developed would identify any major obstacles to either option and start to identify the key benefits and drawbacks, risks and opportunities for each option. This should enable a sensible comparison of the two options. Comparison of the two options should enable a Re-use SAGE New build Dehydration and gas sweetening capture facility compression meaningful estimation of value for money in terms of the costs of modifications, plant operating costs, design life and the risks associated with repurposing old infrastructure that is not being used for its original purpose. 5.2 Overall Design Considerations Concept design Concept design, Concept design and costing and costing and costing The development of capture options at St Fergus should take into consideration the following:
• Capture is a small part of the overall project Risks and Risks and Risks and • Enabling re-use of the existing infrastructure at low cost is more opportunities opportunities opporunities beneficial than increased efficiency
• The ability to scale up in a phased, modular manner is beneficial in Figure 5-1: Methodology for Evaluating Capture Options building out the project • Capture plant should focus on lowest cost capture rather than demonstrating state of the art designs
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The purpose of capture at St Fergus is not to invent or apply novel, first of a kind, open cycle rather than combined cycle however the composition of the gas expensive technology but to capture CO2 in the North East of Scotland and act should be similar – the temperature is likely to be lower for a combined cycle. as a gateway for CO2 sequestration in the North Sea. The gas turbine scenario represents the lowest CO2 inlet concentration.
The key element for the St Fergus terminal is to enable capture of CO2 in For gas heaters the CO2 concentration has been based on a gas boiler, which sufficient quantities to be able to demonstrate the offshore transport and is assumed to be equivalent to the gas fired heaters at St Fergus. Heaters sequestration of CO2 in the North Sea. The report will seek to answer the represent the highest concentration of CO2 possible in the inlet. following research questions: Exhaust gas recycle (EGR) processing has also been considered to increase
1. Can the SAGE gas sweetening plant capture 200,000T/yr CO2? the CO2 concentration in the flue gas to enhance the amount of CO2 captured.
2. What is the cost comparison between re-use and new capture It is assumed that this will enable flue gas inlet CO2 concentrations to be facilities? increased to 9%. 3. What are the other capture option comparison factors that are Since the amount of emissions from individual sources is not yet known the currently known? actual flue gas presented for capture is likely to have a CO2 concentration 4. What further information/work is required to support the selection somewhere between 4% and 9%; an assumption of 7.5% has been made. process? 5.4 SAGE Plant 5.3 Process Design For the SAGE gas sweetening plant, the main differences between the original The ability to repurpose the existing infrastructure to capture flue gas was design of the equipment and repurposing the units for flue gas capture, are the evaluated using process modelling software Aspen Plus. pressure and gas composition. When separating CO2 from natural gas the Flue gas concentrations assumed are as follows absorber tower is operating at ~80bar, whereas for flue gas separation the pressure will be ~1.2 bar. At the time SAGE was designed the gas to be • Gas Turbine flue gas – 4% CO2 concentration processed was predominantly methane with a CO2 concentration of ~7.5%. • Gas Heaters flue gas – 9% CO2 concentration Thus, the original design for the absorber was capable of handling CO2 • Gas Turbine with EGR – 9% CO2 concentration concentrations up to 18% (in natural gas), although the current entry • Average flue gas – 7.5% CO2 concentration specification still remains as stated at less than 7.85% (in natural gas). For gas turbines the flue gas composition has been estimated based on the The original design for the two identical units at the SAGE terminal was used to output from a combined cycle gas turbine. The gas turbines at St Fergus are assess the feasibility of using the existing trains as a capture unit. For this
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assessment, emissions are assumed to come from flue gases from the existing gas treatment at St Fergus, these emissions could come from any of the terminals and from either gas turbines or gas fired heaters. At this stage the split of emissions and the source that will be used are not known and will be determined in a later project phase.
The original design of the absorber, designed to handle CO2 concentrations of up to 18%, shows that the processing train should be very tolerant to CO2 and a good candidate for re-use. Typical flue gas CO2 concentrations are in the region of 4-9%, far below the original specification.
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6.0 Re-use of the SAGE Plant
6.1 Introduction (900,000T/yr) of CO2 removal and removal of H2S to 1 ppm, (Apache, 2015). Gas produced at the terminal is passed to the National Grid terminal for The Scottish Area Gas Evacuation (SAGE) terminal is owned by Ancala who compression into the NTS. NGLs are sent to either the Shell Mossmorran plant acquired the terminal from Apache at the end of 2016. Gas is transported to the or the BP Forties system for further processing. terminal through the 323km, 30” SAGE pipeline. Gas entering the terminal is Gas capacity is split between three processing trains; one train for the Britannia metered and processed to meet the entry specification for the national pipeline and two identical trains to handle gas from the SAGE and Atlantic and transmission system. Cromarty (A&C) pipelines. The receiving facilities for the A&C pipeline, not the pipeline itself, have been decommissioned. The Britannia train only processes gas from the Britannia pipeline and can handle up to 840 mmscfd.
The SAGE plant Block Flow Diagram (BFD) is shown in Figure 6-2. The two processing trains that serve the SAGE pipeline are identical and have a nominal capacity of 575 mmscfd. Gas received from the pipeline is metered and analysed to measure the gas composition, density and water content. Once metered the gas is dehydrated in a molecular sieve before NGLs are separated in a low temperature exchange (LTX) process. This cryogenic section of the process controls the hydrocarbon quality (hydrocarbon dew point, calorific value and Wobbe index) of the gas. Once NGLs have been removed the gas is passed
onto a “treating train” to remove acid gases, namely CO2 and H2S in order to meet the SAGE gas sales specification. At the time of writing (December 2017), only Train 1 is used, and Train 2 has been reportedly decommissioned. Ancala
have confirmed that whilst only operating one train, both remain capable of operating but that both are anticipated to be shut down in the next few years as Figure 6-1: The Souther Area Gas Evacuation (SAGE) Terminal at St Fergus gas supply from the North Sea declines. The Britannia Facilities are expected to The nominal capacity of the SAGE terminal is 1,990 mmscfd of natural gas, 5,300 tonnes/day of Natural Gas Liquids (NGLs), 2,500 tonnes/day
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continue in operation for a considerable period, and therefore have not been considered available for re-use.
The evaluation will only focus on the potential re-use of Treating Train 1 and Treating Train 2, if it is in a reusable condition. Table 6-1 indicates that the natural gas entry specification to the SAGE terminal allows for a carbon dioxide concentration of 7.85mol%. Theoretically the capture equipment could be used to capture CO2 up to a concentration of 18mol%. For the purposes of the SAGE gas entry specification, Table 6-1, “negligible” is defined as less than a concentration that would cause difficulties in transport, processing, safety or integrity of the SAGE system.
Figure 6-2: Existing SAGE Block Flow Diagram (BFD), (Apache, 2015)
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Characteristic Specification 6.2 CO2 Capture Modelling
Cricondenbar pressure Less than or equal to 105barg Process Simulation Modelling Water Content Less than 63ppm by volume The capacity of the SAGE terminal to capture CO2 has been modelled using Carbon Dioxide Content Less than 7.85mol% Aspen Plus a process modelling software, a PFD of the modelled process is
included in Figure 6-3. Two simulations were set up, one for CO2 concentrations Oxygen Content Less than 7ppm by volume typical of gas turbines and one for CO2 concentrations typical of a gas fired H S – less than or equal to 16.4ppm Sulphur Content 2 heater. The absorber sizing has been determined by available information on by volume the existing facilities and is responsible for the constrain on the throughput. The Carbonyl Sulphide (COS) Negligible incoming flue gas needs to be in contact with the solvent for long enough for the
CO2 to be captured, at high throughput the velocity in the absorber is too high Σ(C2 to C12 mol%)/(C1 mol%) Max 0.27 Min 0.19 and the CO2 will pass through without being captured. Max Inlet Pressure 172barg The simulations have assumed that there is some form of compression prior to That minimum pressure (in barg) the capture process, which boosts the flue gas pressure to 30barg this allows required to ensure that the gas delivered remains in dense phase for capture of 74,600 T/yr at a 4% CO2 concentration and 57,000 T/yr at a 9% Min Inlet Pressure until reaching that part of the gas CO2 concentration. The capture rate is lower for the higher concentration processing facilities where liquid condensation is intended because of a lower flue gas throughput despite the increase in capture efficiency. Operating near atmospheric conditions is likely to reduce the captured CO2 rate Sediments/metals Negligible to around ~10,000 T/yr. Mercaptans Negligible CO2 Capture Technology Mercury Negligible Monoethanol amine (MEA), methyl diethanol amine (MDEA) and diethanol Duodecans Negligible amine (DEA) are three commonly‐studied types of amine solvents (Kohl and Temperature Max 13°C Min 4°C Nielson 1997; Jing, Dong 1999; Aroonwilas, Chakma et al. 2003; Ali 2006). Due to the availability of chemical data, MEA was chosen in this simulation; it is also Table 6-1 SAGE Terminal Natural Gas Entry Specification 2005, (Apache, 2015) widely considered to have the fastest reaction rate and thus to be most suitable for flue gas absorption without considering proprietary capture technology.
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However, the energy consumption needed for regeneration of MEA is high and The bottoms from the low pressure tank, CO2 rick solvent, is passed to the top uninhibited solutions cause corrosion to carbon steel equipment (Kohl and of the stripping column (C3102) via a heat exchanger. The heat exchanger
Nielson 1997; Jing, Dong 1999; Tan 2005). preheats the rich CO2 solvent entering the stripper using heat recovered from the lean solvent return to the low pressure tank. Process Description
The stripper is where the CO2 is desorbed from the solvent by heating it up in A process flow diagram (PFD) for simulating the existing gas treatment train at the reboiler. The CO2 is vaporised and leaves the column at the top before being the SAGE terminal is shown in Figure 6-3. In the original design for the treatment returned to the low pressure tank for separation. The lean solvent leaves the train the received gas is let down in pressure, metered at the inlet, dehydrated bottom of the column and is recirculated back to the absorber to capture CO2, and NGLs separated in Separation Train 1 before entering Treating Train 1 before reaching the absorber heat is recovered by preheating the solvent stream (Figure 6-2). entering the stripper and the lean solvent entering the stripper is cooled. The gas enters the treatment train and is passed into the absorber (C3101). The The largest difference between the original design and post combustion capture packed column absorber enables the gas to contact an amine solution that are the pressures involved. The absorber was initially designed to be operated enters the top of the column. The CO is absorbed by the amine and leaves at 2 at elevated pressure, around 80barg, while the flue gas entering a post the bottom of the column. The treated gas leaves the absorber at the top of the combustion capture plant will be close to atmospheric. With a much lower column. In the original design this would be sweetened natural gas that would pressure the density of the gas will be much lower and the volume and therefore pass to the next stage of processing. For post-combustion capture this stream the velocity of the gas will be higher. Due to the speed at which the gas will pass would be the treated flue gas and would be vented to atmosphere. The CO rich 2 through the absorber there is a limit on how much gas can be processed which solvent, stream 4, enters a flash vessel (C3104) where any vapour present is governed by the rate at which the absorbent is able to capture the CO2. leaves the top of the vessel and can be recovered.
At the bottom of the flash vessel the CO2 rich absorbent, stream 6, passes onto a lower pressure flash vessel (C3105). The flash vessel also takes in the liquid reflux from the overhead stream and the overhead vapour from the stripper column. The overhead vapour from the low pressure tank, stream 7, is cooled before entering the reflux drum. The liquids are returned and the vapour in stream 8 contains water saturated CO2 that will be sent to dehydration and compression in the capture process, but would have been released to atmosphere or flared (if there is H2S present) in the original design.
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Figure 6-3: Process Flow Diagram of Existing Facilities
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Simulation Results 6.2.4.4 Exhaust Gas Recycling Exhaust Gas Recycling (EGR) is a process where some of the exhaust gas from 6.2.4.1 Flue Gas from Gas Turbines the gas turbine combustion is mixed with the air intake for the turbine prior to Gas turbine exhausts typically have a CO2 concentration of around 4% on a combustion. The benefit is an increase in the CO2 concentration, which makes molar basis. capture more effective. The downside is that excessive flue gas recycling can
Simulation of flue gas with 4% CO2 shows that at a total mass flow of lead to incomplete combustion and disrupt the operation of the gas turbine, for
220,000kg/hr the plant captured 8,510kg/hr of CO2, equivalent to 74,600 Tonnes EGR to be effective there needs to be an optimisation between increasing the of CO2 captured per year (T/yr). This is achieved through a single train. CO2 concentration and performance of the gas turbine. The biggest issue with EGR in relation to the Acorn project is that the gas turbines are unlikely to be 6.2.4.2 Flue Gas from Gas Heaters owned or operated by the same owner or operator as the capture plant. This For the fired heaters at the St Fergus gas terminal an assumption that the makes the commercial arrangements much more complicated around potential concentration of CO2 is 9%, on a molar basis in the exhaust gases. negative impacts on performance. The simulation for capture at 9% CO2 concentration used a flue gas feed of Papers suggest that the CO2 concentration from turbines with EGR is 9%, 50,000 kg/hr resulting in 6,510kg/hr of CO2 capture, equivalent to 57,000T/yr. (IEAGHG, 2012). By operating a gas turbine in this manner, it would be possible This is achieved through a single train. to boost the CO2 concentration from a gas turbine exhaust up to comparable 6.2.4.3 Flue Gas from Multiple Sources levels as a gas fired heater exhaust, assuming that the commercial hurdles To assess the scenario in which flue gas from multiple sources is processed (a could be overcome. combination of gas turbine and heater flue gases) at the capture plant it is Capture Capacity necessary to estimate a likely concentration of CO2. It has been assumed that the blend of flue gases has a CO2 concentration of 7.5%. This represents a blend It is likely that capture rate will be limited by the capacity of the absorber, i.e. its of emissions from the sources discussed above. On a molecular weight basis physical size and the amount of MEA that can be contacted with the gas during
7.5mol% CO2 is 11.76% by weight and therefore 1.176kg CO2 could be captured its flow though the absorber. for every 10kg flue gas. A feed of 100,000kg/hr has been assumed as possible Given that the flue gas capture will operate at just above atmospheric pressure and the maximum throughput for this case. (~1.2 bara) compared to the current high operating pressure (~78barg), the
For a feed of 100,000kg/hr, this would result in an estimated CO2 capture rate velocities in the absorber will increase by about 50 times, for the same flowrate. of 11,760kg/hr, equivalent to 103,000T/yr. Again, this is achieved through a The capture capacity of a single train at high pressure with 7.5% CO2 in natural single train. gas was, we understand, 456,000T/yr. Maintaining the same CO2 concentration
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(7.5%) in flue gas and assuming that the same residence time is required in the It may be possible to increase capture capacity, and reduce costs, by utilising a absorber, the capacity would be expected to be 50 times less, i.e. 456,000/50 proprietary solvent. or ~10,000T/yr. 6.3 Upgrading of Existing Facilities The simulations run and the Mixed Sources estimate indicate a capture potential from a single train of between 57,000T/yr and 103,000T/yr, which is limited by It has not been possible to examine the facilities during his project and the absorber capacity and the amount of MEA that is used in the system. consequently the condition of the SAGE gas sweetening plant is unknown. There is some indication that Treating Train 2 has been decommissioned
CO2 although discussions with the current owner suggested otherwise. The plant has CO2 Flue Gas CO T/yr Simulation 2 T/yr been operating for over 20 years and, given it is planned to come to the end of kg/hr kg/hr 2 1 Train its intended service shortly, it may not have received much maintenance or Trains equipment replacement. As a consequence, re-using the process equipment
Gas Turbine (4% CO2) 220,000 8,510 74,600 149,600 without any change may incur some refurbishment expense. Given that existing service is at 78barg and intended service is close to atmospheric pressure, the Gas Heaters (9% CO2) 50,000 6,510 57,000 114,000 pressure rating of the main process trains should not be an issue. Mixed Sources (7.5% CO ) 2 100,000 11,760 103,000 206,000 Flue gas absorbers emit waste gas, mainly nitrogen, to atmosphere. The (Estimate) existing natural gas process does not emit to atmosphere and therefore does Table 6-2: Simulation results for single process train modelling not have MEA emissions control equipment installed. Re-purposing the facilities There appears to be considerable uncertainty if the existing capture plant has may require the installation of new emissions control equipment, consistent with the capacity to capture 200,000T/yr CO2 from flue gas. At this stage it would current regulations/practice, to ensure that flue gases emitted to atmosphere do appear that to do so, or come close to doing so, would require both trains to be not contain any MEA. This clean up section would normally be installed on the operational and flue gas compression to around 30barg or higher. Compression top of the absorber tower, increasing its height. In this case with an existing ahead of capture is not an ideal scenario, despite the CO2 requiring compression, absorber, it may require a separate wash column to be installed. since much of the flue gas is composed of nitrogen which will be released back 6.4 Flue Gas Conditioning Pre-Capture to the atmosphere. The energy used in the compression of the nitrogen will make the process inefficient and is unlikely to eliminate the need for post capture Flue gas is assumed to be delivered at atmospheric pressure at the inlet to the compression. existing vent stacks. Increasing the pressure by using an industrial fan will allow the flue gas to be transported to the capture facility by overcoming the pressure
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drop in the ducting, flue gas cooling equipment (including the waste heat In addition to the existing facilities dehydration and compression will be required recovery and direct contact cooler) and in the absorption / water wash column. to meet the CO2 export specification. Incoming flue gas is likely to require pressure boosting, by fan for low pressures or by multistage compression for A direct contact cooler is required to reach the optimal temperature to operate high pressures, as well as dehydration since the existing facilities for gas coming the CO2 absorption process. A direct contact cooler is a packed column where onshore are assumed to remain in use for hydrocarbon treatment. water is sprayed into the flue gas before being cooled against air and recirculated to the top of the column. Some water contained in the flue gas will Until the condition of the equipment can be ascertained, and a design finalised condense requiring that some water is purged from the cooling loop for disposal. for reuse of the existing facilities there will be a massive uncertainty in the cost Some minor contaminants will be scrubbed from the flue gas in the direct contact of the design. At this stage a cost estimate is not considered a useful metric until cooler. the design and operation of the facilities are developed further. 6.5 Compression Facilities Post Capture
The existing CO2 capture facilities do not include any compression since the
CO2 captured from gas sweetening was released to atmosphere. The captured
CO2 needs to be compressed from near atmospheric conditions, once it is released from the solvent, to around 130-150barg to allow for transport and injection. Because of the high compression ratio a multistage compressor will be required with interstage cooling and liquid knockout to remove any water that may condense. New build compression facilities and the estimated cost are discussed towards the end of the next section. 6.6 Cost Estimates
At the time of writing the SAGE terminal has been in a transition period while ownership is transferred from Apache to Ancala. As a result, it has not been possible to organise a site visit to gather data on the condition of the facilities and available land.
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D03 Basis of Design for St Fergus Facilities New Build Capture Facility
7.0 New Build Capture Facility
7.1 Benefits of New Build The feed gas to the capture facility, 1,890,000 tonnes/year, will come from industrial sources at the gas terminal, namely gas turbines and fired heaters. There are some benefits associated with a new build option in comparison with The flue gas flow rate to the capture plant will be 238,600kg/hr based on 330 the re-use of the existing SAGE facilities. These could include; days/year operation.
• Being purpose built to handle the duty and specification required Typical flue gas compositions for gas turbines and fired heaters are provided in • Being located to optimise cross terminal emissions collection and Table 7-1 for the combustion of natural gas. The composition used as a basis of capture this evaluation is representative for flue gases produced by fired gas heaters. • Having space for compression and export • Being located to optimise pipeline connections Gas Fired Heaters Gas Turbines • It could be designed to suit a particular proprietary solvent Component mol % wt % mol % wt % technology • It could use an alternative capture technology Nitrogen / Argon 72.9 73.1 75.3 74.6 • The facility could be designed to be scalable Oxygen 5.0 5.7 14.0 15.7 • Minimising interaction of capture and natural gas processing
• Avoiding commercial issues such as liability, ownership etc. CO2 7.5 11.8 3.1 4.8 • Reducing energy consumption and Opex through design and energy Water 14.7 9.4 7.6 4.8 optimisation Total 100 100 100 100 7.2 Basis of Design Table 7-1: Flue Gas Composition Throughput, Feed Gas Composition and Condition It is noted that due to the higher combustion air flows used in gas turbines, the
The new build facilities at St Fergus have been designed for the annual capture CO2 is more diluted as shown in Table 7-1, which for a given CO2 capture plant
200,000 tonnes of CO2. This gives a CO2 rate of 25,252kg/hr to storage (based capacity represents an increase in the volume of flue gases being treated (by a on 330 days/year, see Section 7.2.4. factor of 2.5) and increased separation duties, leading to larger equipment costs.
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The water composition in Table 7-1 corresponds to the hot flue gas composition Plant Availability at the exhaust temperature. As a result of flue gas cooling, the water content of Assumed operational availability is 90%, equivalent to operation during 330 days the stream entering the capture plant will be lower. per year. The CO2 capture plant will be designed to avoid impact on availability The flue gas will be at atmospheric pressure and will require cooling and of the upstream gas terminal, with flue gas being diverted to existing vents boosting in pressure upstream of the CO capture plant. The capture plant 2 stacks if the CO2 capture plant is not available. operating pressure is approximately 1.1bara. High availability is not critical, but pumps, filters etc. will be duplex to allow The flue gas exhaust temperature is assumed to be at 278°C and will be cooled maintenance during normal operation. Flue gas booster fans and CO2 upstream of the CO2 capture plant. compressors will not be duplex.
Required Unit Performance Site Details
The capture plant has been designed to achieve a CO2 product purity of greater The distance from source to location of capture plant is assumed to be than 90mol% on a dry basis with a delivery pressure in the range of 130-150barg. approximately 1200m and via an existing pipeline corridor. The distance from Utilities the capture plant to the Atlantic and Cromarty reception facility is assumed to be approximately 1500m via an existing pipeline corridor. Space availability within The following site utilities are assumed to be available: the existing corridors for new pipelines needs to be verified.
• Electricity Construction Considerations • LP Steam (4bara)* • Demineralised Water St Fergus is a top tier COMAH site and so the construction will have to consider • Nitrogen the additional safety requirements, the impact of simultaneous gas plant • Instrument Air operations and construction work on the construction productivity; and the • Drains impact of plant availability, as typically only short shutdown windows are available. *It is likely that a sufficient supply of LP steam is not available, and the additional cost of a steam or other heating system will need to be considered. Once the 7.3 Plant Description source of flue gases, available waste heat in flue gas streams, and available hot The overall block flow diagram in Figure 7-1 shows the key functions / equipment, utility supplies is confirmed, this should be evaluated further. excluding the gathering ducting from multiple flue gas sources and the high-
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pressure pipeline to the Atlantic and Cromarty reception facility at the Ancala Flue gas is assumed to be delivered at atmospheric pressure at the inlet to the Terminal. existing vent stacks. Increasing the pressure by using an industrial fan will allow the flue gas to be transported to the capture facility by overcoming the pressure drop in the ducting, flue gas cooling equipment (including the waste heat recovery and direct contact cooler) and in the absorption / water wash column.
A direct contact cooler is required to reach the optimal temperature to operate
the CO2 absorption process. A direct contact cooler is a packed column where water is sprayed into the flue gas before being cooled against air and recirculated to the top of the column. Some water contained in the flue gas will condense requiring that some water is purged from the cooling loop for disposal. Some minor contaminants will be scrubbed from the flue gas in the direct contact cooler.
CO2 Capture
It is assumed that 90% of the CO2 in the flue gases is captured using a chemical
Figure 7-1: Block Flow Diagram for New Build Capture process in which CO2 is absorbed and reacts with a circulating aqueous solvent,
which is then regenerated using heat to deliver the CO2 product. Flue Gas Conditioning Once cooled the flue gas will enter a packed absorber column at near Flue gas supply to the CO2 capture facility is available at atmospheric pressure atmospheric pressure. In the column the CO2 in the gas stream is contacted with and relatively high temperature, so there is a need to cool and boost the the solvent which will chemically absorb the CO2. The treated flue gas is passed pressure of the flue gas stream. As far as practical, waste heat can be recovered to a water wash section (either incorporated at the top of the column or from the flue gas for use in the CO capture process to increase energy 2 separately) to minimise solvent losses and emissions to atmosphere. The efficiency and reduce CO2 emissions arising from solvent regeneration. treated flue gas with reduced CO2 content is then vented to atmosphere at the Flue gas conditioning is not significantly integrated with the capture technology top of the absorber / water wash column. and should be investigated at later project phases. The solvent, rich in CO2, is heated in exchange with hot lean solvent and is
pumped to a packed distillation column where absorbed CO2 is stripped from
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the solvent. The lean solvent can then be recirculated to capture CO2 from the Delivery of CO2 from the solvent regeneration system at elevated pressure is flue gas. Reboil heat for the regeneration of the solvent is provided by low beneficial in reducing compression requirements, however optimal operating pressure steam whilst overhead vapours are partially condensed by cooling pressure is typically close to atmospheric. provided by air. The CO product stream, saturated with water, but with minimal 2 7.4 Plant Design other contaminants, is separated from the condensed water stream in the reflux separator. Flue Gas Conditioning The hot lean solvent is passed to a lean-rich solvent exchanger to recover heat Flue Gas Ducting and is further cooled to the operating temperature of the absorber against air. The lean solvent passes to a tank which provides surge volume in the circuit Insulated ducting (~1200m long) will be required to transport gas from the source ahead of being pumped into the absorber column. To avoid build-up of solids a to the CO2 capture plant. The basis for the cost estimate is that this ducting is slip stream of solvent is passed through a filter. elevated and supported on individual posts rather than a pipe rack.
Periodically impurities and degradation products will require removal from the Waste Heat Recovery Unit (WHRU) solvent by thermal reclamation of a slip stream of the lean solvent. The stripper Recovering heat from the flue gas provides two main benefits; generation of low reboiler duty will be reduced during this period, so the overall duty will remain pressure steam for solvent regeneration and secondly reduction in the cooling similar. duty in the direct contact cooler. The recovery process is anticipated to be
Depending on the capture technology ultimately chosen for the capture plant supplied as packaged units comprised of: economiser, steam generator and there may be some modification to the process. There are processes where the superheater banks, steam drum, local pipework, feed water pumps, valves, lean solvent leaving the bottom of the stripper column is flashed with vapours instrumentation and control and access platforms. WHRU package units that being recompressed and introduced in the bottom of the column. The benefit of reduce the flue gas temperature to around 160-170°C would be able to produce this system is reduced duty in the reboiler and reduced steam demand at the roughly 12T/hr of superheated LP steam. Generated steam can be combined expense of additional electrical power to drive the compressor. with the LP steam utility supply, and boiler feed water can be taken from the steam condensate from the reboiler. CO2 Export Flue Gas Pressure Boost
Downstream of the capture process the CO2 will be conditioned for An industrial fan is required to increase the flue gas pressure and overcome the sequestration, with compression to 130-150barg and dehydration being required pressure drop in the ducting, waste heat recovery steam generator and direct as a minimum. contact cooler, and to reach the required absorber inlet operating pressure
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which is slightly above atmospheric pressure, typically of the order of 1.2bara. when a different type of solvent is used, the net recirculation rates are not always The power requirement of the booster fan providing 210mbar head is a useful measure to compare performances due to differences in density, heat approximately 2.3MW. capacity etc.
Flue Gas Cooling Periodic make up of the solvents is required to combat degradation, particularly in the presence of oxygen. Proprietary solvents are claimed to be more stable Flue gas at approximately 1.2bara and approximately 185°C is introduced to the and tolerant of oxygen levels in typical flue gases. The result is make up rates direct contact cooler. The cooler is a packed column with recirculation of water in the order of 0.2kg/TCO , which is potentially up to 10 times lower than MEA cooled in a fin-fan air cooler. The expected pressure drop of the flue gas should 2 make up requirements. Higher costs for proprietary solvents (including licensing be less than 50mbar. The flue gas delivered at the top of the column is water fees) compared to generic MEA should be considered before a solvent is saturated at 40°C. selected. CO2 Capture Plant There may be other characteristics that make a specific technology more Process Technology favourable. For example, a solvent that is reported to be non-aggressive to steel materials, with carbon steel potentially being considered as a material of At this stage no specific technology has been selected but a generic amine construction for the absorber system. A stripper in a process operating at 5bara process has been used, formal enquiries shall be made in future project phases to include all potential technology suppliers, potentially not limited to amine would be beneficial in reducing CO2 export compression power. based formulations but to include any other solvents. A process flowsheet and performance representative of proprietary CO2 capture chemical absorption processes and proprietary solvent formulations has been The Specific Reboiler Duty (SDR) is a widely used reference value, representing considered for sizing and equipment and estimating costs. the stripper reboiler duty required to regenerate solvent per tonne of captured
CO2. This duty is indicative of the amount of steam and overall operating costs. Operating Conditions
The typical SDR of an absorption process using 30wt% mono-ethylene amine The flue gas and the lean solvent enter the absorber at 40°C, at near
(MEA) is 3.7GJ/TCO2. Reduction in the SDR can be achieved by using more atmospheric pressure, around 1.1bara. The flue gas pressure drop across the concentrated MEA with proprietary formulations including foaming and oxidation absorber, including the water wash, is assumed to be in the range of 50mbar. inhibitor/anticorrosion additives. SDR reductions can be associated with The stripper column used for regeneration of solvent is typically 1.8 to 2bara. reductions in the solvent recirculation rate required, e.g. if MEA concentration is Depending on the selected technology some of the more novel solvents may increased. Reducing the recirculation rate also reduces the equipment size (in allow regeneration at a higher pressure, which would be beneficial in reducing particular pumps and heat exchangers) and the associated costs. However,
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downstream CO2 compression, but this has not been accounted for in the Overall cooling requirements for the CO2 capture process are similar to the proposed equipment sizing. Stripper overhead vapours are partially condensed required reboiler duty. In addition to this, flue gas cooling in the direct contact at around 35°C using air. Solvent recirculation rate for the plant capacity cooler is required. Total cooling requirements are in the order of 40MW minimum, considered will be approximately 400m3/hr. based on initial flue gas cooling in an upstream WHRU. Fin-fan air coolers are proposed to provide the cooling duty. CO2 Product Solvent Make-up and Storage CO2 for export is produced by stripping the absorbed CO2 from the solvent during the thermal regeneration process. The CO2 is absorbed selectively Solvent is regenerated and recirculated in a closed circuit. A slip stream of resulting in water saturated CO2 with purity greater than 99.9% leaving the solvent undergoes a thermal reclaiming process to avoid accumulation of salts. stripper column. The pressure of the CO2 will be the operating pressure of the Periodic make-up of solvents is required in response to degradation, particularly stripping column, around 1.5bara and around 35°C. in presence of oxygen. Proprietary solvents are claimed to be more stable and tolerant of oxygen levels in typical flue gases. The result is make-up rates in the Heating Requirements order of 0.2kg/TCO2, resulting in annual solvent requirements of about 40 Heating is required for thermal regeneration and reclaiming solvent. The reboiler tonnes per annum for the plant capacity under consideration. temperature required is about 112°C. Low pressure steam (at 4bara) is used to Due to the relatively low consumption rate, dedicated solvent tanks are not provide heat to the reboiler to regenerate the solvent. The low-pressure steam expected to be required, with concentrated solvents supplied in IBC tanks. A is condensed in the regeneration stripper reboiler and collected in a condensate solvent holding tank is included with a volume sufficient for complete drainage drum before being pumped for return to the boiler system. of the system. A drain drum is also included to hold a small proportion of the Considering an SDR of 3.0GJ/TCO2 (representative of proprietary amine based total solvent inventory from draining equipment, for pump back to the circuit or solvent formulations), the reboiler duty for the capture plant capacity under holding tank. consideration is 21MW. Waste and Effluent Solvent reclaiming also requires heating, but the duty of the regeneration Waste from the reclaimer will consist of organic and inorganic heat stable salts, stripper reboiler is reduced by an equivalent amount during the reclaiming non-volatile impurities, small amounts of solvent, high molecular weight solvent campaign. degradation products and water. The final waste product is drained to IBC tanks Cooling Requirements or tanker trucks and transported for disposal. The waste has to be treated as hazardous and incineration is the standard treatment.
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An aqueous effluent stream from the direct contact cooler will need to be CO2 Export disposed of to waste water treatment facilities. Compression Materials of Construction CO2 needs to be compressed to 150barg in a multistage compressor with There is a potential for corrosion in the presence of amine solvents, CO2 oxygen, interstage cooling and separation of condensed water. Shaft power is and any degradation products. As a result, stainless steel is assumed at this approximately 3.4MW. stage for the majority of equipment and piping (304L for absorber system The overall compressor after cooling duty is of the order of 3.7MW, which it is including direct contact cooler, 316L for stripper system including reclaiming). proposed is provided by fin-fan air coolers. The storage tank is proposed to be a clad carbon steel construction. Dehydration Areas where lower cost materials could be used should be investigated in the next stage of the project. Addition of chemical inhibitors (anticorrosion agents) Compressed CO2 is dehydrated to reduce the water content to <20ppm as per in solvent formulations may allow the use of carbon steel for parts of the flue gas specifications of commercial CO2 product. For offshore transport the presence conditioning and absorber system. of water can exacerbate corrosion problems and potentially form CO2 hydrates. A fixed solid bed adsorption process is proposed for this purpose, which can Footprint reduce water content to less than 1ppm. Alternative dehydration technologies, Several potential sites exist at St Fergus on which a new capture plant could be such as use of a recirculating tri-ethylene glycol absorption process could be located. The NSMP terminal at St Fergus has the most available land. The area appropriate, but this unit represents a relatively small proportion of the overall used for the now decommissioned Miller processing facilities is piled and has a project costs. concrete foundation that has been left in place. There is also a large open space The process consists of two vessels filled with molecular sieve adsorbent media. next to the Phase 3 gas processing facilities. One vessel is used for dehydration while the bed in the other vessel is
It is expected that CO2 product compression (compressor, air coolers, suction regenerated using a portion of the dry CO2 which is heated, passed through the drums), dehydration, (adsorption vessels, heater air cooler and separators) and bed, cooled, and any liquid water separated, before being recycled back to the storage/offloading can also be accommodated in the available area. CO2 product compressor. Once the water has been driven off the offline vessel, A layout study should be performed in subsequent project phases to verify safety the heater is switched off and the bed is cooled. distances, optimise plant footprint and identify detailed equipment location Adsorbent bed regeneration peak heat duty is estimated to be of the order of requirements. 120kW, although this is not on a continual basis.
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CO2 Product Transfer 2. Product compressor, air cooler fans and dehydration regeneration gas heater The basis for the project is that the captured CO2 will be conditioned and exported at high pressure (up to 150barg) to the Atlantic and Cromarty pipeline LP steam demand is given in Table 7-3, with operating costs estimated based reception facility at the Ancala terminal, located approximately 1500m from the on £18/T of steam. compression system, and the short transfer pipeline cost in included. T/hr £/T MW CO2 will be sent to a geological storage site in the North Sea using existing Steam CO2 offshore pipeline infrastructure, (scope not part of this cost estimate). Solvent Regeneration/Reclaiming (Note 1) 21.0 35.4 £25.3 7.5 Operating Cost Flue Gas Heat Recovery (Note 2) -7.2 -12.2 -£8.7 Operating costs are summarised in the following tables. Unit costs have been TOTAL 13.8 23.3 £16.6 calculated based on annual production of 200,000 tonnes of CO2 and 90% plant availability, resulting in a CO2 product (to storage) of 25.3T/hr. Table 7-3: LP Steam Consumption and Cost
Power demand is summarised in Table 7-2, with operating costs estimated Notes: based on £70/MWh electrical power. 1. Solvent reclaiming uses heat, but regeneration duty reduces by an
equivalent amount during reclaiming campaign MW kWh/T CO2 £/T CO2 2. Based on reducing net steam demand by installing heat recovery Flue Gas Booster Fan 2.3 92 £6.4 equipment on incoming flue gas to generate LP steam. To be confirmed once flue gas sources and temperature is known. CO2 Capture Plant Power (Note 1) 1.9 74 £5.2 It is recognised that capacity to provide this steam supply is unlikely to be CO Product Compression (Note 2) 3.7 146 £10.2 2 available, and the capital cost of a steam or other heating system may need to TOTAL 7.9 312 £21.9 be included.
Table 7-2: Electricity Consumption and Cost Solvent make-up requirement is estimated to be 40 tonnes per annum (overcoming losses of 0.2kg/TCO2). Based on assumed proprietary solvent cost Notes: of £5/kg (which will depend on supplier licence agreement etc.) the estimated
1. Air cooler fans, pumps and energy saving compressors cost is £1.0/TCO2.
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Estimated cost of operations personnel is £300,000 per year (based on sharing • CO2 dehydration package operations resources with existing plants), equivalent to £1.5/TCO2. • CO2 transfer pipeline (1500m 4” buried) • Control system / local equipment building Estimated annual maintenance costs, based on 3% of the capital cost (see the • Electrical substation / local equipment building following section), are £2 million for the CO2 plant including compression and dehydration facilities equivalent to £10/TCO2. The cost estimate includes home office FEED and detailed engineering; procurement of all major equipment and bulk materials including control and Based on the costs above, overall operating cost per unit of CO2 considering the electrical equipment; civil works and small substation / control buildings; capture plant (including waste heat recovery) and CO2 product export facilities construction works including all equipment setting, fabrication and installation of (compression and dehydration) is estimated to be £51/TCO2. piping, valves and insulation, instrument and electrical installation; and site 7.6 Capital Cost construction management.
Project Scope Methodology and Assumptions
The major process equipment is summarised in the equipment list included in The following sources and methods have been used to establish an indicative Annex 3. cost estimate:
The following scope is included: • Cost scale up in function of capacity for the CO2 capture plant based on cost estimates provided by Technology Providers for other similar • Flue gas tie-ins, valves / dampers plants. • Flue gas ducting, supports, insulation (1200m length) • Costain equipment cost data base supplemented by budget • WHRU steam generator quotations for selected major equipment and packages for similar • Flue gas booster fan plant; in-house cost estimating tool with cost estimating models for • Direct contact cooler system major equipment based on key process parameters and factors for • CO2 absorber system bulk materials, construction etc. • Water wash system • Specialist estimating software Aspen Capital Cost Estimator (ACCE) • Solvent regeneration system with major equipment cost models based on key process • Solvent reclaiming system parameters; a volumetric model for estimation of bulk material • Solvent drains system quantities for piping, instruments, electrical, civils, steelwork and • Solvent storage and make-up system insulation; and construction costs based on manhours associated
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with civils, installation of all equipment and bulk materials, plus A. HOME OFFICE ENGINEERING & PROCUREMENT SERVICES indirect costs such as equipment hire etc. A.1 FEED Manhours Cost 835 • Estimated first fill costs for solvent based on allowance for high value A.2 EPC Manhours Cost 5,179
proprietary solvent, incorporating Technology Provider’s fees. A.3 Licensor's Process Design Package 209
• Allowance for tie-ins and interconnecting ducting. A.4 Surveys 259 TOTAL - HOME OFFICE SERVICES 6,482 • Project management, engineering, and procurement services costs B. MATERIALS based on in-house estimates. Construction management costs B1 Major Equipment Cost 14,176 based on in-house estimates and norms. B2.1 Bulk Materials - Piping 5,885 • Conditioning allowances for growth based on levels of engineering B2.2 Bulk Materials - Electrical 1,304 development and any known reasons for growth to raw estimated B2.3 Bulk Materials - Control & Instrumentation 3,115 costs. B2.4 Tower Packing & First Fill Solvent / Licensor Fee 2,609 Sub Total (Equipment & Materials) 27,089 Overall, the Costain in-house estimating tools for equipment costs and factors B3 Packing, Forwarding & Transportation 3% 813 for bulk materials and construction costs have been used to supplement and TOTAL - MATERIALS 27,902 condition the ACCE cost estimate. C. CONSTRUCTION & COMMISSIONING
Utility connections have been assumed to be available close to the CO2 capture C1 Building & Civil Works 3,426 plant battery limit. Costs for any additional utility capacity where this is limited C2 Mechanical Erection, Piping Fabrication & Erection 9,130 and cannot be supplied from site utility networks are excluded. Electrical supply C3 Electrical & Instrumentation Installation 2,670 and LP steam supply is assumed to be taken from the current site and it is TOTAL - CONSTRUCTION & COMMISSIONING 15,227 D. CONSTRUCTION MANAGEMENT assumed that capacity is available. D1 Field Supervision including Commissioning 4,568 Cost of land where the plant facilities will be located is excluded. TOTAL - CONSTRUCTION MANAGEMENT 4,568 E. OTHER COSTS The impact of simultaneous construction and gas plant operations on the E1 Contingency 15% 8,127 brownfield construction productivity will need to be considered in further work. E2 Contractors Fee 10% 6,230 Summary E3 Third Party Inspection, Insurance, Client Costs 5% 3,427 TOTAL - OTHER COSTS 17,784 An indicative total project cost estimate is £72million for which a cost estimate TOTAL 71,962 summary is provided in Table 7-4. Table 7-4: Cost Estimate Summary (Thousand GBP)
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D03 Basis of Design for St Fergus Facilities Future Considerations
8.0 Future Considerations
8.1 Capture Option Selection • Commercial risks and liabilities As can be seen from this initial list of selection factors, the selection process will Assuming both capture options are technically feasible, then subsequent work be a complex mix of technical and commercial factors. can address the two options in more detail and provide the basis for a decision as to which option would be best developed in delivery of the Acorn project. 8.2 Consenting
The evaluation of the best capture solution will include consideration of the An initial consent register has been prepared for the capture plant and is following factors: provided as Annex 2. The consent register covers key terrestrial authorisations required to construct and operate the capture plant in terms of planning, • Capital and operating cost environmental and health and safety based on the current regulatory framework. • Commercial arrangements with terminal owners The project will take place on an existing Control of Major Accident Hazards • Source location of CO2 (COMAH) regulated industrial site. • Source composition • Reliability aspects Water treatment facilities are currently in place. However, it is unclear if these • Condition of existing facilities would be sufficient for the water effluent from this project and the plans for future • Design life aspects water clean-up. This will be addressed in future design work.
• Current and future capacity potential This register is reflective of the current stage of the project and therefore may • Potential for scale up not represent a comprehensive list of all permit, licences, application • Existing and future regulations notifications and consents that would be required through the full life cycle of the • Consents and permitting project. Many of these are developed and understood through design • Site access aspects development of the project. It is recommended that this register provides a basis • Design and construction period to understand the project needs from business planning to concept select stage. • Availability of key equipment This document should be subject to detailed review at each project stage gate • Capture solvent selection to allow it to be updated and brought in line with the project concept and • Impact on future third party CCS business understanding at that stage. • Stability of plant operation
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The requirement for an Environmental Impact Assessment (EIA) will be • Terminal owners position on emissions being captured out with their considered further in the ACT Acorn Project Deliverable 14 Outline EIA. boundary fence • Terminal owners position on third party emissions being captured in 8.3 Issues, Risks and Challenges their terminal The following list highlights some of the key issues, risks and challenges, of a • Significant change in emissions assumptions, based on changes in technical nature, which will need to be addressed as the project moves forwards; terminal activity and/or throughput
• The condition of the SAGE Treating Train 1 presents a risk in that 8.4 Further Technical Work the current condition of the plant is unknown Noted below are some of the key elements of further technical work required • Multiple historical owners of the SAGE plant may lead to a) lack of prior to FEED. detailed design drawings/information and b) insufficient operational expertise to inform the re-use option Further engagement is required with terminal owners to obtain additional
• Lack of clarity on whether SAGE Treating Train 2 is decommissioned information on CO2 emissions sources, including operational information
• Can the gas turbine and heater flue gas streams be amalgamated (variation in emissions per vent), CO2 compositions and potential routing for without impacting the current gas turbine and heater operations? capture and ducting. In the case of SAGE, additional information is required on
• Conformation of CO2 concentration and consistency of concentration the condition of the Treatment Trains and other operational and cost data. from different sources and terminals SAGE study & costing: A detailed study is required, building on this D03, • Having sufficient space for the footprint of a new capture facility providing an engineering study of the potential for re-use. within as close a proximity to the emission points as possible • Handling of effluent streams New build study & costing: A detailed study is required, building on this D03, • Routing of flue gas gathering network across / around existing plant providing an engineering study of a new build capture facility. • Insufficient residual energy to allow adequate dispersal of the Capture option selection: following the two studies above an analysis is required gathered flue gas at the emergency vent point at the capture facility to assess the two options and make a selection prior to FEED. • Wayleave access across the three gas processing terminals for flue Beyond technical activity a wide range of other project activity is required gas gathering ductwork and/or compressed CO2 pipeline. including; a full risk assessment to cover capture aspects; additional consenting • Emissions reporting for SEPA when being gathered within one activity; a wide range of commercial activity relating to terminal activity and; commercial entity and then processed at a second location owned integration of the findings from the capture part into the full chain project. by another commercial entity
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9.0 Conclusions
1. The study suggests that capturing ~200,000T/yr of existing emissions from St Fergus is possible, using a combination of sources, including flue gas from heaters and gas turbines. 2. Reducing emissions in the area by 200,000T/yr would make an important contribution to Scotland’s emissions reduction and open the way to further emissions reduction at St Fergus.
3. An existing gas sweetening plant has been separating CO2 from natural gas at the SAGE terminal for 20 years. Within the next few years it will no longer be required for this purpose and could become available for
separating CO2 from flue gas.
4. Potential exists to re-use the SAGE gas sweetening plant to capture CO2 from flue gas emissions, although further work is required to confirm the viability of SAGE re-use, especially regarding plant condition, capture rate and cost. 5. A new build capture plant could be built which would have the advantages of being designed for purpose, efficient, cost optimised and located to capture emissions from multiple sources. 6. More detailed technical engineering studies are required to assess the two capture alternatives, which along with other commercial, risk and regulatory factors, will enable an effective capture option selection prior to FEED.
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10.0 References
Apache. (2015, Aug). Infrastructure Access Agreement Summary 1. Retrieved Pershad, H. (2013). The costs of Carbon Capture and Storage (CCS) for UK Dec 9, 2017, from Industry - A High Level Review. http://www.apachecorp.com/Resources/Upload/file/UK/infrastructure_i Scottish Environmental Protection Agency. (2017, October 5). Scottish Pollutant nformation/SAGE/SAGE_Golden_Eagle_TPA-agreement.pdf Release Inventory. Retrieved from Scottish Environmental Protection Apache. (2015, Aug). SAGE Terminal Description. Retrieved Dec 9, 2017, from Agency: http://apps.sepa.org.uk/spripa/Search/Options.aspx http://www.apachecorp.com/Resources/Upload/file/UK/infrastructure_i ScottishPower CCS Consortium. (2010). Longannet ScottishPower CCS nformation/SAGE/SAGE_Terminal-technical.pdf Consortium Front End Engineering and Design (FEED). Apache. (2017). SAGE Photo. Retrieved Dec 9, 2017, from Apache Corp: ScottishPower CCS Consortium. (2011). UKCCS - KT - S10.2 - FEED - 001 Post http://www.apachecorp.com/Resources/Photo_gallery/UK_North_Sea. FEED Top 50 Risks. aspx?MediaItemId=416 SEPA. (2017, October 5). Scottish Pollutant Release Inventory. Retrieved from Brownsort, P. A. (2016). Reducing costs of carbon capture and storage by Scottish Environmental Protection Agency: shared used of existing pipeline - Case study of a CO2 capture cluster http://apps.sepa.org.uk/spripa/Search/Options.aspx for industry and power in Scotland. International Journal of Greenhouse Gas Control 52, 130-138. Shell. (2017). St Fergus Asset Fact Sheet. Retrieved from Shell: http://www.shell.co.uk/promos/st-fergus-gas- European Commission. (2017, October 5). The EU Emissions Trading System terminal/_jcr_content.stream/1482750728919/c225c95275df6e333e93 (EU ETS): Revision for Phase 4 (2021–2030). Retrieved from Climate 88b23159f1bc3bc4db759611d74f07e05aceda00b59c/st-fergus- Action: https://ec.europa.eu/clima/policies/ets/revision_en 021799-asset-fact-sheets.pdf IEAGHG. (2012). CO2 capture at gas fired power plants. Total. (2009). Retrieved from Offshore Europe: https://www.offshore- National Grid. (2017). 40th Anniversary Check for St Fergus. Retrieved from europe.co.uk/__novadocuments/29214 National Grid: http://nationalgridconnecting.com/40th-anniversary- Wood Mackenzie. (2017). St Fergus (SAGE). Retrieved from Wood Mackenzie: health-check-st-fergus/ https://www.woodmac.com/reports/upstream-oil-and-gas-st-fergus- NSMP. (2017). 7th December 2017 Site Visit by Pale Blue Dot Energy. sage-2710933
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D03 Basis of Design for St Fergus Facilities Annex 1 Mass and Energy Balances
Annex 1 Mass and Energy Balances
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D03 Basis of Design for St Fergus Facilities Annex 1 Mass and Energy Balances
Original Design - 18% CO2 Stream 1 2 3 4 5 6 7 8 9 10 11 Temperature °C 40 20 67 71 71 71 67 40 67 40 75 Pressure MPag 1 3 3 3 1 1 0.1 0.1 0.1 0.1 0.02 Vapor Fraction 0 1 1 0 1 0 1 1 0 0 1 Mole Flow kmol/hr 2,916 1,177 1,015 2,916 1 2,915 186 171 2,951 15 173 Mass Flow kg/hr 85,000 27,200 19,820 92,380 38 92,342 7,611 7,342 91,417 269 6,417 Volume Flow MMcuft/day 0.07 0.73 0.76 0.073 0.003 0.073 2.194 1.855 0.073 < 0.001 3.485 Enthalpy MMBtu/hr -841 -136 -72 -905 -0.3 -905 -66 -63 -900 -4 -58 Mass Flow kg/hr 38,185 0.19 18,846 0.001 18,907 0.27 trace 22,813 < 0.001 0.82 MDEA 46,740 170 43,646 0.63 43,655 384 115 44,974 269 844 H2O 9,306 1,773 367 24.4 365 7,223 7,222 158 0.53 5,573 CO2 trace < 0.001 < 0.001 < 0.001 < 0.001 H3O+ 9.30 0.04 0 0.06 trace OH- 9,935 9,904 7,904 0.14 HCO3- 0.06 0 0.22 trace CO3-2 65.7 19,568 19,507 15,569 0.27 MDEAH+ 12,353 12,339 13.5 9.9 3.6 3.6 3.6 0.002 < 0.001 0.002 CH4 4,769 4,766 3.1 2.6 0.5 0.5 0.5 < 0.001 trace < 0.001 N2 C2+ 772 771 0.8 0.6 0.2 0.2 0.2 < 0.001 trace < 0.001 Mole Fraction 0.11 2 PPM 0.05 4 PPM 0.05 12 PPM trace 0.07 86 PPB 40 PPM MDEA 0.89 0.01 0.83 0.03 0.83 0.12 0.04 0.85 1.00 0.27 H2O 0.18 0.04 0.003 0.42 0.003 0.88 0.96 0.001 807 PPM 0.73 CO2 trace trace trace trace 54 PPB H3O+ 187 PPM 877 PPB 886 PPB 1 PPM trace OH- 0.06 0.06 0.04 149 PPM HCO3- 364 PPB 373 PPB 1 PPM 4 PPB CO3-2 187 PPM 0.06 0.06 0.04 149 PPM MDEAH+ 0.65 0.76 289 PPM 0.47 77 PPM 0.001 0.001 39 PPB 51 PPB 670 PPB CH4 0.15 0.17 38 PPM 0.07 7 PPM 104 PPM 113 PPM 2 PPB 2 PPB 33 PPB N2 C2+ 0.02 0.03 9 PPM 0.02 3 PPM 40 PPM 44 PPM 1 PPB 2 PPB 24 PPB Table A1-1: Mass and Energy Balance for the Original Design of the Existing Equipment
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D03 Basis of Design for St Fergus Facilities Annex 1 Mass and Energy Balances
Gas Turbine - 4% CO2 Stream 1 2 3 4 5 6 7 8 9 10 11 Temperature °C 40 20 63 44 44 44 51 40 51 40 63 Pressure MPag 3 3 3 3 1 1 0.1 0.1 1 0.1 0.02 Vapor Frac 0 1 1 0 1 0 1 1 0 0 1 Mole Flow kmol/hr 2,916 7,586 7,446 2,864 1 2,864 204 201 2,896 2.98 242 Mass Flow kg/hr 85,000 220,000 212,429 92,571 17 92,554 8,708 8,654 93,578 54 9,678 Volume Flow MMcuft/day 0.07 4.97 5.66 0.07 0.00 0.07 2.30 2.19 0.07 < 0.001 4.70 Enthalpy MMBtu/hr -841 -116 -47 -910 -0.02 -910 -74 -74 -921 -0.80 -85 Mass Flow kg/hr
MDEA 38,185 0.85 15,425 < 0.001 15,434 0.06 trace 14,350 < 0.001 0.41
H O 46,740 989 42,310 0 42,311 190 136 42,686 53.6 675 2 CO 13,355 4,816 109 2 110 8,510 8,510 203 0.11 9,003 2 H O+ trace trace trace trace trace 3 OH- 9.30 0.03 0.03 0.03 trace
HCO - 11,687 11,682 12,238 0.03 3 CO -2 0.08 0.08 0.05 trace 3 MDEAH+ 65.7 23,017 23,008 24,102 0.06
N 185,526 185,508 18.5 12.4 6.11 6.11 6.11 0.001 trace 0.001 2 O2 21,119 21,115 3.92 2.04 1.88 1.88 1.88 0.001 trace 0.001 Mole Fraction
MDEA 0.11 952 PPB 0.05 262 PPB 0.05 2 PPM trace 0.04 93 PPB 14 PPM
H O 0.89 0.01 0.82 0.01 0.82 0.05 0.04 0.82 1.00 0.16 2 CO 0.04 0.02 865 PPM 0.09 876 PPM 0.95 0.96 0.00 807 PPM 0.85 2 H O+ trace trace trace trace 52 PPB 3 OH- 187 PPM 651 PPB 654 PPB 588 PPB trace
HCO - 0.07 0.07 0.07 155 PPM 3 CO -2 483 PPB 483 PPB 283 PPB 4 PPB 3 MDEAH+ 187 PPM 0.07 0.07 0.07 155 PPM
N 0.87 0.89 230 PPM 0.79 76 PPM 0.00 0.00 18 PPB 21 PPB 218 PPB 2 O2 0.09 0.09 43 PPM 0.11 21 PPM 288 PPM 293 PPM 9 PPB 11 PPB 108 PPB
Table A1-2: Mass and Energy Balance for Simulation of a Gas Turbine Exhaust
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D03 Basis of Design for St Fergus Facilities Annex 1 Mass and Energy Balances
Gas Boiler - 9% CO2 Stream 1 2 3 4 5 6 7 8 9 10 11 Temperature °C 40 20 59.7 66.9 67.2 67.2 67.6 40 67.6 40 74.8 Pressure MPag 3 3 3 3 1 1 0.1 0.1 0.1 0.1 0.02 Vapor Frac 0 1 1 0 1 0 1 1 0 0 1 Mole Flow kmol/hr 2,916 1,682 1,543 2,912 1 2,911 168 154 2,953 14.0 179 Mass Flow kg/hr 85,000 50,000 43,611 91,389 21 91,368 6,871 6,618 91,364 253 6,614 Volume Flow MMcuft/day 0.07 1.097 1.161 0.073 0.001 0.073 1.987 1.671 0.073 < 0.001 3.603 Enthalpy MMBtu/hr -841 -61.7 -6.53 -896 -0.06 -896 -59.4 -56.4 -900 -3.78 -59.5 Mass Flow kg/hr
MDEA 38,185 0.14 21,081 < 0.001 21,103 0 trace 23,066 < 0.001 0.86
H O 46,740 179 43,976 0.26 43,979 356 104 45,054 251.7 882 2 CO 7,197 649 207 6.54 208 6,508 6,508 157 0 5,731 2 H O+ trace < 0.001 < 0.001 < 0.001 < 0.001 3 OH- 9.30 0.05 0.05 0.06 trace
HCO - 8,791 8,780 7,775 0.13 3 CO -2 0.13 0.13 0.23 trace 3 MDEAH+ 65.7 17,314 17,292 15,313 0.25
N 40,736 40,717 18.8 13.2 5.63 5.63 5.63 0.002 < 0.001 0.002 2 O2 2,067 2,066 1.68 0.96 0.72 0.72 0.72 < 0.001 trace < 0.001 Mole Fraction
MDEA 0.11 741 PPB 0.06 3 PPM 0.06 13 PPM trace 0.07 88 PPB 40 PPM
H O 0.89 0.01 0.84 0.02 0.84 0.12 0.04 0.85 1.00 0.27 2 CO 0.10 0.01 0.00 0.22 0.00 0.88 0.96 0.00 807 PPM 0.73 2 H O+ trace trace trace trace 54 PPB 3 OH- 187 PPM 1 PPM 1 PPM 1 PPM trace
HCO - 0.05 0.05 0.04 151 PPM 3 CO -2 762 PPB 766 PPB 1 PPM 4 PPB 3 MDEAH+ 187 PPM 0.05 0.05 0.04 151 PPM
N 0.86 0.94 231 PPM 0.71 69 PPM 0.00 0.00 22 PPB 26 PPB 365 PPB 2 O2 0.04 0.04 18 PPM 0.05 8 PPM 134 PPM 147 PPM 4 PPB 5 PPB 72 PPB
Table A1-3: Mass and Energy Balance for Simulation of a Gas Boiler Exhaust
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D03 Basis of Design for St Fergus Facilities Annex 2 Consent Register
Annex 2 Consent Register
Aspect Requirement Determining body Comment
Planning permission for capture plant under the Aberdeenshire Council (AC). Town and Country Planning Act (TCPA) 1990.
Due to the small scale of the pipeline ~1km and low environmental sensitivity we assume Planning that the pipeline would not be EIA development and could either be rolled up into the Permission Planning permission for the transmission pipeline application for the capture plant or be subject to its own planning application. AC. under the Pipeline Act 1962 and TCPA 1990. Based on the assumption that the proponent is not a public gas transporter and the proponent can apply under the Gas Transporter Pipe-line Works (Environmental Impact Assessment) (Amendment) Regulations 2007. Subject to the EIA screening opinion / direction Environmental EIA for the capture plant under the Town and It may be possible to screen the capture plant out of the need for EIA particularly if the Impact Assessment AC. Country Planning (Environmental Impact existing SAGE facility is used. This will be confirmed during the next phase (EIA) Assessment) (Scotland) Regulations 2011. Environmental Permit for the operation of the Environmental The Scottish Environment capture plant under the Pollution Prevention and Application to vary an existing permit or a new permit subject to agreement with SEPA. Permit Protection Agency (SEPA). Control (Scotland) Regulations 2012. Habitats Habitats Regulations Assessment (HRA) the The competent authority will vary Regulations The need for, and level of assessment will vary depending on potential (if any) pathways Conservation (Natural Habitats, &c.) Regulations, for planning and permitting. For Screening for effects to occur on nature sites. 1994 and Habitats Regulations 2010. planning AC; for permitting SEPA. Assessment A water abstraction licence is subject to the Water Environment (Controlled Activities) (Scotland) On the assumption that there is not sufficient ‘headroom’ within the existing license it may Water abstraction SEPA. Regulations 2011 more commonly known as the also be possible to use the existing terminal operator extraction licence. Controlled Activity Regulations (CAR). Consent for Hazardous Substances under the Hazardous Planning (Hazardous Substances) (Scotland) AC. Subject to the capture technology included within the project. (e.g. Amines). Substance Consent Regulations 2015.
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D03 Basis of Design for St Fergus Facilities Annex 2 Consent Register
Aspect Requirement Determining body Comment European protected species licence (i.e. for European badgers, bats, Great Crested Newts etc.) under Scottish Natural Heritage (SNH) May be required depending on which species, if any are present within and around the Protected Species The Conservation of Habitats and Species and if applicable Marine Scotland project area and the effect of the projects upon those species present. Regulations 2010 and Habitats Regulations 2010 Building Building Regulations Approval under Building Regulations AC. Detailed design to be completed before Building Regulations application(s) can be made. (Scotland) Regulations 2017 (as amended). approval Installations covered by the Scheme are required to monitor and report their emissions. EU ETS Greenhouse Gas Emissions Trading At the end of each year they are required to surrender allowances to account for their The Greenhouse Gas Emissions EU ETS Permit Permit under the Greenhouse Gas Emissions installation’s actual emissions. They may use all or part of their allocation and have the Trading Scheme Regulations 2012. Trading Scheme Regulations 2012. flexibility to buy additional allowances or to sell any surplus allowances generated from reducing their emissions below their allocation. The Competent Authority is hosted Registration Evaluation, Authorisation and by the Health and Safety Executive Subject to the capture technology included within the project. There could be a REACH restrictions of Chemical Regulations. (HSE), working with SEPA and requirement to register as a downstream user of chemical (e.g. Amines). other government departments.
The CO2 stripping process uses chemicals such as amines that, depending upon the characteristics and the volumes stored and used in process, may be a qualifying Variation to COMAH Safety Report under the The HSE and SEPA are jointly the substance under COMAH. The CA has published guidance on the storage of bulk COMAH Control of Major Accident Hazards Regulations Competent Authority (CA) for hazardous materials. If the amine to be used falls under the COMAH regulations, the 2015. COMAH in Scotland. detailed design will need to incorporate specific consideration on secondary and tertiary containment provisions PSR require a local authority to prepare emergency plans for pipelines which have the SI 1996/825 The Pipeline Safety Regulations 1996 Pipeline operational potential to cause a major accident for pipelines conveying ‘dangerous fluids’, defined in (PSR) – Major Accident Emergency Plan and HSE. safety Schedule 2 of the Regulations. The Regulations also require a pipeline operator to notification prior to construction. establish emergency procedures for such pipelines. During the design and construction phase of a project there are key responsibilities for safety management that lie with the Client, the appointed Construction Design and The Construction (Design and Management) CDM HSE. Management Co-ordinator (CDMC), designers and the appointed principal contractor. Regulations 2015. Provided that these responsibilities are implemented in line with regulation, all relevant safety management considerations should be met.
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D03 Basis of Design for St Fergus Facilities Annex 3 Major Equipment List for Capture Facility
Annex 3 Major Equipment List for Capture Facility
Flue Gas Conditioning
No. Name Type No. Units Material Design Pressure (Barg)
1 Direct Contact Cooler Water Cooler Fin-Fan Air Cooler 1 SS 7.0
2 Flue Gas Booster Fan Centrifugal Fan 1 CS 2.0
3 Waste Heat Recovery Unit Steam Generator/Boiler 1 CS 2.0 / 7.0
4 Direct Contact Cooler Column Packed Column 1 SS 2.0
5 Direct Contact Cooler Water Pump Centrifugal Pump 2 SS 7.0
CO2 Capture
No. Name Type No. Units Material Design Pressure (Barg)
6 Lean Solvent Cooler Fin-Fan Air Cooler 1 SS 7.5
7 Stripper Reflux Condenser Fin-Fan Air Cooler 1 SS 3.5
8 Water Wash Cooler Fin-Fan Air Cooler 1 SS 7.0
9 Energy Saving Compressor Centrifugal Compressor 1 SS 3.5
10 Lean/Rich Solvent Heat Exchanger Plate and Frame Exchanger 1 SS 6.0
11 Stripper Reboiler Shell and Tube Exchanger 1 SS 3.5 / 7.0
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D03 Basis of Design for St Fergus Facilities Annex 3 Major Equipment List for Capture Facility
CO2 Capture
No. Name Type No. Units Material Design Pressure (Barg)
12 Lean Solvent Filter Cartridge Filter 2 SS 7.5
13 Absorber Column Packed Column 1 SS 2.0
14 Stripper Column Packed Column 1 SS 3.5
15 Solvent Reclaimer Package Distillation Column System 1 SS 7.5
16 Rich Solvent Pump Centrifugal Pump 2 SS 10.0
17 Lean Solvent Pump Centrifugal Pump 2 SS 6.0
18 Lean Solvent Feed Pump Centrifugal Pump 2 SS 7.5
19 Stripper Reflux Pump Centrifugal Pump 2 SS 11.0
20 Water Wash Pump Centrifugal Pump 2 SS 7.0
21 Solvent Transfer Pump Centrifugal Pump 1 SS
22 Demineralised Water Transfer Pump Centrifugal Pump 1 CS
23 Waste Water Pump Centrifugal Pump 1 SS
24 Steam Condensate Pump Centrifugal Pump 2 CS 7.0
25 Solvent Holding Tank Atmospheric Tank (cladded) 1 CS
26 Solvent Drain Tank Horizontal Vessel (underground) 1 SS
27 Stripper Reflux Separator Vertical Separator 1 SS 3.5
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D03 Basis of Design for St Fergus Facilities Annex 3 Major Equipment List for Capture Facility
CO2 Capture
No. Name Type No. Units Material Design Pressure (Barg)
28 Lean Solvent Flash Vessel Horizontal Separator 1 SS 3.5
29 Steam Condensate Drum Horizontal Vessel 1 CS 7.0
CO2 Product Export
No. Name Type No. Units Material Design Pressure (Barg)
30 Aftercooler Stage 1 Fin-Fan Air Cooler 1 SS 5
31 Aftercooler Stage 2 Fin-Fan Air Cooler 1 SS 12
32 Aftercooler Stage 3 Fin-Fan Air Cooler 1 SS 25
33 Dehydration Regen Gas Cooler Fin-Fan Air Cooler 1 SS 25
34 CO2 Compressor Reciprocating Compressor 1 SS 25
35 Dehydration Regen Gas Heater Electric Heater 1 SS 25
36 CO2 Condenser Shell and Tube Exchanger 1 CS 25
37 CO2 Pumps Centrifugal Pumps 2 CS 25
38 Refrigeration Package Ammonia Refrigeration Package 1 CS -
39 CO2 Storage Tank Cryogenic Storage Tank 1 CS 25
40 Suction Scrubber Stage 1 Vertical Separator 1 SS 5
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D03 Basis of Design for St Fergus Facilities Annex 3 Major Equipment List for Capture Facility
CO2 Product Export
No. Name Type No. Units Material Design Pressure (Barg)
41 Suction Scrubber Stage 2 Vertical Separator 1 SS 12
42 Suction Scrubber Stage 3 Vertical Separator 1 SS 25
43 Dehydration Inlet Separator Vertical Separator 1 SS 25
44 Dehydration Adsorber Vessel Molecular Sieve Vertical Vessel 2 SS 25
45 Dehydration Water Separator Vertical Separator 1 SS 25
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