Project: ACT Acorn Feasibility Study
Terms of Use
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. Pale Blue Dot Energy reserve all rights over the use of the material in connection with the development of the Acorn Project. In the event of any questions over the use of this material please contact [email protected].
Acorn
D18 Expansion Options 10196ACTC-Rep-12-01 March 2018
www.actacorn.eu
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. D18 Expansion Options Contents
Contents
Document Summary
Client Research Council of Norway & Department of Business, Energy & Industrial Strategy
Project Title Accelerating CCS Technologies: Acorn Project Title: D18 Expansion Options
Distribution: Client & Public Domain
Date of Issue: 26 March 2018
Prepared by: Sam Gomersall (Pale Blue Dot Energy), Dr Peter Brownsort (SCCS)
Approved by: Steve Murphy, ACT Acorn Project Director Amendment Record Rev Date Description Issued By Checked By Approved By V01 26/03/18 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.
The ACT Acorn consortium is led by Pale Blue Dot Energy and includes Bellona Foundation, Heriot-Watt University, Radboud University, Scottish Carbon Capture and Storage (SCCS), University of Aberdeen, University of Edinburgh and University of Liverpool.
ACT Acorn Consortium Page 3 of 80
D18 Expansion Options Contents
Table of Contents
CONTENTS ...... 3
1.0 EXECUTIVE SUMMARY ...... 8
2.0 INTRODUCTION TO ACT ACORN ...... 10
3.0 D18 SCOPE ...... 15
4.0 ACORN BUILD OUT VISION ...... 16
5.0 ACORN HYDROGEN ...... 18
6.0 CO2 UTILISATION (CCU) ...... 33
7.0 BIOENERGY ...... 38
8.0 PETERHEAD CO2 TRANSFER FACILITIES ...... 40
9.0 INTERNATIONAL CO2 SHIPPING ...... 45
10.0 CONCLUSIONS ...... 49
11.0 REFERENCES ...... 50
12.0 ANNEX 1: INTERNATIONAL CO2 SHIPPING SCENARIOS ...... 53
13.0 ANNEX 2: INTERNATIONAL SHIPPING DATA ...... 78
ACT Acorn Consortium Page 4 of 80
D18 Expansion Options Contents
Figures
FIGURE 2-1: ACT ACORN CONSORTIUM PARTNERS ...... 10 FIGURE 2-2: KEY AREAS OF INNOVATION ...... 11 FIGURE 2-3: ACT ACORN WORK BREAKDOWN STRUCTURE ...... 11 FIGURE 2-4: ACORN OUTLINE MINIMUM VIABLE DEVELOPMENT PLAN ...... 13 FIGURE 2-5: ACORN BUILD OUT SCENARIO FROM THE 2017 PCI APPLICATION ...... 14 FIGURE 4-1: SUMMARY OF ACORN'S DELIVERY,ENABLING AND BUILD OUT OPTIONS ...... 16
FIGURE 4-2: ACT ACORRN CO2 SUPPLY OPTIONS SCENARIO A ...... 17
FIGURE 4-3: ACT ACORN CO2 SUPPLY OPTIONS SCENARIO B ...... 17 FIGURE 5-1: UK ENERGY DEMAND SHOWING SEASONAL SWING ...... 19
FIGURE 5-2: BLOCK DIAGRAM OF AN SMR PLANT WITH CO2 CAPTURE ...... 30 FIGURE 5-3: UNIT COST OF HYDROGEN PRODUCTION UNIT ...... 31 FIGURE 5-4: HYDROGEN PRODUCTION UNIT CASH FLOW CHART ...... 31
FIGURE 6-1: SCOTTISH CO2 EMISSIONS AND DEMAND ...... 35
FIGURE 8-1: TANKER JETTY AT PETERHEAD PORT, WHICH COULD BE USED FOR CO2 IMPORT VIA SHIP ...... 40 FIGURE 8-2: PETERHEAD AREA ...... 40 FIGURE 8-3: PORT AND TRANSFER FACILITIES DIAGRAM ...... 41
FIGURE 8-4: CO2 TRANSFER PHASE CONDITIONS ...... 42 FIGURE 12-1: INDICATIVE ACORN BUILD-OUT SCENARIOS ...... 54 FIGURE 12-2: PETERHEAD PORT FROM THE SOUTH, TANKER JETTY CENTRE-RIGHT ...... 55 FIGURE 12-3: BLOCK DIAGRAM OF INITIAL MODEL STRUCTURE ...... 59 FIGURE 12-4: BLOCK DIAGRAM OF CAPACITY BUILD-UP MODEL ...... 60 FIGURE 12-5: PORT MODEL FOR MAXIMUM PRACTICAL THROUGHPUT ...... 62 FIGURE 12-6: EFFECT OF SHIP SIZE ON PORT THROUGHPUT CAPACITY ...... 64 FIGURE 12-7: SENSITIVITY FOR 50,000 DWT CASE ...... 66 FIGURE 12-8: SENSITIVITY FOR 30,000 DWT CASE ...... 66 FIGURE 12-9: SENSITIVITY FOR 10,000 DWT ...... 67
ACT Acorn Consortium Page 5 of 80
D18 Expansion Options Contents
FIGURE 12-10: BUFFER CAPACITY REQUIRED WITH INCREASING DELAY BETWEEN SHIP ARRIVALS ...... 69 FIGURE 12-11: SUPPLY MODEL FOR SINGLE EXPORT POINT SHIPPING SCENARIO, 50,000 DWT SHIPS, CARGO AT -50°C ...... 71 FIGURE 12-12: CAPACITY BUILD-UP MODEL EXAMPLE FOR 10MT/YR WITH 50,000 AND 2 OFFLOAD PUMPS ...... 74
Tables
TABLE 2-1:ACT ACORN MILESTONES AND DELIVERABLES ...... 12 TABLE 5-1: KEY ASPECTS OF ELECTRIFICATION AND DECARBONISED GAS ...... 19 TABLE 5-2: CAUTIOUS SCENARIO ...... 23 TABLE 5-3: AMBITIOUS SCENARIO ...... 24 TABLE 5-4: COMPARISON OF KEY HYDROGEN PROJECTS ...... 26 TABLE 5-5: NATIONAL GAS TRANSMISSION SYSTEM GAS QUALITY SPECIFICATION (1996) ...... 28 TABLE 5-6: LIFE CYCLE COST OF HYDROGEN PRODUCTION UNIT, OPEX OVER 20 YEARS ...... 31 TABLE 5-7: HYDROGEN PRICE SENSISTIVITY ...... 32 TABLE 6-1: DIFFERENCES BETWEEN THE UK AND THE USA WITH RESPECT TO EOR ...... 36 TABLE 8-1: CAPEX COSTS ...... 44 TABLE 8-2: OPEX COSTS ...... 44 TABLE 9-1: BASE CASE MODEL RESULTS; MAXIMUM CAPACITY FOR DIFFERENT SHIP SIZES ...... 45 TABLE 12-1: BASE CASE MODEL RESULTS; MAXIMUM CAPACITY FOR DIFFERENT SHIP SIZES ...... 53
TABLE 12-2: ESTIMATED MAXIMUM CO2 THROUGHPUT CAPACITY FOR PETERHEAD PORT ...... 64 TABLE 12-3: SENSITIVITY TO VARIANCE OF INPUTS, 50,000 DWT CASE ...... 65 TABLE 12-4: POSSIBLE PROS AND CONS OF BUFFER STORAGE ...... 69
TABLE 12-5: INDICATIVE CO2 SUPPLY POTENTIAL OF NORTH SEA EXPORT HUB ...... 70 TABLE 12-6: NUMBER OF SHIPS IN SINGLE EXPORT POINT SCENARIO, VARYING SHIP SIZE AND CARGO TEMPERATURE ...... 72 TABLE 12-7: TWO EXPORT POINT SCENARIO – KEY INPUTS AND OUTPUTS...... 72 TABLE 12-8: NUMBER OF SHIPS AND OFFLOAD PUMPS FROM CAPACITY BUILD-UP MODEL ...... 75 TABLE 12-9: OFFLOAD FREQUENCY AND NUMBER OF PUMPS FROM CAPACITY BUILD-UP MODEL ...... 75 TABLE 12-10: SPECIFIC FUEL CONSUMPTION ESTIMATES FOR BUILD-UP SCENARIOS ...... 76
ACT Acorn Consortium Page 6 of 80
D18 Expansion Options Contents
TABLE 13-1: BASIC SHIP AND EXPORT DATA ...... 78 TABLE 13-2: SHIP FUEL CONSUMPTION – LARGE SHIP ...... 78 TABLE 13-3: SHIP FUEL CONSUMPTION – SMALL SHIP ...... 79 TABLE 13-4: GENERAL PORT DATA ...... 79 TABLE 13-5: TANKER JETTY DATA ...... 79
TABLE 13-6: CO2 DENSITY ...... 80 TABLE 13-7: SELECTED MODEL INPUT VARIABLES ...... 80
ACT Acorn Consortium Page 7 of 80
D18 Expansion Options Executive Summary
1.0 Executive Summary
Due to its location, existing natural gas hub and pipeline connections, St Fergus St Fergus will be a key UK Carbon Capture & Storage will be one of three or four key UK coastal hub locations for CCS. (CCS) hub location. The initial capture volumes from St Fergus are intended to initiate the Acorn project. However, the real opportunity lies in the build-out enabled by the Acorn enables the production of hydrogen at St capacity of the already installed infrastructure and the new decarbonisation Fergus, which can help decarbonise UK heat demand. opportunities which the expansion enables. Acorn enables the potential for hydrogen manufacture at St Fergus as an initial St Fergus is the best location in the UK to initiate step in decarbonising gas in the UK. Natural gas would be used in Steam hydrogen production by decarbonising natural gas. Methane Reformers to produce hydrogen whist capturing the CO2. Hydrogen can then be exported in the gas transmission system or used locally, whilst the
CO2 can be imported via Peterhead Port and CO2 is transported and stored offshore. St Fergus is the best location in the UK transferred to St Fergus in liquid phase through a new to initiate hydrogen production by decarbonising natural gas. This is because it is both an important natural gas import facility, and lies close to significant CO purpose-built pipeline. 2 storage facilities, with three redundant but re-usable offshore pipelines.
Peterhead Port could import up to 16MT/yr CO2 by 406 Details are provided for importing CO2 via Peterhead Port and transferring it by pipeline via Peterhead Power Station to St Fergus in a new line designed for ship movements from European ports. For import carrying liquid phase CO at ~120bar. The power station is included to provide quantities in the range of 5 to 10MT/yr, a fleet of three 2 land for facilities, access to waste heat for warming the imported CO2 and or four vessels is required. provision of power and utilities.
Feeder 10 provides an existing pipeline to enable Peterhead Port has ample capacity for the import quantities envisaged for early build-out phases and a maximum practical capacity of 16.2MT/yr. effective decarbonisation of industrial emissions at Grangemouth. For import quantities in the range of 5 to 10MT/yr, a fleet of three or four tankers of 30,000 to 50,000 deadweight tonnage (equivalent to 24,000 to 40,000 T CO2)
ACT Acorn Consortium Page 8 of 80
D18 Expansion Options Executive Summary
size will be required to service routes from CO2 export hubs within the North Sea area.
CO2 supply via Feeder 10 was analysed in ACT Acorn Deliverable 17 (D17).
This confirmed that Feeder 10 was a viable route by which CO2 emissions from industrial sources at Grangemouth could be transported to St Fergus.
The Grangemouth industrial cluster presents the best location in Scotland for developing Carbon Capture & Utilisation (CCU) opportunities, with the potential link to higher volume CO2 capture and transport through Feeder 10 to the Acorn project. Given its location and site-based constraints it is unlikely that St Fergus will be a suitable site on which to develop commercial scale CCU projects.
The opportunities for physical linkage of bioenergy projects with the Acorn project are limited, but considerable opportunity exists for development of synergies and the development of bioenergy as part of the integrated energy mix, which includes consideration of CO2 emissions and new energy vectors such as hydrogen.
ACT Acorn Consortium Page 9 of 80
D18 Expansion Options Introduction to ACT Acorn
2.0 Introduction to ACT Acorn
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:
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.
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.
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
Identify other potential locations for CCS hubs around the North Sea regions and develop policy recommendations to protect relevant infrastructure from
premature decommissioning and for the future ownership of potential CO2 Figure 2-1: ACT Acorn consortium partners stores.
ACT Acorn Consortium Page 10 of 80
D18 Expansion Options Introduction to ACT Acorn
Engage with CCS and low carbon economy stakeholders in Europe and The project activity has been organised into 6 work packages as illustrated in worldwide to disseminate the lessons from the project and encourage Figure 2-3. Specific areas being addressed include; regional CO2 emissions; St replication. Fergus capture plant concept; CO2 storage site assessments and development plans; reservoir CO flow modelling, geomechanics; CCS policy development; As a new and emerging industry, the current state of the art for CCS lags that of 2 infrastructure re-use; lifecycle analysis; environmental impact; economic other more mature industries. Maturity improvements are required in the modelling; FEED and development plans; and build out growth assessment. application of technology, the commercial structure of projects, the scope of each development and the policy framework. CCS projects themselves have The project will be delivered over a 19-month period, concluding on the 28th also been considered as standalone ventures with reluctance to really share February 2019. During that time, it will create and publish 21 items known as learnings and co-operate. Inaccurate assumptions of who the key industrial Deliverables. Collectively these will provide a platform for industry, local players should be may also have held CCS back. partnerships and government to move the project forward in subsequent phases. It will be driven by business case logic and inform the development of The key areas of innovation in which the project will seek insights are UK and European policy around infrastructure preservation. The deliverables summarised in Figure 2-2. are listed in Table 2-1.
Figure 2-2: Key areas of innovation
Figure 2-3: ACT Acorn work breakdown structure
ACT Acorn Consortium Page 11 of 80
D18 Expansion Options Introduction to ACT Acorn
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
ACT Acorn Consortium Page 12 of 80
D18 Expansion Options Introduction to ACT Acorn
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
ACT Acorn Consortium Page 13 of 80
D18 Expansion Options Introduction to ACT Acorn
A successful project will then drive further growth and incremental development as and when CCS becomes more commercially viable in the UK, thus minimising any potential regret costs should CCS not be adopted more widely.
This 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.
Acorn is being developed by Pale Blue Dot Energy affiliate, CO2DeepStore. Figure 2-5: Acorn build out scenario from the 2017 PCI application
ACT Acorn Consortium Page 14 of 80
D18 Expansion Options D18 Scope
3.0 D18 Scope
3.1 Purpose 3.3 Statement of Assumptions
The purpose of the ACT Acorn Expansion Options (D18) report is to develop The assumptions detailed in this section apply to the Acorn Project under the and articulate the vision and opportunities for the build out of the Acorn project, ACT ERA-NET funding package. For future Acorn project development, these including ship import, hydrogen, bioenergy and CO2 utilisation. assumptions may be revised. 3.2 Scope Alignment with previous work • To align with the Committee on Climate Change’s Central Scenario The scope of deliverable D18 includes: decarbonisation pathway as far as possible, capture from bioenergy • Describing a vision for the build out of Acorn and the opportunities is assumed to begin no earlier than 2035 and hydrogen for transport this creates no earlier than 2030. • Highlighting the commercial benefits and low carbon industrial • Potential sources and build out of CO2 emissions have been opportunities which a Carbon Capture & Storage (CCS) hub at St developed to align with a subset of Scenario A in the UK East Coast Fergus creates Carbon Capture & Storage (CCS) Study: the macroeconomic case • Articulate further work required to develop the build out opportunities for the UK work (Summit Power, 2017) and the CO2 SAPLING PCI • Describing the potential for hydrogen production from natural gas bid (Pale Blue Dot Energy, 2017). with CCS at St Fergus and outlining the required facilities • It is assumed that CO2 from Teesside will be shipped to Peterhead • Considering the potential for CO2 utilisation (CCU) rather than piped and that the shipping will be a short-term solution • Describing the potential for bioenergy facilities with CCS ahead of a store being developed nearer Teesside. • Developing the concept for Peterhead harbour ship import/export This deliverable has considered the ACT Acorn Feeder 10 (D17) report and facilities for CO2 and the Peterhead to St Fergus CO2 transfer assumes that Feeder 10 can be made available to transport CO2 from Central facilities Scotland to St Fergus.
ACT Acorn Consortium Page 15 of 80
D18 Expansion Options Acorn Build Out Vision
4.0 Acorn Build Out Vision
The initial capture volumes from St Fergus are intended to initiate the Acorn project, but the potential opportunity lies in build out created by capacity in the installed infrastructure and the new decarbonisation opportunities this build out enables.
St Fergus will be a key UK CCS hub location
As a result of its location and existing role as a natural gas hub, St Fergus will be one of three or four coastal locations in the UK where CO2 from multiple sources will be delivered and from which CO2 will be transported offshore in one or more pipelines for permanent storage.
The ACT Acorn CO2 Supply Options (D02) report provided a view of two CO2 supply profiles through the St Fergus hub. These are shown in Figure 4-2 and Figure 4-3.
Figure 4-1: Summary of Acorn's delivery,enabling and build out options
ACT Acorn Consortium Page 16 of 80
D18 Expansion Options Acorn Build Out Vision
Scenario A The capacity of the offshore infrastructure provides for ~5MT/yr through the Atlantic pipeline and up to 16MT/yr if all three available pipelines form St Fergus were re-used.
ACT Acorn Deliverable D17 provides a view as to the potential re-use of Feeder
10 to transport CO2 from the Central Belt to St Fergus, thus enabling decarbonisation of the Grangemouth region, including potential development of projects such as the Caledonia Clean Energy Project (CCEP), decarbonisation of the Ineos petrochemical facility at Grangemouth and the ExxonMobil and Shell facilities at Mossmoran. Grangemouth and Mossmoran and the largest emissions locations in Scotland.
This report discusses some of the other potential build out opportunities, including the potential for hydrogen manufacture at St Fergus as an initial step
in developing decarbonised gas in the UK. Natural gas would be used in Steam Figure 4-2: ACT Acorrn CO2 Supply Options Scenario A Methane Reformers to produce hydrogen whist capturing the CO2. Hydrogen Scenario B can then be exported in the gas transmission system or used locally, whilst the CO2 is transported and stored.
Another key expansion opportunity is the import of CO2 into Peterhead Port via ship for onshore pipeline transportation to St Fergus and subsequent pipeline transport and storage offshore. Development of such facilities would enable the
UK/Scotland to store CO2 from other regions/countries.
As well as enabling Scottish decarbonisation and wider UK decarbonisation, the opportunities created by build-out are significant and include;
• O&G supply chain opportunities • Development of a leading hydrogen capability • Development of a leading CCS capability
• International CO2 storage services
Figure 4-3: ACT Acorn CO2 Supply Options Scenario B The build out opportunities are discussed further in this report.
ACT Acorn Consortium Page 17 of 80
D18 Expansion Options Acorn Hydrogen
5.0 Acorn Hydrogen
5.1 Summary 5.2 Hydrogen Background
The Acorn hydrogen concept involves build out using the Acorn CCUS project Hydrogen is an energy vector of increasing importance during the transition into as the basis to enable production of hydrogen from natural gas with CCS at St a low carbon world. It can be produced in a wide range of ways, it acts as an Fergus using steam methane reformation. The project has similarities to those energy carrier, and its energy can be used in many ways. The manufacture of described at Leeds H21 and the Liverpool-Manchester HyNet (Northern Gas hydrogen by the electrolysis of water provides a storage medium for surplus Networks, 2016) and (Cadent, 2017). electricity as an alternative to batteries. The use of hydrogen in fuel cells provides a power source for transport vehicles and industrial applications. Decarbonising natural gas to produce hydrogen, which is then transported in the Hydrogen has the benefit of creating no carbon emissions at the point of use. gas grid, has the potential to effectively decarbonise heat in the UK and enable Hydrogen vehicles therefore, emit nothing but water. widespread use of hydrogen for decarbonising transport and industry. Hydrogen blending with natural gas requires changes to the gas specification, and these In the UK, gas provides three times as much energy as electricity, (National specifications are the subject of current study (DNV GL, Working Paper). Grid, 2017). Currently, 80% of UK gas supply is used for domestic and industrial Following this a blend of 10-20% hydrogen by volume with methane could be heating with the remaining 20% being used for power generation. Decarbonising transported using the existing gas grid. heat in the UK is essential to meet the 2050 climate change targets laid out in the 2008 Climate Change Act and the UK’s subsequent signature of the Paris Blending hydrogen into the gas grid is a lower cost, more straightforward way to Accord, which, along with other global signatories, aims to keep global average start the decarbonisation than a 100% hydrogen conversion. temperature rise below 2°C. Blending 10% hydrogen by volume at St Fergus would have a larger In the UK the considerable seasonal swing in heat demand is illustrated in Figure environmental benefit than converting the Leeds area gas grid to 100% 5-1 (Wilson, 2016), currently provided by the seasonal flexibility of gas supply. hydrogen. In winter peak heat (i.e. gas) demand is four times peak electricity demand. This St Fergus is a cost-effective place to produce hydrogen from gas. The cost of is further compounded by considerable daily swing in heat demand, i.e. clean hydrogen is lower for both Acorn scenarios than the other hydrogen domestic heating times set for early morning and evening. projects currently being considered for the UK.
ACT Acorn Consortium Page 18 of 80
D18 Expansion Options Acorn Hydrogen
regional basis. The CO2 would be transported offshore for permanent sequestration.
Whilst a full analysis of the relative merits and challenges of electrification vs decarbonised gas is beyond the scope of this report, a summary of key aspects may be useful;
Electrification Decarbonised Gas
Merits Potential to phase out use of Continued use of the low- natural gas, if power generation pressure gas grid assets allowed it including polyethylene pipes. Gas grid itself acts as an energy store
Challenges Construction of sufficient Construction of sufficient generation facilities hydrogen production facilities Figure 5-1: UK Energy demand showing seasonal swing Supply of seasonal demand Decarbonising hydrogen supply There are two extremes in the continuum of options for decarbonising heat; would require a generation and grid capacity five times current. Hydrogen storage facilities electrification or decarbonised gas. Of course, a mix of these two options is Decarbonising electricity supply possible. National Grid have developed a set of Future Energy Scenarios which Electrical energy storage facilities outline possible future energy supply and demand and included within these are Grid addition and re-enforcement variants of the electrification and decarbonised gas options. Likewise, the UK required Governments Clean Growth Strategy (UK Government, 2017) outlines Table 5-1: Key aspects of electrification and decarbonised gas scenarios which include electrification and decarbonised gas. It is sufficient to conclude that if we are to meet our emissions reduction To displace natural gas in the gas grid it is likely that hydrogen would be obligations, then decarbonised gas is likely to form a part, probably a significant manufactured by the process of steam methane reforming natural gas. In this part, of the future energy mix. process natural gas is combined with water in the form of steam, to produce hydrogen and CO2. The hydrogen could initially be blended with natural gas in The matters of decarbonised gas and CCS are also addressed in the UK the gas grid, in order to start the decarbonisation process. Subsequently it may Government’s Clean Growth Strategy, the Scottish Government’s Energy be possible to transfer entire sections of the gas grid to 100% hydrogen, on a Strategy (Scottish Government, 2017) and the Scottish Governments Climate
ACT Acorn Consortium Page 19 of 80
D18 Expansion Options Acorn Hydrogen
Change Plan (Scottish Government, 2017) These are broadly supportive of The study concluded that: decarbonised gas and CCS, whilst recognising that considerable policy • The Leeds gas network has the correct capacity for such a development is required in these and other energy and climate change related conversion areas. • It can be converted incrementally with minimal disruption to A report by KPMG (KPMG, 2016) also considers four future energy scenarios customers and the role of decarbonised gas and CCS. • Minimal new energy infrastructure will be required compared to alternatives 5.3 Analogue Projects • The existing heat demand for Leeds can be met by SMRs and salt In addition to UK-wide studies and scenarios, a number of significant regional cavern storage using existing proven technology studies and trials have been completed in the UK looking at the potential for The project configuration involves four 250MW SMRs at Teesside, with a net decarbonising gas using steam methane reformers with CCS to produce output of 730MW, 162,000T/yr of hydrogen and 1.5MT/yr CO2. Intraday storage hydrogen. These include the Leeds City Gate H21 project led by Northern Gas and inter-seasonal storage would be provided by salt caverns. A new hydrogen Networks, the Liverpool Manchester HyNet led by Cadent and various project transmission system will connect the Teesside SMRs and salt caverns to Leeds. trials and studies led by SGN. It is interesting to note that this activity has been The existing medium pressure (MP) and low pressure (LP) gas distribution led by the regional gas network operators, who are driving the long term thinking networks have sufficient capacity to convert to 100% hydrogen with relatively about the future of the UK gas network. A short summary of each is provided minor upgrades. The network could be segmented and converted from natural below; gas to hydrogen over a 3-year period. Hydrogen appliances and equipment can 5.3.1 Leeds City Gate hydrogen project (H21) be developed. A cost breakdown is included in Section 5.6.
The H21 Leeds City Gate project was a study with the aim of determining the 5.3.2 Liverpool Manchester hydrogen cluster (HyNet) feasibility, from both a technical and economic viewpoint, of converting the entire The Liverpool-Manchester Hydrogen Cluster or HyNet project (Cadent, 2017) existing natural gas network in Leeds, one of the largest UK cities, to 100% highlighted that the characteristics required of a deliverable, cost effective, hydrogen. The project was designed to minimise disruption for existing hydrogen conversion project are; customers and to deliver heat at the same cost as natural gas, (Northern Gas • Low cost, low risk low carbon hydrogen production Networks, 2016). • Minimum disruption to customers
ACT Acorn Consortium Page 20 of 80
D18 Expansion Options Acorn Hydrogen
• The facility to match hydrogen production to network demand, both 5.3.3 Hydrogen active experimentation on a seasonal and daily basis, at low cost HyDeploy: National Grid and Northern Gas Networks are conducting trials The project considered the gas distribution network area around Liverpool and with injection of up to 20% hydrogen into a test grid at Keele University. The Manchester, based upon the concept of; project is seeking to assess the technical and non-technical implications of such • Injecting hydrogen into the natural gas distribution network to the an approach. Current gas grid specification is for hydrogen to be less than maximum possible level without requiring changes to gas appliances 0.1%vol. (National Grid, 2017) thus reducing the carbon intensity of the gas distribution network H100: Network operator SGN has been involved in developing studies and supplying a population of around five million; trials to better understand the issues associated with blended hydrogen and a • Converting a tranche of industrial plants to high purity hydrogen to full hydrogen composition in the gas grid. SGN Oban involved trialling different provide a large base-load demand for low carbon hydrogen thus gas compositions within the constrained gas network of Oban. SGN’s current delivering major CO2 reduction for a tranche of industry, which has H100 project is designed to assess the technical and commercial viability of a no viable alternative means of decarbonisation; 100% hydrogen network including demonstrating that hydrogen can be • Avoiding the need for expensive salt cavern storage by using a range distributed safely and reliably. The objectives of this project are to; evaluate the of methods to manage fluctuations in domestic demand; suitability of sites and requirements for a 100% hydrogen demonstration project; • Creating CCS infrastructure as an integral part of the project to select the most practical and cost-effective site for development; to complete enable a more extensive, subsequent decarbonisation of the gas the initial design of the site; and carry out on site or off-site testing of aspects network; and supporting the quantification of risk. Three sites in Scotland are currently being • Locating SMRs to minimise the costs of hydrogen transport, CO2 evaluated for the trial. (SGN, 2017) transport and natural gas supply.
The project configuration involves three 260MW SMRs in the Cheshire area, 5.4 Acorn Hydrogen Concept with a net output of 580MW H in the summers and 760MW H during winter 2 2 The Acorn hydrogen concept involves build out using the Acorn CCS project as months. The project would create approximately 1.0 MT/yr CO . Which is 2 the basis to enable production of hydrogen from natural gas with CCS at St planned to be stored in the depleted Hamilton gas field in the East Irish Sea. Fergus using steam methane reformation. The project has similarities to those This is an excellent site for CO sequestration; it is 25km from the shore, has a 2 described for H21 and HyNet. capacity of approximately 125MT and has secure seals and containment features (Pale Blue Dot Energy & Axis Well Technologies, 2016). St Fergus is a remote location and might not be of great interest to traditional industry, however hydrogen generation in the form of steam methane
ACT Acorn Consortium Page 21 of 80
D18 Expansion Options Acorn Hydrogen
reformation (SMR) would be ideally located at St Fergus. An SMR requires Cautious Hydrogen Scenario: In this scenario two phases of hydrogen natural gas as a feedstock. If the hydrogen generated is to be low-carbon then production, using SMR have been assumed. Each Phase of SMR plant consists the plant needs to capture and sequester the CO produced as a by-product. 2 of two 250MW units each producing ~0.5MT/yr of CO2 emissions. Assuming the The co-location of gas import terminal and CO2 storage infrastructure make St current rate of natural gas coming ashore at St Fergus (currently around 70M Fergus an ideal location to produce large scale volumes of hydrogen. Movement Sm3 per day) the first phase of SMR would be capable of supplying the NTS towards hydrogen as an energy vector is anticipated to be phased and would with ~5% hydrogen by volume of gas from St Fergus. The addition of 5% likely begin by blending hydrogen into methane in the existing gas grid. hydrogen into the grid in 2030 is assumed to be a part of a UK initiative to begin
Currently the limit of hydrogen in the UK NTS (National Transmission System) decarbonising the grid using hydrogen and storing the CO2 offshore. is less than 0.1% on a molar basis, however, as per the current grid specification The second phase of hydrogen generation could either increase hydrogen in other countries, e.g. Germany, there is potential to increase this to ~10% content to 10% or could supply the energy needs of Aberdeen and Moray if they before the Wobbe index of the gas is altered significantly. This change would were converted to 100% hydrogen. require the regulations which control the current gas specification to be changed. Work on this is already underway supported by the ‘active experimentation’ Ambitious Hydrogen Scenario: In this scenario four phases of described above and largely led by the UK Government Department of Business hydrogen production, using SMR have been assumed. Applying an accelerated Energy and Industrial Strategy (BEIS), the gas distribution companies and build programme compared to the Cautious Scenario, Phases 1 and 2 are the National Grid. same configuration as the Cautious Scenario but occur in 2025 and 2030 (rather than 2030 and 2040). Phase 1 provides 5% hydrogen by volume from St Fergus 5.5 Acorn Hydrogen Scenarios into the NTS and Phase 2 increases this to 10%.
Whilst the volumes and phasing of hydrogen production at St Fergus are Phase 3, implemented by 2035 with a total of eight SMRs, increases the uncertain, two scenarios have been considered which are representative of proportion of hydrogen being blended into the grid to 20% by volume from St different levels of ambition in the hydrogen pathway. Fergus. This scenario assumes that the grid specification is increased to allow 20% hydrogen by volume. • The Cautious Hydrogen Scenario involves a phased approach of 5% and then 10% hydrogen blended into the gas at St Fergus over Phase 4, provides sufficient additional hydrogen to transition the gas grid to a relatively long period. 100% hydrogen in order to supply the gas based energy needs of Aberdeen and • The Ambitious Hydrogen Scenario involves an accelerated Moray. In this phase 32% of St Fergus gas is converted to hydrogen using a blending of hydrogen to higher levels and full gas to hydrogen total of thirteen SMRs. Due to the lower energy density of hydrogen by volume transition for Aberdeen and Moray. compared to natural gas, this equates to 10% of gas from St Fergus by energy.
ACT Acorn Consortium Page 22 of 80
D18 Expansion Options Acorn Hydrogen
In the Ambitious scenario, if the gas grid specification for hydrogen was more infrastructure, suitable for 100% hydrogen. This infrastructure has not been than 20% by volume, it would be possible to export more hydrogen for use in considered further in this study. other parts of Scotland, or to adjust the phasing to provide 100% hydrogen earlier than described. It is likely that export of 100% hydrogen beyond the Aberdeen and Moray regions, would require new high-pressure gas pipeline
Natural gas rate at Hydrogen SMRs Hydrogen rate CO2 Phase Year Scenario St Fergus energy (250MW each) MSm3/d MT/yr MSm3/d TWh/yr
5% of St Fergus gas by Phase 1 2030 2 70 3.6 4.4 1.1 volume
10% of St Fergus gas Phase 2 2040 4 70 7.5 9.2 2.2 by volume
Table 5-2: Cautious scenario
ACT Acorn Consortium Page 23 of 80
D18 Expansion Options Acorn Hydrogen
Natural gas rate at Hydrogen SMRs Hydrogen rate CO2 Phase Year Scenario St Fergus energy (250MW each) MSm3/d MT/yr MSm3/d TWh/yr
5% of St Fergus gas by Phase 1 2025 2 70 3.6 4.4 1.1 volume
10% of St Fergus gas Phase 2 2030 4 70 7.5 9.2 2.2 by volume
20% of St Fergus gas Phase 3 2035 8 70 15 18.4 4.4 by volume
32% of St Fergus gas Phase 4 2040 by volume (10% by 13 70 23 28.2 6.8 energy)
Table 5-3: Ambitious scenario
ACT Acorn Consortium Page 24 of 80
D18 Expansion Options Acorn Hydrogen
5.5.1 Cost Estimate
The Leeds H21 project is a close analogue to the Acorn plan for hydrogen generation by SMR. The H21 project looks at using gas from the NTS to feed the SMRs with CO2 being captured from the flue gas stack for storage underground. The report from the H21 Leeds Citygate project gives a capital expenditure (Capex) of £395million for four 256MW SMR units. This gives a cost of £98.75million per unit, (Northern Gas Networks, 2016).
The Liverpool – Manchester HyNet project by Cadent also looks at using SMR with CO2 capture to provide decarbonised hydrogen. The project proposes that three 260MW units could provide the 760MW demand, at a unit cost of £98million, for a total of £296million, (Cadent, 2017).
With steam methane reforming being an established technology, the design and costs of systems are well understood with variation coming from proprietary designs. There is more uncertainty in the capture side of the process due to developments in novel solvents beyond the standard amine systems. A large portion of the cost in the capture plant will likely be caused by the need for compression of CO2. 5.6 UK Hydrogen Project Comparison
The table below is intended to provide a like for like comparison of the key hydrogen projects being considered in the UK.
ACT Acorn Consortium Page 25 of 80
D18 Expansion Options Acorn Hydrogen
Liverpool-Manchester Acorn Cautious One SMR Leeds H21 Acorn Ambitious Scenario HyNet Scenario
Gas grid blended to Gas from St Fergus blended to Gas from St Fergus Conversion of Leeds gas maximum possible and 20% hydrogen and Concept For comparison blended to 10% grid to 100% hydrogen high hydrogen for Aberdeen/Moray to 100% hydrogen industry hydrogen SMRs 1 (250MW) 4@70% 3@90% 5@80% 15@87% 3 H2 rate MSm /d 1.8 5.2 4.9 7.5 23
H2 energy TWh/yr 2.2 6.4 5.9 9.2 28
H2 T/yr 55,000 163,000 152,000 234,000 717,600
CO2 MT/yr 0.5 1.7 1.6 2.2 6.8 % of current UK 1.4% 4.0% 3.7% 5.8% 17.7% gas by volume % of current UK 0.4% 1.2% 1.2% 1.8% 5.4% gas by energy Capex cost estimate (excl. £100m £2,054m £600m £500m £1,500m CCS) CCS costs - £1,609m £874m £804m £1,608m Opex cost - £79m £57m £60m £180m Total cost - £5,243m £2,614 £2,504 £6,708m
Cost/kg H2 - £1.60/kg 86p/kg 53p/kg 47p/kg
Table 5-4: Comparison of key hydrogen projects
Assumptions Acorn to achieve a cost comparison. Captain X storage development cost is used for Acorn Hydrogen Cautious. Twice the Captain X • Hydrogen and SMR costs from H21 report, (Northern Gas Networks, storage development cost is used for Acorn Hydrogen Ambitious. 2016), and Cadent report, (Cadent, 2017). The storage development cost for Hamilton is used for Liverpool- • CCS costs from ETI report, (Pale Blue Dot Energy & Axis Well Manchester HyNet. The storage development cost for Bunter CL36 Technologies, 2016). This assumes no previous development at
ACT Acorn Consortium Page 26 of 80
D18 Expansion Options Acorn Hydrogen
is used for Leeds H21 (Pale Blue Dot Energy & Axis Well • St Fergus is a cost-effective place to produce hydrogen from gas.
Technologies, 2016). The cost of abatement, i.e. the cost per tonne of CO2, is lower for • 20-year project life. Thus 20 years of operational expenditure (Opex) both Acorn scenarios than the other projects considered. The cost of cost. hydrogen is lower for both Acorn scenarios than the other projects • Hydrogen cost/T figures are total costs divided by tonnage of considered. hydrogen (20 years at full rate) 5.7 Hydrogen Production Concept • All costs are undiscounted
Based on this comparison it is apparent that; The steam reformation process is well established with the first patents dating back to the 1930’s. Since then research and development of catalysts and • Blending hydrogen into the gas grid is a lower cost, more optimisation of the process has led to an average efficiency of 65-75% straightforward way to start the decarbonisation than a 100% (NYSERDA, 2006). hydrogen conversion. Costs for 100% grid conversion requires the cost of appliance conversion, Intraday and Inter-seasonal salt Steam methane reformation of natural gas consists of the following reactions: caverns and a hydrogen transmission system, which are not ° 퐶퐻 + 퐻 푂 ⇌ 퐶푂 +3퐻 (−Δ퐻 = −206 kJ/mol) required for blending. Thus, there is a considerable cost difference 퐶푂 + 퐻 푂 ⇌ 퐶푂 + 퐻 (−Δ퐻° = 41 kJ/mol) between these project types. Given the minimal additional infrastructure and no user interventions, it also appears more The first reaction is the steam reformation reaction for methane. It is a reversible straightforward to blend hydrogen. This should enable hydrogen reaction and strongly endothermic. Using le Chatelier’s principle it must be conversion by blending to take place earlier that 100% hydrogen carried out at high temperature, a high steam to methane ratio and low pressure conversion. Both approaches have an important role to play in to shift the equilibrium to the right and achieve maximum conversion of methane. decarbonisation with the early cost benefits of SMR hydrogen Additional hydrogen can be recovered with a lower temperature gas shift helping to grow the demand, infrastructure, supply chain and value reaction to convert the carbon monoxide. proposition for pure hydrogen. A typical SMR process will begin with a feed preheating stage prior to the steam • Blending 10% hydrogen by volume at St Fergus would have a larger reformation reactor. The preheat stage allows for the use of recovered heat to environmental benefit than converting the Leeds area gas grid to increase efficiency. The reformation reactor outlet contains methane, CO2 100% hydrogen (2.2MT/yr CO vs 1.7MT/yr CO respectively). 2 2 carbon monoxide and water with the temperature typically around 800 to 950°C Whilst recognising that these are not mutually exclusive projects, it (Dotzenrod, et al., 2015). This stream is passed onto the shift reactors to convert points towards starting the decarbonisation process by blending.
ACT Acorn Consortium Page 27 of 80
D18 Expansion Options Acorn Hydrogen
the carbon monoxide into CO and generate additional hydrogen. From the shift 2 Content or Value reactors the product is passed on to a capture plant, typically amine, where the Characteristic
CO2 will be removed. Hydrogen is separated using pressure swing adsorption Hydrogen Sulphide (PSA) with the unreacted methane being recycled back into the process. ≤ 5 mg/m3 (H2S) Content 5.7.1 Outline Basis of Design Total Sulphur Content 3 Feed Gas Composition and Condition ≤50 mg/m (including H2S) The ideal offtake for natural gas feeding into the SMR plant is downstream of Hydrogen Content ≤0.1% (molar) gas processing but upstream of compression. The offtake should be upstream of compression because the reformation reaction will have a higher conversion Oxygen Content ≤0.2% (molar) at lower pressure. The condition of the gas output from the processing terminals Shall not contain solid or liquid material which at St Fergus might need to be adjusted to create the ideal pressure for the may interfere with the integrity or operation of pipes or any gas appliance (within the meaning reformation reaction. Impurities of regulation 2(1) of the 1994 Regulations) The gas feed to the SMR plant will be the same as the gas specification of the which a consumer could reasonably expect to operate National Transmission System (NTS).
3 3 There would need to be a revision of the gas quality specification to enable Wobbe Number (WN) (i) ≤51.41 MJ/m , and (ii) ≥47.20 MJ/m blending of hydrogen into the NTS as the current allowable hydrogen content is Incomplete Combustion ≤0.48 less than 0.1% on a molar basis. BEIS are currently supporting several projects Factor (ICF) which involve a review of the gas specification for the NTS. Sooting Index ≤0.60
Table 5-5: National Gas Transmission System Gas Quality Specification (1996)
Required Unit Performance
Required hydrogen purity will depend on end use. For blending into the NTS the required quality is uncertain as the gas specification needs to change to allow hydrogen blending in the first place. For hydrogen fuel cells very high purities, >99%, are required. Very high purities of hydrogen can be achieved by using
ACT Acorn Consortium Page 28 of 80
D18 Expansion Options Acorn Hydrogen
pressure swing adsorption to separate the hydrogen from any unconverted 5.7.2 Conceptual Design methane. Steam methane reforming is a mature technology and the underlying processes Utilities are well understood. There are five key stages to an SMR:
Typical utilities that may be required include: • Preheat – A simple train designed to use recovered heat to provide • Electricity energy to the incoming feed. • Steam • Reformation – The key operational parameters of the reformation • Cooling Water reactor are the temperature it operates at and the catalyst selected, • Demineralised Water cheaper nickel catalysts are typical rather than expensive platinum • Nitrogen and rhodium. The shape and construction of the reactor also impact • Instrument Air the heat distribution from the burners and the life span of the tubes • Drains and the reactor itself. • Shift Reactors – The stream leaving the reformation reactor will Plant Availability require cooling ahead of the shift reaction. A suitable catalyst will Since the purpose of the SMR is to provide hydrogen to blend into the NTS it need to be selected for the reactor, copper catalysts are typical but should aim to provide hydrogen year-round. High availability, while desirable for more effective and higher cost catalysts are available. decarbonisation, is not critical since the methane that would be used to generate • Capture – Solvent choice is a critical decision in capture processes, hydrogen can enter the NTS while the plant is not operating. Availability the choice of solvent will directly impact the energy requirement for becomes a greater concern when considering a dedicated hydrogen grid. regeneration as well as the operational costs associated with first fill
Thus, the technical case for SMR will need to consider the sizing of capacity to and replenishment. allow for the seasonality factor outlined in Figure 5-1, i.e. SMR capacity • PSA – The material selected for use in pressure swing adsorption is requirement to match a 10% hydrogen inclusion in the NTS at 07:00 on a peak dependent on the gases being separated. Typical examples include; summer day will be significantly lower than that required to deliver 10% inclusion activated carbon, silica gels, zeolites and resins. Surface area is a at 07:00 on a peak winter day. key consideration for the material. The choice will also impact how the bed is regenerated.
ACT Acorn Consortium Page 29 of 80
D18 Expansion Options Acorn Hydrogen
hydrogen needs to be from renewable sources. To consider hydrogen as a decarbonisation pathway through the reformation of fossil fuels, typically natural
gas, carbon capture and sequestration of the CO2 emissions of a reformer is absolutely necessary.
5.8.2 Economic Case
An economic model for a hydrogen generation project has been used to appraise the business case for hydrogen production. The model is substantially based around work done of the Teesside Industrial CCS project which included
the BOC H2 SMR facility at Seal Sands (Pale Blue Dot Energy Ltd., 2015). Key assumptions are provided below:
• Costs are based on 2018 real term estimates • The plant is assumed to operate for 20 years • Operations commence in 2023 • A 150MW hydrogen production unit, operating at 100% availability, is assumed to require 130kT/yr of natural gas (including fuel) and 5.9MW of imported power to produce 33kT/yr of hydrogen and Figure 5-2: Block diagram of an SMR plant with CO2 capture 339kT/yr of carbon dioxide
5.8 Hydrogen Economics • No capture of CO2 is included • An 8% rate of return on investment is required 5.8.1 Strategic Case • Power and Natural Gas prices are wholesale figures reported in the The strategic thinking behind a move to a hydrogen economy is routed in the BEIS Energy Projections Annex M decarbonisation of energy, notably heat and transport demand. While efforts in The plant is assumed to cost £59 million to build and roughly £51 million/year to renewable power have reduced the carbon intensity of power generation, heat operate based on the £40 million that the plant and associated infrastructure and transport have lagged behind. was reported to have cost to building 2002 (ICIS, 2002). Hydrogen can be generated using electrolysers or can be reformed from fossil fuels. To ensure that energy is decarbonised the power used to generate
ACT Acorn Consortium Page 30 of 80
D18 Expansion Options Acorn Hydrogen
Cost Element £ Million Over the 20 year operational life the plant will generate roughly 652kT of hydrogen. Capex 59 Opex 1025 The project is assumed to have a period prior to commencement of FEED where Power 52 additional feasibility work is carried out, this is assumed to begin in 2019 and last for two years. Construction is assumed to begin in 2021 and takes two years Natural Gas 885 to complete ahead of commercial operation in 2023. Other Opex 87 Decommissioning 18 Revenue is generated from the sale of hydrogen. To achieve the assumed 8% Total 1,102 rate of return (in real terms) a hydrogen price of £44.77/MWh is required (£1,778/Tonne of hydrogen). The cost of natural gas for feedstock and fuel is Table 5-6: Life Cycle Cost of Hydrogen Production Unit, Opex over 20 years the biggest influence on the cost of hydrogen and therefore on the required price.
Figure 5-4: Hydrogen Production Unit Cash Flow Chart
The upwards trend in the operating cost between 2023 and 2029 reflects the gas price projections (BEIS, 2018).
Figure 5-3: Unit Cost of Hydrogen Production Unit
ACT Acorn Consortium Page 31 of 80
D18 Expansion Options Acorn Hydrogen
Impact on Hydrogen Price £/T Low Base High
Natural Gas Price 1,252 1,778 2,141
Power Price 1,778 1,778 1,778
Table 5-7: Hydrogen Price Sensistivity
ACT Acorn Consortium Page 32 of 80
D18 Expansion Options CO2 Utilisation (CCU)
6.0 CO2 Utilisation (CCU)
6.1 Summary 6.2 CCU Context
CO2 utilisation (CCU) offers the potential to use emitted CO2 as a feedstock to CO2 utilisation (CCU) offers the potential to take certain carbon emissions and produce carbon-based products such as inorganic fertiliser, fuels, chemicals use them as a feedstock to produce carbon-based products such as inorganic and building materials. Converting CO2 into carbon-based products requires fertiliser, fuels, chemicals and building materials. Historically CO2 utilisation has energy and other input materials, thus the economics depend upon these focused on Enhanced Oil Recovery (EOR), which involves injecting CO2 into oil factors. Whereas with CO2 sequestration (CCS), the focus is on climate change fields to increase oil recovery. CO2 utilisation also offers the potential to store mitigation, with CO2 utilisation (CCU) the focus is primarily about revenue ‘surplus’ electricity at times of oversupply via the creation of synthetic generation through new value-added products. It should be noted that many hydrocarbons, such as methanol. current CCU products eventually release the re-used CO2 into the atmosphere. Many CO2 utilisation processes require an input of energy, which should be from CO has also been used to enhance oil recovery (EOR), especially in the US. 2 a low carbon source. As the world transitions to products with lower The Acorn project is focused on carbon capture and storage and has can environmental impacts, it will need access to lower impact feedstocks and fuels facilitate CO2 utilisation opportunities. to create these products. CO2 utilisation offers a route to provide the carbon needed for lower impact products (as the carbon is being re-used), but due to The Grangemouth industrial cluster presents the best location in Scotland for the lower cost of “virgin” carbon from fossil fuel sources, there is currently little developing CCU opportunities, with the potential link to higher volume CO2 market pull through. capture and transport through Feeder 10 to the Acorn project. However, initial
CCU activity does not require any CO2 transport and storage infrastructure. In the medium to long-term, if CCS is able to provide a route for the industrial complexes at Grangemouth to a low-carbon future through world leading low Given its location, lack of industrial by-products and site-based constraints it is carbon manufacturing, CO utilisation is likely to find a role to play here too. unlikely that St Fergus will be a suitable site on which to develop commercial 2 scale CCU projects. CO2 utilisation holds out the promise of providing economic activity by re-using
CO2 as a feedstock to create various products. This economic activity has the Whilst potential exists to use CO2 from the Acorn CCS system for EOR, the potential to help the UK shift to a lower-carbon, more sustainable and more economics of North Sea offshore CO2 EOR are currently challenging. circular economy through better management and re-use of its carbon, and in
particular, by helping the UK to develop its CO2 resource by giving it a value.
ACT Acorn Consortium Page 33 of 80
D18 Expansion Options CO2 Utilisation (CCU)
Carbon Capture and Storage (CCS) and CO2 Utilisation (CCU) should both be Database lists 212 technology projects, 28 of which are within the UK. These 28 part of the UK’s overall strategy for CO2 management. The two avenues are projects are led by 22 individual organisations. Of these organisations 10 are considered to be complementary. Both share the potential to be significant future universities, implying a low technology readiness level, and of the remaining 12, growth areas, which will be governed by market developments at a policy level, only 8 appear to be aspiring CCU technology providers. as well as technological advances and sufficient levels of Government Typically, the business case for CO2 utilisation technologies relies on offsetting investment in infrastructure. Whilst the applications for CO are varied, the 2 waste disposal costs from certain industrial processes by using their waste as a potential near-term demand for CO2 relative to the scale of supply of UK CO2 feedstock to combine with CO2 and create a valuable product. emissions is low, to the extent that CCU should NOT be considered an CO2 utilisation technology companies have, thus far, located at or near sources alternative to CCS when looking to tackle and mitigate the scale of the UK’s CO2 emissions. CCS and CCU are aiming for very different scales of deployment. of feedstock to minimise their logistical costs and bring in the CO2 rather than select a location based on CO2 availability. CO2 utilisation is not currently considered to be a CO2 abatement technology under the EU ETS, although this situation may change when the scheme is The graphic below shows the scale of CO2 emissions in Scotland vs potential demand (The University of Sheffield, Pale Blue Dot Energy et al, 2016). revised. Consequently, CO2 that is used to create a product of some kind is still considered to be emitted and is therefore still chargeable under the EU ETS rules. Geological sequestration of CO2 is the only recognised abatement technology under the EU ETS and quantities of CO2 thus sequestered would be exempt from the EU ETS and Carbon Price Floor schemes.
There are currently no financial, policy or commercial reasons to capture CO2 from industrial (or other) processes. Several organisations have received financial support from governments and European Funding Agencies to explore the benefits of CO2 utilisation technology as detailed in two recent publications (Imperial College and Ecofys, 2016) and (SCOT Project, 2016), amongst others.
SCOT (Smart CO2 Transformation) was a collaborative European project
(supported by the Seventh Framework programme) on CO2 utilisation. The main objective of the project was to define a Strategic European Research and
Innovation Agenda for Europe in the field of CO2 Utilisation. The SCOT CCU
ACT Acorn Consortium Page 34 of 80
D18 Expansion Options CO2 Utilisation (CCU)
produced from existing industrial processes. A step change in CO2 utilisation could theoretically be achieved through the development of new markets and technologies. However, the majority of emerging technologies are at too early a
stage for deployment to reach the scale of 0.1-1 MTCO2/yr in 2025 that would
be needed to support industrial capture, and the costs, performance and CO2 abatement potential of these are not yet well described in the literature.
Meaningful levels of onshore CO2 utilisation are only possible with significant and carefully designed government interventions to build markets and push
technology development. Stranded industrial CO2 sources are unlikely to implement capture based on revenues from utilisation alone without additional policy support. In the future, annual revenues of £25-250million may be possible if some of the hurdles can be overcome.
One study (Element Energy, 2014), estimated an upper limit for CO2 utilisation
deployment in the UK be 9 MTCO2/yr by 2025. The same study estimated annual revenues of up to £3 billion from the production of fuels, building
products and chemicals based on CO2 feedstocks.
6.3 CO2 Enhanced Oil Recovery (EOR)
CO2 Enhanced Oil Recovery (CO2-EOR) could use the captured CO2 from large
Figure 6-1: Scottish CO2 emissions and demand emitters such as power stations or industrial sources to yield additional oil from hydrocarbon reservoirs. This technique has been used in the USA (and other In theory CO2 utilisation offers opportunities for improving the economics of laces) for many decades, utilising CO2 from naturally occurring geological capture or providing a use of CO2 for those sites that cannot access transport and storage infrastructure. A literature review reveals that utilisation options accumulations and more recently (and occasionally) from anthropogenic sources. Development of CO2-EOR in the UK, using CO2 from large industrial differ in terms of technology availability, market maturity, CO2 abatement potential, and relevance for large UK industrial sites. A key challenge is that or power sources would require significant infrastructure and project activity, which studies to date have shown to be uneconomic when set against risk and existing markets for CO2 are already competitively over supplied with CO2 incremental production. Other regions of the world have reached similar
ACT Acorn Consortium Page 35 of 80
D18 Expansion Options CO2 Utilisation (CCU)
conclusions, which are that CO2 EOR can be economic onshore, but is difficult Pale Blue Dot Energy prepared an unpublished study for a North Sea Operator, to make economic offshore. which suggested that oil prices ~$100/bbl were required for offshore CO2 EOR to be economic in a particular project. Key differences between the UK and US situation with respect to EOR are shown in Table 6-1. Based on the table above, and the previous work done by Pale Blue Dot Energy,
our view is that North Sea CO2 EOR is; US UK • Technically feasible and could contribute to the basins 2035 vision Offshore: High cost to Maximise Economic Recovery (MER) Onshore: Low cost environment, challenging • Currently uneconomic, due to high costs Location environment, easy access, access from platform or multiple wells on a pattern subsea, expensive • Could become economic if the oil price was sufficiently high and/or directionally drilled wells tax incentives were provided. • More complicated and costly to implement than is often assumed – Naturally occurring CO2 used initially to develop two in reality existing oil field infrastructure would require modification to major US pipeline systems enable it to be used for CO2 EOR operations. CO2 Source transporting and selling CO2. No CO2 currently available Now an active CO2 market, An obvious tension exists between CO EOR and CCS, given that the objective creating a drive for 2 anthropogenic CO2 of CCS is climate change mitigation and the objective of EOR is increased oil production. Some work on EOR has suggested that it may be possible to Land wells and facilities, Platform wells and facilities increase the volumes sequestered if the objective of EOR was climate change spaced out with little space with limited space and Access constraints and therefore designed for hydrocarbon mitigation and there was a commercial driver to store as much CO2 as possible. few HSE issues HSE issues 6.4 St Fergus CCU High cost environment and location. Any change to CO Low cost environment and 2 The St Fergus gas terminal is the planned site for CO2 capture for the Acorn Brownfield flood requires considerable location to change field Modifications facility change, which needs CCS project. Whilst this could also present potential for CO2 utilisation, there operations to CO flood 2 to fit within the platform are some obvious challenges with this location; capability • Site security, designed to protect the gas terminal from unauthorised Table 6-1: Differences between the UK and the USA with respect to EOR access, constrains its use for additional activity.
ACT Acorn Consortium Page 36 of 80
D18 Expansion Options CO2 Utilisation (CCU)
• The site location has few existing waste streams, other than CO2, Grangemouth is also close to the potential markets of central Scotland for any
which could be combined with the CO2 to make new product. products such as inorganic fertiliser, fuels, chemicals and building materials, • The site location in North East Scotland makes it remote from which are produced. Existing port infrastructure offers shipping routes. markets for products created unless shipped via Peterhead. Whilst the availability of CO2 transport and storage facilities are not a pre-
For these reasons it appears unlikely that St Fergus would make a good location requisite for CCU, having a CO2 collection network for CCS, would provide a for commercialising CCU products at scale. useful network off which to develop and link CCU projects. The build out of the Acorn project by using Feeder 10 creates an opportunity for linking CCS projects It remains possible that some R&D facility could be constructed at St Fergus and CCU opportunities in this important regional industrial centre. although even that could be an issue with site access for research staff, visitors etc.
Section 9 outlines the prospect of CO2 being bulk imported for sequestration via Peterhead Port. The could enable Peterhead Port to develop a new CCU manufacturing sector involving the import/export of raw materials/finished product. However, as below, Grangemouth offers a stronger case. 6.5 Grangemouth CCU
Grangemouth is likely to be the location for any longer-term strategic aspiration to create a CO2 utilisation hub of scale in Scotland, as the location houses the majority of Scotland’s large emitters and has straightforward tie-ins to identified potential CCS infrastructure. Grangemouth is Scotland’s largest manufacturing region, with a deep and broad chemical sciences knowledge base and its associated supply chains. Half of the 20 largest Scottish carbon emitters are in the Grangemouth Region, with 12 CO2 emitters within 50 miles of Grangemouth producing CO2 with an estimated capture potential of 3.1MT/yr. As Grangemouth develops its potential as an Industrial Biotechnology cluster, there are likely to be synergies and industrial symbiotic opportunities that use CO2 to provide additional value.
ACT Acorn Consortium Page 37 of 80
D18 Expansion Options Bioenergy
7.0 Bioenergy
7.1 Summary will shortly exceed the supply of UK biomass. While domestic sources offer the greatest energy security and sustainability benefits in the longer-term, the UK Bioenergy offers considerable potential to support the decarbonisation of the UK currently doesn’t have enough of its own biomass feedstock to supply a energy mix. When linked with CCS, bioenergy can support delivery of negative commercially-viable large-scale bioenergy sector. Therefore, the most emissions, which many forecasts see as an essential part of meeting our long- pragmatic approach is to develop the sector based on near-term increases in term climate goals. biomass imports derived from sustainable sources, such that the key actors in Acorn is not a bioenergy project. The opportunities for physical linkage of the supply chain can ‘learn by doing’ in terms of logistics, handling, designing bioenergy projects with the Acorn project are limited, but considerable and operating bioenergy conversion technologies. In parallel, support is needed opportunity exists for development of synergies and the development of to build up a strong and commercially-viable biomass feedstock supply chain in bioenergy as part of the integrated energy mix, which includes consideration of the UK, such that domestic biomass supplies can continue to play a significant
CO2 emissions and new energy vectors such as hydrogen. role, (Energy Technologies Institute, 2016). 7.2 Context 7.3 Acorn Linkage
Bioenergy can play a significant and valuable role in the future UK energy Biomass projects of scale, such as at Grangemouth, could include CCS, thus system. When combined with Carbon Capture and Storage (CCS) bioenergy enabling negative emissions. With the Acorn project and build out through can deliver net negative emissions of circa -55MT/yr and meet around 10% of Feeder 10, the incremental cost of such biomass CCS projects is principally the UK energy demand in the 2050s, ultimately reducing the cost of meeting the capture system. An 85MW biomass combined heat and power (CHP) plant is UK’s 2050 greenhouse gas (GHG) emission reduction targets by more than 1% planned for Grangemouth. of GDP. Without CCS, bioenergy can still deliver GHG savings and play an Whilst there are only limited opportunities for direct linkage between Acorn and important role in the energy system. Delivering the greatest value from bioenergy projects, there are some potential synergies, by which Acorn could bioenergy depends on the UK’s ability to source and distribute sufficient biomass support the development of bioenergy in the UK. These are presented here; from sustainable sources, either domestic or imported. • CO2 capture at Acorn will provide learning for subsequent CO2 In recent years supplies of both imported and UK produced biomass for capture projects including on bioenergy. Implementing the bioenergy (excluding waste) have increased. However, quantities of imported biomass have been growing at a much greater rate and, if this trend continues,
ACT Acorn Consortium Page 38 of 80
D18 Expansion Options Bioenergy
technology at various scales will help reduce cost and progress new Aberdeen Exhibition and Conference Centre (AECC) as part of the energy capture technologies. supply for the integrated energy centre. • The hydrogen build-out of Acorn could support the decarbonisation Waste to power plants also provide an opportunity for integrated energy systems of the gas grid and provision of hydrogen for transport and heat. By which could capture CO2 for utilisation or storage. Waste gasification allows initiating the hydrogen market, Acorn could stimulate the provision of heat or electricity to be generated locally and syngas to be injected into the gas hydrogen from other projects including bioenergy projects grid, with the prospect of cheaper flue-gas clean-up, reduced emissions and • There is a linkage between bioenergy projects and CCU, where higher efficiency compared to incineration plants. Agile Energy are planning a waste CO can be recombined with other waste streams, i.e. ash, to 2 project at Inverurie in Aberdeenshire, which could produce hydrogen in addition produce a valuable product (as described in the previous section. to power and heat. Aberdeen City Council are progressing a waste to power 7.4 Regional Potential plant in Aberdeen, which could capture CO2 for re-use. Biomass CHP plants, such as those on Speyside in Moray, present an For the same reasons as for CO2 utilisation, it is unlikely that the St Fergus Gas equivalent opportunity. terminal will be a development location for bioenergy projects. Another concept is the large-scale gasification of woodchip where syngas is However, the North East of Scotland has considerable potential for the exported into the gas grid and CO is exported into the transport and storage development of bioenergy projects and is already involved in several 2 infrastructure. Wood supply could be transported by ship providing a “Ship to developments. Gas” solution at the dockside. This could work at either Peterhead or It would be possible to capture CO2 from bioenergy projects and integrate this Grangemouth. There will be an opportunity for heat recovery from the process with the CO2 transport and storage infrastructure planned for Acorn. However, for a local district heat solution. many biomass projects are relatively small scale and not located adjacent to pipeline infrastructure, so would require road tanker transport. CCU is an alternative which could suit some projects.
Anaerobic digestion (AD) as a process to produce gas from farm and food waste is a well proven and growing technology area. In particular, biomethane to grid plants where biogenic CO2 is already separated at high purity. There are several small-scale projects in the North East with more planned, including at the new
ACT Acorn Consortium Page 39 of 80
D18 Expansion Options Peterhead CO2 Transfer Facilities
8.0 Peterhead CO2 Transfer Facilities
8.1 Background
Peterhead Port is in the northeast of Scotland, about 20km south of the St Fergus gas processing terminal (Figure 8-2) and is mainly used for vessels in the fishing and oil and gas industries.
It is a deep-water port with a tanker jetty designed for tankers up to 50,000 tonnes deadweight, which could be used to import CO2 for onward transport to St Fergus and subsequent storage in Central North Sea storage sites. A picture of the tanker jetty is shown in Figure 8-1 (Peterhead Port Authority, 2017).
Figure 8-2: Peterhead area
Currently there is no facility to import or export CO2 at Peterhead. CO2 offloading Figure 8-1: Tanker jetty at Peterhead Port, which could be used for CO2 import via ship and transportation infrastructure would need to be installed, including for
ACT Acorn Consortium Page 40 of 80
D18 Expansion Options Peterhead CO2 Transfer Facilities
transportation of CO2 from the harbour to St Fergus. There is an existing natural Peterhead to the Port, a pipeline route via Peterhead Power station seems a gas pipeline that runs between St Fergus and Peterhead power station slightly sensible approach. south of the town. Once the infrastructure is in place then Peterhead would be a prime location to import CO2 for storage purposes either from elsewhere within the UK or more broadly from Europe, especially Rotterdam.
An initial feasibility study on CO2 importation via ship to Peterhead Port was conducted by Petrofac (Petrofac, 2012) which concluded that CO2 transport via Peterhead Port was technically viable. The study also looked at the logistics of onward transportation from the port to St Fergus and found that re-use of existing (low pressure) regional pipeline infrastructure constrains the maximum
CO2 that could be imported per year to 1.2 to 1.5MT/yr. This is illustrated in Figure 8-3. If a new 20” high pressure pipeline was built, then this increases to 5.7MT/yr. 8.2 Basis of Design
The facilities required are intended to enable CO2 offloading from ocean going bulk CO2 carriers at Peterhead Port, conditioning of the CO2 and transfer to St Fergus by pipeline where it would then be prepared for offshore transport and storage. The CO2 is assumed to be shipped in tanks at 7bara and -55°C (liquid). The required delivery conditions for pipeline transportation to the offshore facility are 120barg (minimum) and >29°C. The CO2 rich fluid stream is assumed to be
99% (by volume) pure CO2. Figure 8-3: Port and transfer facilities diagram
The proposed route for transfer of CO2 is via the tanker jetty at the port, to land CO2 shall be maintained in liquid phase at all times. Previous work has at Peterhead Power Station and then onwards to St Fergus. Peterhead Power considered the possibility of changing the phase of imported CO2 back to gas Station is included, since there is potential space available for any facilities (such phase for onshore transport between Peterhead and St Fergus, possibly to space is lacking near the port side) and there is also an existing pipeline route enable re-use of existing lines. Given the capacity constraints in the existing from Peterhead Power Station to St Fergus. Given the proximity of the town of lines (1.2 to 1.5MT/yr), a new onshore pipeline is proposed and as such it shall
ACT Acorn Consortium Page 41 of 80
D18 Expansion Options Peterhead CO2 Transfer Facilities
be designed for high pressure service. This approach minimises the energy • CO2 transport vessels assumed to be 30,000T. consumption and process complexity of the transfer process, by keeping the • Offload rate 17,500T/d, 2 days to unload a 30,000T vessel.
CO2 in liquid phase and avoiding the issues of vaporising and compressing the • Ship import capacity on an annualised basis is ~5MT/yr.
CO2, which would arise if we crossed the saturation line. Potential also exists for the export of CO2 from Peterhead Port. Commentary on the implications of this are provided, but such facilities have not been costed at this stage. 8.3 Peterhead Port Facilities
Ships of approximately 30,000m3 carrying capacity (slightly in excess of 30,000
tonnes of CO2) for which the approximate sizes are 210m long, 11m draught and 37,000 tonnes deadweight are well within the capabilities of the port and the tanker jetty. The originally dredged depth was 12.5m to chart datum.
The tanker jetty can accept ships of up to 50,000 tonne cargo size. The harbour is nearing the end of a 12-month upgrade programme the included significant dredging to deepen the harbour. To accommodate vessels larger than this, some additional dredging may be necessary to ensure under keel clearance is maintained. This will depend upon the tanker size and design.
Facilities will be designed to enable offloading of CO2 directly at vessel conditions, for transfer to the Peterhead Power Station, through a 20” 2km low temperature pipeline, designed to offload 17,500T/d. Figure 8-4: CO2 transfer phase conditions The transportation of cold liquid CO , if left to warm to ambient conditions in a Other key assumptions are as follows: 2 closed system would increase pressure by at least 25%. This could lead to the • The distance between Peterhead Port and Peterhead Power Station requirement to have very high design pressures for the low temperature pipeline is 2km. between Peterhead Port and Peterhead Power Station. • The pipeline distance between Peterhead Power Station and St Fergus is 20km.
ACT Acorn Consortium Page 42 of 80
D18 Expansion Options Peterhead CO2 Transfer Facilities
The design pressure of the low temperature pipeline and the requirement for 8.5 Peterhead to St Fergus Facilities over-pressure protection by relief to the atmosphere is a design issue that would be addressed during a potential FEED study. CO2 is transferred from Peterhead Power Station to St Fergus by a new 20” medium pressure pipeline operating at ambient temperature and 120barg. The There would be a requirement to place transfer pumps on Peterhead Port tanker pipe is a 20” 20km line with a throughput capacity of 17,500T/d. jetty. Installing pumps on the jetty, of the size considered, appears to be quite feasible; along with the power supply they require (approx. 2.5MW). The transfer system contains in the order of 4,300 tonnes CO2 at approximately 120barg in liquid state (approx. 500 tonnes being at -55°C, the remainder being Facilities should also allow for vessel loading of CO at the same conditions in 2 ambient). the event that export of CO2 was required. Only modest changes to offloading facilities are expected to be required to enable this. During periods between ship unloading at Peterhead Port it is foreseen that for liquid transfer, the pipeline would remain under pressure and equal to that of the 8.4 Peterhead Power Station Facilities destination pressure.
On the site of the Peterhead Power Station, CO2 imported from the port as a CO2 would be vented to safe location at Peterhead Port, Peterhead Power liquid will be heated and pumped from vessel conditions of -55°C and 7bara to Station or St Fergus as appropriate in emergency situations. A means of heating pipeline transfer conditions also as a liquid at 120barg and ambient temperature. would be beneficial as depressurisation of even medium pressure, ambient temperature CO would lead to very cold emissions with negative buoyancy that Cooling water discharge (seawater) from Peterhead Power Station is assumed 2 would tend to sink towards the ground or the sea (in the port area). to be available at 20°C for use as a warming medium when heating refrigerated
CO2. This warms the CO2 to 10°C and consequently this cools the seawater (to The potential impact of CO2 vent stacks on the surrounding areas (e.g. physical a minimum of approximately 12°C). This requires 24MW of heating, all provided height and plumes, depending on operating conditions, would also need to be by cooling water discharge. considered. In addition to land space, the site is also assumed to provide power and utilities. 8.6 Consents In the case of CO export to ship, refrigeration facilities would also be required 2 Any proposed development will be required to apply for planning consent in the to convert CO at ~100barg and ambient temperature to -55°C and 7bara for 2 normal manner and will be a classed as a “Major Development” under The Town shipment. and Country Planning (Hierarchy of Developments) (Scotland) Regulations 2009. Such an application will include an Environmental Impact Assessment and an extensive evaluation of any associated health and safety impacts.
ACT Acorn Consortium Page 43 of 80
D18 Expansion Options Peterhead CO2 Transfer Facilities
8.7 Costings Opex item notes cost
Costs below are drawn from the Petrofac shipping report, (Petrofac, 2012). Onshore Inspection and All sites $1.5m/yr Maintenance Capex items Notes Cost Power and Utilities Heating and pumping $2.4m/yr Jetty Modifications At Peterhead Port $4m Logistics and Consumables $2.1m/yr
CO2 Unloading Arms LT liquid $1m Insurance 2% pa of asset values $3.6m/yr 20” 2km LT Pipeline Port to Power station $8.9 Operations, Personnel and $1.5m/yr Management 20” 20km MP Pipeline Power station to St Fergus $37.8m Vessel Operations $2.5m/yr HP Liquid Pumping System At Peterhead Power Station $43.8m Total $13.6m/yr Warming Exchanger System At Peterhead Power Station $0.7m Table 8-2: Opex costs Site Civils/Buildings All sites $9.3m
Power & Controls All sites $3.5m 8.8 Future work
HSE Systems All sits $3.6m The next phase of activity is for a detailed engineering scope to be developed for detailed pre-feed study on the import configuration. This also requires further Warming and Pumping $5m System understanding of the detail of CO2 shipping vessels.
Total $117.6m
Table 8-1: Capex costs
ACT Acorn Consortium Page 44 of 80
D18 Expansion Options International CO2 Shipping
9.0 International CO2 Shipping
9.1 Shipping Summary downstream CO2 transport for interrupted flow, improving definition of weather- related downtime and effects of downtime seasonality on other elements of the Transport of liquefied carbon dioxide CO2 by ship is an established operation CCS chain. and is under consideration by a number of CCS projects around the North Sea Factor Unit Value Value Value Basin. Ship transport of CO2 is recognised as a viable alternative to pipeline Ship size DWT 50,000 30,000 10,000 transport in appropriate circumstances. Cargo Size T CO2 40,000 24,000 8,000 Build-out options for the Acorn Project include importing CO2 by ship into Max practical annual offloads offload/yr 406 543 820 Peterhead Port. Modelling for this study suggests the port has ample capacity Maximum practical capacity MT/yr 16.2 13.0 6.6 for the import quantities envisaged for early build-out phases; a maximum Max practical offload offload/day 1.1 1.5 2.2 frequency practical capacity of 16.2MT/yr is estimated. This would require over 400 ship Table 9-1: Base case model results; maximum capacity for different ship sizes movements during the course of a year and would represent a 15-25% increase of port traffic. Potential CO2 export hubs around the North Sea Basin could A summary on shipping is provided here and the full CO2 shipping report is supply several times this quantity. included as Section 12 Annex 1 International CO2 Shipping Scenarios.
Shipping scenarios based on potential CO2 export hubs have explored the 9.2 Shipping Introduction number, size and fuel consumption of ships required to service the maximum practical capacity of the port, and also for a range of lower annual quantities. The transport of CO2 in bulk by ship is established in European waters as part of the international trade in CO2 for industrial, food and drink, and other uses. For import quantities in the 5 to 10MT/yr range, a fleet of three or four tankers The CO2 is, in general, obtained as a by-product of hydrogen production as part of 30,000 to 50,000 deadweight tonnage (DWT) size will be required to service of the ammonia synthesis process. However, the scale of the current CO2 routes from CO export hubs within the North Sea area. Specific fuel 2 market is small (around 3MT/yr) compared to the envisaged scale of the CCS consumptions of 4.6 to 5.2T/kT-CO are estimated for these scenarios. 2 industry at, potentially, tens to hundreds of millions of tonnes per year. There
This study has increased the understanding of factors affecting CO2 import by are currently only a small number of existing CO2 transport ships and these are ship into Peterhead Port and shown that the port has ample capacity for import of low capacity, in the range of 900 to 1,800 tonnes (T), (Brownsort P. A., 2015a). levels for early build-out phases of the ACT Acorn Project. Areas for further consideration include definition of low-temperature CO2 pumps, design of
ACT Acorn Consortium Page 45 of 80
D18 Expansion Options International CO2 Shipping
CO2 is carried in ships as a refrigerated liquid under pressure. Conditions used (Global CCS Institute, 2017). The transport infrastructure and build out of Acorn, in the current fleet are typically 15-20bara pressure and -30 to -40°C. Some CO2-SAPLING is one such project and includes international transport aspects. literature suggests CO2 shipping is most efficient at a lower pressure and Another is related to the Norwegian CCS Demonstration Project and proposes temperature, around 7bara and -50°C, as the density is greater under such to use international shipping to bring CO2 from export hubs to the port and conditions. However, the optimum choice of conditions for shipping in any CO2 storage facilities developed by that project, essentially a parallel proposal to the supply chain will depend on the upstream and downstream processes, in Acorn Project. The Norwegian project has progressed feasibility studies and is particular the energy required for liquefaction and for reconditioning for thought to have chosen CO2 conditions for ship transport of around 16bara and downstream operations, (Brownsort P. A., 2015a) -25°C, similar to the existing CO2 shipping fleet, (Graff, 2016).
Shipping has long been recognised as an alternative to pipeline transport of CO2 9.3 Shipping Assumptions in appropriate circumstances, (Doctor, et al., 2005). Studies have shown that The import of CO2, in the form of a refrigerated liquid, will be by ship into ship transport of CO2 can be cost competitive with new offshore pipelines, generally for smaller scales and longer distances. Shipping may have lower Peterhead Port. Section 12 outlines the methodology and assumptions used to financial risks than new offshore pipelines as it is inherently flexible with lower estimate the maximum capacity for CO2 import through Peterhead and what entry capital. This is particularly advantageous in the early and build-up phases affects that capacity. Section 12 also considers briefly the potential CO2 export of projects, where transport capacity can be increased in line with demand by locations that could supply CO2 to Peterhead from around the North Sea Basin. adding ships to the fleet, (Brownsort P. A., 2015a) This allows example scenarios to be suggested, which, in turn, allow estimation of some fundamental logistic data, such as the size and number of ships, round- In recent years, the focus of CCS interest in Europe has shifted somewhat from trip time and fuel consumption. large, power station-based proposals to projects based on industrial emission clusters, where capture capacity may increase sequentially. This may favour the A key assumption made when estimating maximum CO2 import capacity through Peterhead is that neither upstream nor downstream capacity is constrained. In development of shipping as a solution for CO2 transport, where routes from a other words, it is assumed that there are abundant supplies of captured CO2 number of CO2 export hubs can bring CO2 to different storage facilities in the North Sea Basin. available from export locations and that the transfer from Peterhead to St Fergus, and onwards, has greater capacity than the port. However, once the Four CO transport projects have been listed by the European Union as meeting 2 maximum capacity constrained by the port itself was established, one series of the criteria for European Projects of Common Interest (PCI) and so may be example scenarios examined a stepped build-up of CO2 import volume. eligible for funding under the Connecting Europe Facility. Each of these projects Another assumption underlying the work is that there are no insurmountable proposes to use CO2 shipping for at least some phases of their development, technical or regulatory constraints affecting bulk transport of liquid CO2; this
ACT Acorn Consortium Page 46 of 80
D18 Expansion Options International CO2 Shipping
aspect is not considered in the present work, but the assumption is supported If it were installed, the volume of shoreline buffer storage that would be needed by the body of existing literature, (Brownsort P. A., 2015a) to “smooth out” flow of CO2 into a downstream pipeline was estimated as 20,200m3 to cover average turnaround operations to 90,000m3 to cover a 24h 9.4 Shipping Conclusions delay between shipments.
Transport of liquefied CO2 by ship is an established operation and is under Previously published studies of eight potential CO2 export hubs around the North consideration by a number of CCS projects around the North Sea Basin. Ship Sea Basin were used to compile an indicative estimate of CO2 volumes that transport of CO2 is recognised as a viable alternative to pipeline transport in might be available for shipping at an arbitrary time in the future: over 65MT/yr appropriate circumstances. was estimated.
The maximum practical capacity for import of liquid CO2 through Peterhead Based on these potential CO2 export hubs, two different shipping scenarios were Port’s tanker jetty is estimated to be about 16.2MT/yr, assuming a CO2 tanker examined to supply the maximum CO2 import capacity of Peterhead. A scenario size of 50,000 DWT, the largest that can be accommodated at the jetty. This with a single export point at 800km distance from Peterhead would require five estimate is constrained only by factors relating to the port itself, that is, without ships of 50,000 DWT to satisfy the maximum capacity. A second scenario with applying any upstream supply constraints or downstream processing or two export points at 330 and 1000km distance would require between five and transport constraints. This capacity estimate is significantly higher than previous six ships of the same size; this scenario raises numerous options for varying values discussed for import through Peterhead, which have been constrained ship sizes and scheduling to satisfy the total transport capacity. by downstream pipeline capacity. Fuel consumption was estimated for the shipping cycles in these example Sensitivity analysis identified the main factors affecting capacity as the size of scenarios. The consumption was normalised as specific fuel consumption per the ship and the cargo offload rate (that is, the liquid CO2 pumping rate), with thousand tonnes of CO2 carried with values of 4.3 and 4.5T/kT-CO2, the time for ship turnaround also becoming important for smaller ships. Other respectively, estimated for the two scenarios. factors studied had relatively little influence on overall port capacity. However, Further modelling explored the system requirements of a series of scenarios while port unavailability due to bad weather has only a moderate influence with a stepped build-up in CO import quantity. The model allowed estimates to overall, it is a factor that would benefit from further clarification, particularly due 2 be made for the number of ships, number of offloading pumps, frequency of to its seasonal impact mostly during winter months. offloading and specific fuel consumption for a range of ship sizes (10,000 to It was concluded that the capital costs to provide buffer storage and associated 50,000 DWT) and a range of import quantities (2.5 to 20MT/yr), based on a systems would outweigh any advantage and that downstream transport systems single export point at 800km distance from Peterhead. Model outputs suggested should be designed to cope with interrupted flow of CO2. that import quantities of 5 to 10MT/yr are achievable with three or four ships of
ACT Acorn Consortium Page 47 of 80
D18 Expansion Options International CO2 Shipping
30,000 to 50,000 DWT size offloading less than once per day using one or two pumps, and with specific fuel consumption of 4.6 to 5.2T/kT-CO2. This range of throughput capacity is understood to cover the values being considered for initial pipeline transport development from Peterhead to St Fergus.
A few areas have been identified by this study where further work or clarification would be useful. These include: improving the definition of the capacity of pumps available to handle liquid CO2 at low temperatures; ensuring that designs for onward CO2 transport allow for interruptions in flow caused by gaps between ship deliveries; improving definition of weather-related downtime at the port and, in particular, how seasonality of downtime may affect upstream and downstream elements of the CCS chain.
ACT Acorn Consortium Page 48 of 80
D18 Expansion Options Conclusions
10.0 Conclusions
1. Due to its strategic position as a gas import facility and close to some of the new thermal power generation capacity to be installed in Central Scotland
best CO2 storage sites in the UK, St Fergus will be a key UK carbon capture (including CCEP or the Forth Ports biomass project) and for the CO2 & storage (CCS) hub location. emissions from them to be transported and stored, mitigating emissions or 2. Development of the Acorn CCS project enables the production of hydrogen creating negative emissions (in the case of biomass). at St Fergus by steam methane reforming natural gas with CCS, which 7. Development of the Acorn project is well aligned with key UK and Scottish would support decarbonisation of UK heat demand and support Government policy and strategy as stated in the Scottish Government’s decarbonisation of transport and power. Climate Change Action Plan, UK Industrial Strategy and UK Clean Growth 3. St Fergus is the best location in the UK to initiate hydrogen production by Plan.
decarbonising natural gas, due to an ability to commingle hydrogen into the 8. CO2 utilisation presents considerable opportunity for Scotland, partly grid initially at low concentrations. enabled by the Acorn project, with most development opportunities being at
4. CO2 can be imported via Peterhead Port and transferred to St Fergus in Grangemouth and smaller industrial emissions sites. liquid phase through a new purpose-built pipeline, thus enabling the UK to
make best use of its national storage assets and import/store CO2 from other countries.
5. Peterhead Port is strategically important in terms of CO2 storage, given its
location close to some of the UK’s largest CO2 storage sites and could
import up to 16MT/yr CO2 by ship from European ports. The port appears to have ample capacity for the levels of import envisaged for the early build out phases of the Acorn Project. For initial import quantities in the range of 5- 10MT/yr, a fleet of three or four vessels of 30,000-50,000 DWT size would
be required, a similar sized ship to that being considered by other CO2 ship transport projects in the North Sea region. 6. Feeder 10 provides an existing pipeline to enable effective decarbonisation of industrial emissions at Grangemouth, thus providing a low-cost route to decarbonise Scotland’s industry. Feeder 10 also provides the opportunity for
ACT Acorn Consortium Page 49 of 80
D18 Expansion Options References
11.0 References
BEIS. (2018). Updated Energy and Emission Projections 2017 - Annex M. Doctor, R., Palmer, A., Coleman, D. L., Davison, J., Hendriks, C., Kaarstad, O., . . . Austell, M. (2005). Transport of CO2. In IPCC Special Report on Brownsort, P. A. (2015a). Ship transport of CO2 for Enhanced Oil Recovery - Carbon Dioxide Carbon Capture and storage. Literature Survey. SCCS. Dotzenrod, N., Fong, S., Kenny, V., Leung, M., Nathal, M., Plaxco, J., . . . Brownsort, P. A. (2015b). Offshore offloading of CO₂ - Review of single point Zuehlke, E. (2015). Natural Gas to Hydrogen. Retrieved from mooring types and suitability. SCCS. https://processdesign.mccormick.northwestern.edu/index.php/Natural_ Brownsort, P. A., Haszeldine, R. S., & Scott, V. (2016). Reducing costs of carbon Gas_to_Hydrogen_(H) capture and storage by shared reuse of existing pipeline—Case study Element Energy. (2014). Demonstrating CO2 capture in the UK cement, of a CO2 capture cluster for industry and power in Scotland. chemicals, iron and steel and oil refining sectors by 2025: A Techno- International Journal of Greenhouse Gas Control, 130-138. economic Study. UK Government. Brownsort, P., Scott, V., & Sim, G. (2015). Carbon Dioxide Transport Plans for Energy Technologies Institute. (2016). Biomass Logistics in the UK: Request for Carbon Capture and Storage in the North Sea Region. SCCS Working Proposals. Paper. Engineering Toolbox. (2018). Carbon Dioxide Properties. Retrieved from The Cadent. (2017). The Liverpool-Manchester Hydrogen Cluster: A low cost, Engineering Toolbox: https://www.engineeringtoolbox.com/carbon- deliverable project. Cadent. dioxide-d_1000.html de Kler, R. (2015). (P. Brownsort, Interviewer) Flowserve. (2010, September). Pumps for CO2 Capture, Transportation and de Kler, R., Neele, F., Nienoord, M., Brownsort, P., Koornneef, J., Belfroid, Storage. Retrieved from www.flowserve.com: S., . . . Loeve, D. (2016). Transportation and unloading of CO2 by ship https://www.flowserve.com/sites/default/files/2016-07/fpd-17- - a comparative assessment. CATO. ea4_1.pdf
DNV GL. (Working Paper). Working paper - Hydrogen in the Natural Gas (1996). Gas Safety (Management) Regulations, Schedule 3, Part 1. Transport. GCCSI. (2017, October 3). Projects of Common Interest. Retrieved from GCCSI: https://www.globalccsinstitute.com/projects/projects-common-interest
ACT Acorn Consortium Page 50 of 80
D18 Expansion Options References
Giles, C. (2012). Peterhead CO2 Importation Feasibility Study. Petrofac Pale Blue Dot Energy. (2017). CO2 SAPLING Transport Infrastructure Project: Engineering Ltd. Project of Common Interest Application.
Global CCS Institute. (2017). Projects of Common Interest. Retrieved from Pale Blue Dot Energy Ltd. (2015). Industrial CCS on Teesside - The Business https://www.globalccsinstitute.com/projects/projects-common-interest Case.
Graff, O. (2016). CCS Demo Project Norway. GCCSI EMEA Members Meeting. Paterson, S. (2018). Personnal Communication. Oslo. Peterhead Port Authority. (2017). Introduction to Peterhead Port: Acorn CCS ICIS. (2002, February 4). BOC Brings North Tees, UK hydrogen plan onstream. kick-off meeting. ICIS. ICIS. Peterhead Port Authority. (2018). Peterhead Port Authority. Retrieved from Imperial College and Ecofys. (2016). Assessing the Potential of CO2 Utilisation Peterhead Port Authority: http://www.peterheadport.co.uk/ in the UK. Stakeholder Workshops. London. Petrofac. (2012). Peterhead CO2 Importation Feasibility Study. CO2DeepStore. KPMG. (2016). 2050 Energy Scenarios: The UK Gas Networks role in a 2050 RPS. (2016). Peterhead Port: Wave Climate data at Breakwaters. Belfast: RPS. whole energy system. Samadi, S., Lechtenböhmer, S., Schneider, C., Arnold, K., Fischedick, M., National Grid. (2017). Future Energy Scenarios. National Grid. Schüwer, D., & Pastowski, A. (2016). Decarbonization Pathways for the National Grid. (2017). Project Summary: HyDeploy. National Grid. Industrial Cluster of the Port of Rotterdam. Wuppertal Institut.
North Sea Basin Task Force. (2017). NSBTF strategic regional plan on CCS SCCS. (2018). Global CCS Map. Retrieved from Scottish Carbon Capture & transport infrastructure. Storage: http://www.sccs.org.uk/map
Northern Gas Networks. (2016). Leeds City Gate study report. SCOT Project. (2016). Joint Action Plan for Smart CO2 Transformation in Europe. EU 7th Framework Programme. NYSERDA. (2006). Hydrogen Production - Steam Methane Reforming Fact Sheet. Scottish Government. (2017). Draft Climate Change Plan: The draft third report on policies and proposals 207-2032. Edinburgh: Scottish Government. Pale Blue Dot Energy & Axis Well Technologies. (2016). Hamilton CO2 Storage Development Plan and Budget. ETI. Scottish Government. (2017). Scottish Energy Strategy: The Future of Energy in Scotland. Edinburgh: Scottish Government. Pale Blue Dot Energy & Axis Well Technologies. (2016). Strategic UK CO2 Storage Appraisal Project. Energy Technology Institute. SGN. (2017). NIA Project Registration and PEA Document: 100% Hydrogen.
ACT Acorn Consortium Page 51 of 80
D18 Expansion Options References
Skagestad, R., Eldrup, N., Hansen, H. R., Belfroid, S., Mathisen, A., Lach, A., & Haugen, H. A. (2014). Ship transport of CO2 - Status and Technology Gaps. Tel-Tek.
Summit Power. (2017). UK East Coast Carbon Capture & Storage (CCS) Study: the macroeconomic case for the UK.
The University of Sheffield, Pale Blue Dot Energy et al. (2016). Actions required to develop a roadmap towards a Carbon Dioxide Utilisation Strategy for Scotland. Scottish Enterprise.
UK Government. (2017). The Clean Growth Strategy. UK Government.
UK Hydrographic Office. (2016). Admiralty Chart 213, Fraserburgh to Newburgh.
Wilson, G. (2016). Seasonality of UK Energy Demand. The University of Sheffield.
ACT Acorn Consortium Page 52 of 80
D18 Expansion Options Annex 1: International CO2 Shipping Scenarios
12.0 Annex 1: International CO2 Shipping Scenarios
12.1 Summary for interrupted flow, improving definition of weather-related downtime and effects of downtime seasonality on other elements of the CCS chain. Transport of liquefied carbon dioxide (CO2) by ship is an established operation and is under consideration by a number of carbon capture and storage (CCS) Factor Unit Value Value Value Ship size DWT 50,000 30,000 10,000 projects around the North Sea Basin. Ship transport of CO2 is recognised as a Cargo Size T CO 40,000 24,000 8,000 viable alternative to pipeline transport in appropriate circumstances. 2 Max practical annual offloads offload/yr 406 543 820
Build-out options for the ACT Acorn Project include importing CO2 by ship into Maximum practical capacity MT/yr 16.2 13.0 6.6 Peterhead Port. Modelling for this study suggests the port has ample capacity Max practical offload offload/day 1.1 1.5 2.2 frequency for the import quantities envisaged for early build-out phases; a maximum Table 12-1: Base case model results; maximum capacity for different ship sizes practical capacity of 16.2MT/yr is estimated. Potential CO2 export hubs around the North Sea Basin could supply several times this quantity. 12.2 Introduction Shipping scenarios based on potential CO export hubs have explored the 2 12.2.1 The ACT Acorn Report number, size and fuel consumption of ships required to service the maximum practical capacity of the port, and also for a range of lower annual quantities. The current phase of the ACT Acorn Project is a feasibility study to prepare the way for development of a full-scale carbon capture and storage (CCS) project For import quantities in the 5 to 10MT/yr range, a fleet of three or four tankers centred at St Fergus gas terminal in North East Scotland. The initial of 30,000 to 50,000 deadweight tonnage (DWT) size will be required to service development phase is proposed to be a minimal full-scale facility, capturing routes from CO2 export hubs within the North Sea area. Specific fuel carbon dioxide (CO2) at St Fergus and using an existing offshore pipeline for consumptions of 4.6 to 5.2T/kT-CO2 are estimated for these scenarios. transport to an offshore location for permanent geological storage of CO2. This study, completed by PA Brownsort (SCCS), has increased the The feasibility study also addresses future build-out options for the Acorn understanding of factors affecting CO2 import by ship into Peterhead Port and development; additional sources of captured CO will be needed. One option, shown that the port has ample capacity for import levels for early build-out 2 considered in the ACT Acorn CO Supply Options and ACT Acorn Feeder 10 phases of the ACT Acorn Project. Areas for further consideration include 2 Business Case, would use an existing natural gas pipeline (Feeder 10) to definition of low-temperature CO2 pumps, design of downstream CO2 transport transport captured CO2 from Central Scotland to St Fergus. A second option
ACT Acorn Consortium Page 53 of 80
D18 Expansion Options Annex 1: International CO2 Shipping Scenarios
would be to import CO2 by ship from other industrial clusters where CO2 quantity of CO2 that might be imported by ship through Peterhead Port is, captured might be deployed to the Port of Peterhead, which is close to St therefore, important to the case for expansion of the Acorn Project. Fergus. Potential build-out options for the Acorn Project are shown 12.2.2 CO2 transport by ship schematically in Figure 12-1.
The transport of CO2 in bulk by ship is established in European waters as part
of the international trade in CO2 for industrial, food and drink, and other uses.
The CO2 is, in general, obtained as a by-product of hydrogen production as part
of the ammonia synthesis process. However, the scale of the current CO2 market is small (around 3MT/yr) compared to the envisaged scale of the CCS industry at, potentially, tens to hundreds of millions of tonnes per year. There
are currently only a small number of existing CO2 transport ships and these are of low capacity, in the range of 900 to 1,800 tonnes (T), (Brownsort P. A., 2015a).
CO2 is carried in ships as a refrigerated liquid under pressure. Conditions used in the current fleet are typically 15-20bara pressure and -30 to -40°C. Some
literature suggests CO2 shipping is most efficient at a lower pressure and temperature, around 7bara and -50°C, as the density is greater under such
conditions. However, the optimum choice of conditions for shipping in any CO2 supply chain will depend on the upstream and downstream processes, in particular the energy required for liquefaction and for reconditioning for Figure 12-1: Indicative Acorn build-out scenarios downstream operations, (Brownsort P. A., 2015a).
Since the closure of fossil fuel burning power stations in Central Scotland, the Shipping has long been recognised as an alternative to pipeline transport of CO2 quantity of CO2 that might realistically be captured in the area has reduced and in appropriate circumstances, (Doctor, et al., 2005). Studies have shown that is now reasonably well matched to the capacity of Feeder 10, which is ship transport of CO2 can be cost competitive with new offshore pipelines, approximately 7 to 10 million tonnes per year (MT/yr) of CO2. (Brownsort, generally for smaller scales and longer distances. Shipping may have lower Haszeldine, & Scott, 2016) However, the developed capacity of the Acorn financial risks than new offshore pipelines as it is inherently flexible with lower Project has potential to be much higher than this. An understanding of the entry capital. This is particularly advantageous in the early and build-up phases
ACT Acorn Consortium Page 54 of 80
D18 Expansion Options Annex 1: International CO2 Shipping Scenarios
of projects, where transport capacity can be increased in line with demand by Central North Sea. Peterhead Port Authority (PPA) and companies sited at the adding ships to the fleet, (Brownsort P. A., 2015a). port have recently made large investments to accommodate increasing activity from the renewable energy and decommissioning markets, as well as for 12.2.3 Current project interest in CO2 shipping increasing fishing activity, (Peterhead Port Authority, 2018). The PPA is open to In recent years, the focus of CCS interest in Europe has shifted somewhat from the possibility of a role in a future CCS industry, (Paterson, 2018). large, power station-based proposals to projects based on industrial emission The port has an existing tanker jetty built for the import of fuel oil to Peterhead clusters, where capture capacity may increase sequentially. This may favour the Power Station, which is sited about 1.5km to the south of the port. The power development of shipping as a solution for CO2 transport, where routes from a station converted to gas some time ago and the tanker jetty has seen no regular number of CO2 export hubs can bring CO2 to different storage facilities in the use for bulk fluids since. The potential exists for redeploying this jetty for the North Sea Basin. import of bulk CO2 by ship.
Four CO2 transport projects have been listed by the European Union as meeting the criteria for European Projects of Common Interest (PCI) and so may be eligible for funding under the Connecting Europe Facility. Each of these projects proposes to use CO2 shipping for at least some phases of their development,
(Global CCS Institute, 2017). One of the projects, CO2-SAPLING, concerns the international transport aspects of the ACT Acorn Project; for which this study is relevant. Another is related to the Norwegian CCS Demonstration Project and proposes to use international shipping to bring CO2 from export hubs to the port and storage facilities developed by that project, essentially a parallel proposal to the Acorn Project. The Norwegian project has progressed feasibility studies and is thought to have chosen CO2 conditions for ship transport of around
16bara and -25 °C, similar to the existing CO2 shipping fleet, (Graff, 2016).
12.2.4 Peterhead Port
Peterhead is the largest fishing port in the UK in terms of fish landings and it has served an important, long-term role in the development and servicing of the North Sea oil and gas industry, being the closest large port to many fields in the Figure 12-2: Peterhead Port from the south, tanker jetty centre-right
ACT Acorn Consortium Page 55 of 80
D18 Expansion Options Annex 1: International CO2 Shipping Scenarios
Petrofac Engineering Ltd carried out a previous study for CO2DeepStore in 2012 scenarios to be suggested, which, in turn, allow estimation of some fundamental to examine the potential for use of the tanker jetty for CO2 import; it also logistic data, such as the size and number of ships, round-trip time and fuel considered offshore offloading from ships direct to a platform at a storage site, consumption. (Giles, 2012). The study considered reuse of existing pipelines running to the This International Shipping report does not consider in any detail the transfer of power station and from there to St Fergus for downstream CO2 transport. It was CO2 from Peterhead Port to St Fergus for onward transport to a CO2 storage found that use of these existing lines constrained the CO throughput capacity 2 facility; this is covered in Section 8.0. Neither is reconditioning process to 1.2 to 1.5MT/yr. Scenarios using new pipelines were also examined and found equipment, to warm and pressurise the CO2 for pipeline transport, considered to have lower estimated costs and higher capacities, at up to 5.7MT/yr; the in this report other than in terms of the pumping capacity required at Peterhead offshore offloading scenario had similar costs and capacity. for ship offloading. The Petrofac study forms an important foundation of the Acorn project work. 12.3.3 Assumptions However, the present study focuses on the constraints of the port itself and the shipping service as described below. One main assumption made when estimating maximum CO2 import capacity through Peterhead is that neither upstream nor downstream capacity is 12.3 Scope constrained. In other words, it is assumed that there are abundant supplies of 12.3.1 Purpose captured CO2 available from export locations (this is explored briefly) and that the transfer from Peterhead to St Fergus, and onwards, has greater capacity The purpose of this report is to provide information on the transport of bulk CO2 than the port. However, once the maximum capacity constrained by the port by ship from exporting hubs to Peterhead Port. This information will form one itself was established, one series of example scenarios examined a stepped element of the ACT Acorn Expansion Options report, which considers expansion build-up of CO2 import volume. options beyond the initial project development phase. Another assumption underlying the work of this study is that there are no 12.3.2 Scope insurmountable technical or regulatory constraints affecting bulk transport of
liquid CO2; this aspect is not considered in the present work but the assumption The scope is mostly focused on the import of CO2, in the form of a refrigerated is supported by the body of existing literature, (Brownsort P. A., 2015a). liquid, by ship into Peterhead Port. It aims to estimate the maximum capacity for
CO2 import through Peterhead and to understand what affects that capacity. A series of further detailed and technical assumptions are described in later
This study also considers briefly the potential CO2 export locations that could sections. One such area of assumption is around shipping and port system supply CO2 to Peterhead from around the North Sea Basin. This allows example availability, or “up-time”, which depends on a number of individual availability
ACT Acorn Consortium Page 56 of 80
D18 Expansion Options Annex 1: International CO2 Shipping Scenarios
factors. An overarching assumption is that, if the transport facilities are not Estimates of potential future CO2 availability at possible export hubs were taken available for a period, such as during a prolonged period of bad weather in from a number of literature sources describing studies of industrial emission winter, there is a way of dealing with the effect on the upstream and downstream clusters near UK and European ports; sources are given in Table 12-5. Shipping elements of the whole CCS supply chain. route distances were estimated using Google Maps. 12.4 Data Sources, Modelling and Analysis Methods 12.4.2 Model structure
12.4.1 Main data sources Modelling was carried out in two phases, with the first divided into four sections. All the modelling was performed using Excel spreadsheets; excerpts are given The data used here come mostly from a small number of key literature reports, in Annex 2: International Shipping Data where appropriate for illustration. plus information obtained directly from the PPA. 12.4.2.1 Initial modelling phase General information on CO shipping is drawn from a literature survey carried 2 This phase was based on the constraints of Peterhead Port only, assuming out in 2014, (Brownsort P. A., 2015a). upstream CO2 supply and downstream CO2 transport and storage were Specific data on shipping comes from two main sources. Firstly, a study by Tel- unconstrained.
Tek for Gassnova on status and technology gaps for CO2 shipping, (Skagestad, • Estimation of maximum CO2 throughput constrained only by factors et al., 2014). Secondly, a project under the Dutch CATO programme, (de Kler, relating to the port. et al., 2016), including unpublished personal communication with the project • Exploration of the effect of providing a buffer storage volume at the manager, (de Kler, et al., 2016). port.
Information regarding the transfer of CO2 from Peterhead to St Fergus comes • Estimation of upstream supply potential at different export hubs, from the Petrofac report mentioned above (Giles, 2012). estimation of voyage distance, implication for number of ships in two example scenarios. Data and information on Peterhead Port and the tanker jetty come from the PPA • Estimation of fuel consumption for shipping cycle for the same two website, (Peterhead Port Authority, 2018), and through personal communication example scenarios. with Stephen Paterson, Deputy Chief Executive of the PPA, (Paterson, 2018). A report on wave height climate at the harbour entrance was also provided by A block diagram showing the relationships between the main inputs and outputs the port authority, (RPS, 2016). and between sections of the model is given in Figure 12-3.
The base input data used in modelling conducted for this study are given in Table 13-1 to Table 13-7 in Section 13.
ACT Acorn Consortium Page 57 of 80
D18 Expansion Options Annex 1: International CO2 Shipping Scenarios
12.4.3 Modelling of build-up cases
The basic throughput capacity model was adapted to explore the effect of a stepped build-up of throughput, and of the size of ships used, on the number of ships required, the offloading frequency, the number of offloading pumps needed and the fuel consumption of the shipping cycles.
A block diagram of the adapted model for the build-up cases is given in Figure 12-4.
ACT Acorn Consortium Page 58 of 80
D18 Expansion Options Annex 1: International CO2 Shipping Scenarios
Figure 12-3: Block diagram of initial model structure
ACT Acorn Consortium Page 59 of 80
D18 Expansion Options Annex 1: International CO2 Shipping Scenarios
Figure 12-4: Block diagram of capacity build-up model
ACT Acorn Consortium Page 60 of 80
D18 Expansion Options Annex 1: International CO2 Shipping Scenarios
12.4.4 Sensitivity Analysis 12.5 Model Outputs, Shipping Scenarios, Discussion
A limited sensitivity analysis was performed on the port throughput model. 12.5.1 Peterhead Port throughput capacity Sensitivity of port capacity to ship size was examined over a range up to a size greater than the stated limit for the tanker jetty. Sensitivity of port capacity to In the Petrofac study of CO2 import through Peterhead, the maximum throughput variation of the main model inputs was then examined for three selected ship rate into Peterhead Port was not addressed, (Giles, 2012). The highest sizes, with low and high input values treated individually. Sensitivity to combined throughput considered in that study was 17,500 tonnes per day (T/day) of CO2, variance was examined for one ship size, that is, setting all variables to minimise which is a nominal 6.4MT/yr but given in that report as 5.7MT/yr, implying some or to maximise port throughput capacity. a90% factor constraining system availability was applied. The scenario with that throughput was constrained by the size of the downstream pipeline for transfer 12.4.5 Main Outputs to St Fergus and further offshore; a new 20-inch ambient temperature liquid The main outputs of the modelling and analysis, as described in the following pipeline was assumed. If there were no such constraints downstream, what section, are: would be the maximum throughput that could be achieved by the port? The port throughput model outlined above was used to examine this question. A snapshot • An estimate of the theoretical and likely practical maximum of the model spreadsheet showing input data values set to predict maximum throughput capacity for bulk liquid CO2 import through the Peterhead throughput is given in Figure 12-5. A brief explanation of some of the input tanker jetty with an understanding of the main factors that affect this. variables follows. • A view on the need for shoreline buffer storage of CO2 at Peterhead.
• A rough-cut, indicative estimate for potential CO2 export volumes from ports around the North Sea Basin. • An indication of the number and size of ships required for two
example scenarios for CO2 import to Peterhead. • An estimate of the fuel consumption for the shipping cycles in the example scenarios.
• A picture of the requirements for building up the volume of CO2 imported to Peterhead in terms of size and number of ships, number of offloading pumps, frequency of offloading, and fuel consumption for the shipping cycles.
ACT Acorn Consortium Page 61 of 80
D18 Expansion Options Annex 1: International CO2 Shipping Scenarios
Factor Unit Value Observation
Ship deadweight DWT 50,000 Non-cargo allowance % 20 Cargo weight t 40,000 Cargo temperature °C -50 -30 or -50, not used but sets density CO2 density kg/m3 1156 1077 or 1156 for the two temperatures Cargo volume m3 34,602
Tidal gate, average delay h 3 Average delay for random arrival times Port entry and docking time h 2 Offloading rate m3/h 2883 Key sensitivity and uncertainty Offloading time h 12.00 Undocking and port exit time h 2 Turnround time h 19.00 Theoretical offload frequency offload/day 1.26 Theoretical annual offloads offload/yr 461 Theoretical annual throughput Mt/yr 18.44
Combined weather availability % 91.8 Includes berthing and tug connection factors Tanker jetty availability % 98.6 Tug services availablity % 97.3 Allows for pilot and tug availability Total port availability % 88.0
Max practical offload frequency offload/day 1.11 Max practical annual offloads offload/yr 406 Max practical throughput Mt/yr 16.24
Figure 12-5: Port model for maximum practical throughput
ACT Acorn Consortium Page 62 of 80
D18 Expansion Options Annex 1: International CO2 Shipping Scenarios
12.5.1.1 Input variables Information from discussions with the PPA was used to set the variables relating The maximum size of ship that the tanker jetty can accommodate is given by the to ship entry and exit times and port availability, (Paterson, 2018). The largest PPA in terms of deadweight tonnage (DWT). This term includes the weight of all ship size was assumed, that is 50,000 DWT; these larger tankers using the jetty removable materials on the ship, such as crew, fuel, water and equipment, not will require a pilot for entry to the port and a tug for assistance with manoeuvring just the cargo. An arbitrary allowance, adapted from the Petrofac study, (Giles, and berthing. Entry will be restricted to times around slack water due to tidal 2012), for non-cargo materials of 20% of DWT was applied to estimate the cargo streams running at up to 2.1 knots off the entrance, (UK Hydrographic Office, weight. 2016). An average delay of 3h was allowed to account for this “tidal gate”, assuming random ship arrival times. In practice, ships would vary their approach The density of liquid CO2 varies with temperature; two temperature conditions speed to arrive at a suitable time for entry. Achievable port entry time from ship were used in this study, -50 and -30°C, from which the CO2 density was approach to berthing is said to be 2h; it is assumed exit time is the same. For determined from literature, (Engineering Toolbox, 2018).. From the cargo weight smaller ships, these times may be less, but this has not been considered here. and density, the cargo volume was calculated, which, together with offloading pump volumetric capacity, allowed calculation of offloading time. Port control services are available continuously. A specific outage allowance of 5 days each year was made for maintenance affecting use of the tanker jetty; a The capacity of available pumps for dense-phase CO2 was reviewed in the 10-day outage allowance was made for tug and pilot service availability. Bad Petrofac study and found not to be a constraint, (Giles, 2012). A limited search weather prevents safe berthing at the tanker jetty for typically 7 to 10 days each for the current work confirmed that single pumps with capacities up to 3,635 year; however, the period during which a towline cannot be safely connected by 3 cubic metres per hour (m /h) are available, specified for CO2 transport, a tug is longer, but coincident. A bad weather allowance totalling 30 days each (Flowserve, 2010). However, it is not clear that these larger pumps are rated for year was assumed. This is an arbitrary figure set as a compromise between an low temperatures. In equipment lists included in the Petrofac study, the largest availability estimate of 94.6% (about 20 days outage) based on indicative wave- pump size listed has a capacity of 1,069m3/h and a temperature rating of -60°C height information, (RPS, 2016)and an experience-based estimate from the to +50°C (this is thought to be based on an actual equipment specification) and PPA of up to 15% (about 55 days outage (Paterson, 2018). two such pumps were assumed in one example scenario (Scenario 17), (Giles, 2012). The value for pump capacity used in the present estimate was taken from The combination of weather, maintenance and services availability factors have the CATO ship transport project, (de Kler, et al., 2016) and relates to an arbitrary the effect of downrating the port capacity from a “theoretical” value to a 15-hour (h) offload of a 50,000T cargo. It is assumed that use of multiple pumps “practical” value, with the weather factor having the greatest effect in the in parallel for offloading is possible. estimate shown.
ACT Acorn Consortium Page 63 of 80
D18 Expansion Options Annex 1: International CO2 Shipping Scenarios
12.5.1.2 Model outputs Figure 12-5 the size of ship, in terms of deadweight tonnage, was varied from
The main outputs of this basic estimate of potential CO2 throughput capacity of 5,000 to 100,000 DWT. The resulting output values for practical throughput Peterhead, constrained only by factors relating to the port itself, are shown in capacity are plotted in Figure 12-6. Table 12-2. As well as results for the case with the largest ship size, 50,000 DWT, Table 12-2 gives model results for 30,000 and 10,000 DWT tankers as Port throughput capacity vs ship size base cases for the sensitivity analysis described in Section 12.5.1.3. 25.0
Factor Unit Value Value Value 20.0 Mt/yr
Ship size DWT 50,000 30,000 10,000 Theoretical offload frequency offload/day 1.3 1.7 2.6 15.0 throughput,
Theoretical annual offloads offload/yr 461 617 932 cal 10.0 prac
Theoretical annual throughput MT/yr 18.4 14.8 7.5 Maximum practical offload offload/day 1.1 1.5 2.2 frequency
Maximum 5.0 Maximum practical annual offload/yr 406 543 820 offloads Maximum practical throughput MT/yr 16.2 13.0 6.6 0.0 - 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000 100,000 Ship deadweight, DWT Table 12-2: Estimated maximum CO2 throughput capacity for Peterhead Port
These results suggest the capacity of the port itself is significantly higher than Figure 12-6: Effect of ship size on port throughput capacity discussed in the previous study (5.7MT/yr (Giles, 2012), which was constrained This shows that, as the size of each load increases, the capacity increases but by downstream transport capacity. A practical throughput capacity of over tends towards a plateau. This is because the effect of the time between each 16MT/yr is suggested in the present work. This estimate is considered realistic load declines and the plot trends towards the offloading pump capacity adjusted given the degree of detail of information included; however, it does involve a by the combined port availability factor. The limitation of ship size in Peterhead delivery frequency of more than one ship each day with rapid offloading and to 50,000 DWT is, therefore, not a great constraint. efficient turnaround. Using the input figures shown in Figure 12-5 as a base case and changing the 12.5.1.3 Sensitivity analysis on port throughput model – individual variance main variables to high and low values independently, allowed the sensitivity of The port throughput model was used to explore the sensitivity of port capacity the maximum throughput estimate to each variable to be tested. This analysis to changes in the main variables used. Starting with the input figures shown in
ACT Acorn Consortium Page 64 of 80
D18 Expansion Options Annex 1: International CO2 Shipping Scenarios
was carried out around bases of three ship sizes: 50,000, 30,000 and 10,000 Table 12-3 also shows the sensitivity analysis output for the 50,000 DWT case, DWT. The variations applied are shown in Table 12-3, mostly ±20% but with the both as the capacity response in MT/yr resulting from each variance and as a extreme estimates for weather factor described in Section 12.5.1.1, and a one- normalised response in percentage change from the base capacity value. sided variance to a potential higher cargo temperature of -30°C. Sensitivities to Similar analyses were carried out based on 30,000 and 10,000 DWT ships. The the tanker jetty availability and tug services availability were not examined as normalised responses are plotted for the 50,000, 30,000 and 10,000 DWT cases these would have lesser effects. in Figure 12-7, Figure 12-8 and Figure 12-9, respectively.
Factor, variance Unit Base value Variance Outcome, MT/yr Normalised response % change from base Response Response Response to low Response to high Low High to low to high variance variance variance variance Ship deadweight, ±20% DWT 50,000 40,000 60,000 14.9 17.3 -8.4 6.5 Non-cargo allowance, ±20% % 20 16 24 16.5 15.9 1.8 -1.9 Cargo temperature, +20°C (i.e.-30°C) °C -50 -30 15.5 -4.4 Port entry/exit, docking/undocking, ±20% h 2 1.6 2.4 16.9 15.6 4.4 -4.0 Offloading rate, ±20% m3/h 2883 2306 3460 14.0 18.1 -13.6 11.8 Weather availability, extreme estimates % 91.8 85.0 94.6 15.0 16.7 -7.4 3.1 Maximum practical throughput MT/yr 16.2
Table 12-3: Sensitivity to variance of inputs, 50,000 DWT case
ACT Acorn Consortium Page 65 of 80
D18 Expansion Options Annex 1: International CO2 Shipping Scenarios
Sensi vity of maximum prac cal throughput, Sensi vity of maximum prac cal throughput, 50,000 DWT case 30,000 DWT case
3.1 3.1 Weather availability, extreme es mates -7.4 Weather availability, extreme es mates -7.4 11.8 9.2 Offloading rate, ± 20% -13.6 Offloading rate, ± 20% -11.3 -4.0 -5.3 Port entry/exit, docking/undocking, ± 20% 4.4 Port entry/exit, docking/undocking, ± 20% 6.0
Cargo temperature, +20°C (i.e.-30°C) -4.4 Cargo temperature, +20°C (i.e.-30°C) -3.6
-1.9 -2.5 Non-cargo allowance, ± 20% 1.8 Non-cargo allowance, ± 20% 2.4 6.5 9.0 Ship deadweight, ± 20% -8.4 Ship deadweight, ± 20% -11.0
-20.0 -10.0 0.0 10.0 20.0 -20.0 -10.0 0.0 10.0 20.0 % Response to variance % Response to variance
Response to high variance Response to low variance Response to high variance Response to low variance
Figure 12-7: Sensitivity for 50,000 DWT case Figure 12-8: Sensitivity for 30,000 DWT case
ACT Acorn Consortium Page 66 of 80
D18 Expansion Options Annex 1: International CO2 Shipping Scenarios
in any of the cases despite the large weather outage (55 days) that the low Sensi vity of maximum prac cal throughput, variance represents. 10,000 DWT case In all cases, the effect of a warmer cargo is less significant, implying that there
3.1 is little capacity penalty for the reduced cargo density resulting from a reduced Weather availability, extreme es mates -7.4 degree of refrigeration of the liquid CO . This may have benefits for operating 4.4 2 Offloading rate, ± 20% -6.0 expenses and energy consumption, and supports the decision made by the -7.8 Port entry/exit, docking/undocking, ± 20% 9.3 Norwegian CCS Demonstration Project to use a warmer temperature and higher -1.8 Cargo temperature, +20°C (i.e.-30°C) pressure for CO2 transport, (Graff, 2016).
-3.8 Non-cargo allowance, ± 20% 3.7 12.5.1.4 Sensitivity analysis on port throughput model – combined variance 14.2 Ship deadweight, ± 20% -15.7 A further sensitivity analysis was carried out to examine the effect of all the variations modelled above acting together to either minimise or maximise the -20.0 -10.0 0.0 10.0 20.0 % Response to variance port throughput capacity using the single case of a 50,0000 DWT CO2 tanker. Against the base case capacity estimate of 16.2MT/yr, the response to Response to high variance Response to low variance combining the minimising variances was 10.8MT/yr, and to the maximising variances, 21.3MT/yr. In percentage terms this is a range from -33.3% to Figure 12-9: Sensitivity for 10,000 DWT +31.3%, the asymmetry being due to the one-sided variance applied for cargo The sensitivity to offloading rate is high for the larger ships, highlighting the temperature. While this is not the same as an error analysis on the calculations, importance of understanding the scope of pump capacity for cold liquid CO2. For this result, taken together with the sensitivities to individual variances discussed smaller ships, the effect of port entry and exit times become more important as above, suggest that the model estimate is reasonably robust. the delivery frequency increases to achieve the same capacity. For the larger 12.5.1.5 Port throughput capacity model – summary ship sizes, the port turnaround time is less important, reflecting the lower modelled delivery frequency. The effect of ship size is greater for a smaller ship, The model calculations described indicate that, in the absence of upstream which relates to the shape of the plot shown in Figure 12-6. supply constraints or downstream processing or transport constraints, the maximum capacity for import of bulk liquid CO2 through Peterhead Port tanker The sensitivity to the weather factor, when normalised, is the same for each ship jetty is about 16.2MT/yr, assuming a CO2 tanker size of 50,000 DWT, the largest size, reflecting the simple calculation involved. It is not the dominant sensitivity that can be accommodated at the jetty. This is significantly higher than the
ACT Acorn Consortium Page 67 of 80
D18 Expansion Options Annex 1: International CO2 Shipping Scenarios
5.7MT/yr capacity mentioned in the previous study, (Giles, 2012), which was they generally need to be designed for interrupted flow. This study briefly constrained downstream. examined the need for buffer storage capacity near to the Peterhead Port tanker jetty. The main factors affecting the throughput capacity are the size of the ship and the cargo offload rate, that is, the liquid CO2 pumping rate, with the time for ship It was assumed that a constant rate of CO2 supply was required to the pipeline turn-round also becoming important for smaller ships. These findings are connecting reconditioning equipment sited near the jetty to St Fergus. The time intuitive and are clearly supported by the sensitivity analyses. Of other factors for undocking and the exit of one ship then entry and berthing of the next means studied, the cargo temperature and the proportion of ship deadweight not there will always be an interruption in supply from the ship offloading operation available for cargo each have relatively little influence on overall port capacity. between deliveries. In addition, there may be time waiting for slack tide, plus any Port unavailability due to bad weather is a factor that would benefit further “slot time” waiting for the next ship to approach. The total time gap between clarification, but it has only a moderate influence overall. The times when the offloading operations multiplied by the pumping rate gives the buffer capacity port is unavailable due to bad weather will, however, mostly occur during the that would be needed to maintain a constant flow of CO2 to the reconditioning winter months. This may have an impact on the overall capture, transport and equipment. storage chain if CO2 cannot be imported for significant periods during the winter. Using the base model case for a 50,000 DWT CO2 tanker, with data as shown 12.5.2 Buffer storage in Figure 12-5, the capacity required to cover just the entry and exit times is around 11,500m3 (at liquid shipping conditions, -50°C). Assuming addition of the For transport of liquid CO2 by ship, it is generally assumed that buffer storage average tidal delay increases this to around 20,200m3. Further “slot time” waiting will be required near the ship loading point. This is because the CO capture and 2 for the next ship to approach increases the buffer capacity requirement in a liquefaction facilities will be continuous processes, while the shipping leg is linear manner, as shown in Figure 12-10: the plot gradient is the pump rate and essentially a batch process. Therefore, a buffer storage with capacity to fill one the intercept is the volume with no “slot time”. For a 24h slot, the capacity ship is generally assumed as a minimum for the loading point, (Brownsort P. A., required would be nearly 90,000m3. 2015a). For the ship offloading point, the need for buffer storage depends on the downstream operation. If a continuous flow of CO2 is required downstream, such as might be the case for some injection well designs with direct delivery of CO2 by ship to the well location, then buffer storage at the ship offloading point may be required, (Brownsort P. A., 2015b). For delivery to a downstream pipeline system, the need for buffer storage near the ship offloading point is less clear as there is no requirement for continuous flow into a pipeline system; indeed,
ACT Acorn Consortium Page 68 of 80
D18 Expansion Options Annex 1: International CO2 Shipping Scenarios
maximum flow. Possible advantages and disadvantages of having a shoreline Varying slot me buffer capacity at Peterhead are summarised in Table 12-4. 100000 Pros Cons 90000 Reduced Capex for heat exchanger Increased Capex for buffer storage 80000
70000 Reduced Opex for heat exchanger Increased Capex for pressure
m3 60000 (warming water supply) equalization loop on storage 50000 40000
Buffer, Reduced Opex for main pump while Increased Capex for diverter valves 30000 drawing from buffer and control systems 20000 10000 Reduced Capex for pipeline Space requirement for storage 0 0 5 10 15 20 25 Table 12-4: Possible pros and cons of buffer storage Slot, h y = 2883x + 20181 On balance, it seems unlikely that the advantages, which arise only from reduced equipment duties, would outweigh the costs of additional facilities and Figure 12-10: Buffer capacity required with increasing delay between ship arrivals equipment for buffer storage. In addition, there are unknown implications from planning control and safety factors that would need to be considered for large- These are quite large storage volumes. By comparison, the current liquid CO2 scale buffer storage of CO2 at Peterhead. These were mentioned in the earlier storage capacity at Yara’s CO2 import terminal on the Thames at Purfleet, is around 3,300m3 in twelve large bullet tanks (approximately 22 x 4m cylinders). Petrofac study but without detail, (Giles, 2012). The volumes indicated in the present estimate suggest one or more large 12.5.3 Potential CO2 supply from North Sea Basin ports, example spherical storages would be appropriate. shipping scenarios and fuel consumption
The advantages of having buffer capacity might be that the CO2 reconditioning For the modelling above it was assumed that an unconstrained supply of bulk and transport system downstream of the offloading pumps could run at a lower liquid CO2 can be sourced by ship from exporting locations around the North flow rate by using the buffer to average out the flow to match the average Sea Basin. This section describes a rough-cut capacity estimate for captured delivery rate. However, the offloading pumps would still be sized to minimise CO2 emissions from industrial clusters with ports having access to the North ship offload time, and as any delay between deliveries is likely to be largely Sea. The estimate relies heavily on previous work and is not comprehensive; unpredictable, it is likely that the whole system would still be designed for other clusters might be equally appropriate. In most cases it does not consider
ACT Acorn Consortium Page 69 of 80
D18 Expansion Options Annex 1: International CO2 Shipping Scenarios
the proportion of CO2 that might be captured in a cluster or the difficulty of Google Maps and the indicative CO2 supply potential of each location was establishing a large CO2 capture and collection network. estimated. These data are shown in Table 12-5, along with source references and notes on the manner of estimate. Eight potential CO2 exporting locations were identified; their distance by sea from Peterhead was measured (rounded up to the next 10 km) using the tool on
Indicative Export Distance to Site supply Source reference Notes hub Peterhead potential
km NM MT-CO2/yr Grange 13 large industrial emitters, adjusted for practical capture rates, Forth 230 124 4.2 (Brownsort, Haszeldine, & Scott, 2016) mouth not including CCEP. Teespo Teessid Adjusted from Teesside total of 11 Mt with 65% from SSI rt 330 178 3.9 (Pale Blue Dot Energy Ltd., 2015) e steelworks, now closed. (Yara) (Brownsort, Scott, & Sim, 2015) Figure for "potentially available other industrial sources", i.e. not Humber Saltend 500 270 9 (Referencing National Grid, 2015) defunct power + CCS projects. Purfleet (Brownsort, Scott, & Sim, 2015) Half total estimated for "cluster of eight existing large emitters Thames 800 432 22 (Yara) (Referencing E.On, 2009) and two new power stations", i.e. assuming no new stations. Le Tidal (Brownsort, Scott, & Sim, 2015) 1000 540 13 Five networked capture sites studied in COCATE Project. Havre basin (Referencing Roussanaly et al, 2013) Rotterd Beerka Estimate for capture in 2030 in Technological Progress 730 394 8 (Samadi, et al., 2016) am naal scenario, from Fig 13 in Wupertal Institut report. Skagerr ak- Gothen (Brownsort, Scott, & Sim, 2015) 850 459 6 Estimate for capture from three major industrial clusters. Kattega burg (Referencing Tel-Tek, 2012) t Grenlan Porsgru 770 416 1.5 (SCCS, 2018) Total of three plants in current Norwegian CCS Project. d nn Total 67.6
Table 12-5: Indicative CO2 supply potential of North Sea export hub
ACT Acorn Consortium Page 70 of 80
D18 Expansion Options Annex 1: International CO2 Shipping Scenarios
While not claiming any degree of accuracy, these indicative figures for CO2 of the model used for the base case is shown in Figure 12-11 for a fleet of 50,000 supply potential, totalling over 65MT/yr, support the assumption that absolute DWT tankers with CO2 cargo at -50°C. upstream supply can be considered unconstrained relative to Peterhead Port Factor Unit Value Observation maximum throughput capacity. Theoretical offload frequency offload/day 1.26 Linked Theoretical annual offloads offload/yr 461 Not used The ACT Acorn CO2 Supply Options report considered a scenario for CO2 import Theoretical annual throughput Mt/yr 18.44 Not used via Peterhead which included some CO from Teesside and Rotterdam Max practical offload frequency offload/day 1.11 Linked 2 Max practical annual offloads offload/yr 406 Not used delivered on a phased basis increasing to a volume of 5.4Mt/y. Max practical throughput Mt/yr 16.24 Not used
Voyage distance km 800 12.5.3.1 Example shipping scenarios Cruising speed km/h 26 Cruising speed knots 14.0 Not used, agrees with Tel-Tek data There are many combinations of shipping scenarios that could supply Time at sea h 30.8 Each leg, doubled in round-trip calculation Peterhead’s maximum throughput, estimated above as 16.2MT/yr, from the Export turnround and loading time h 18 Import turnround and offload time h 19.00 Linked industrial clusters listed in Table 12-5. Two example scenarios were chosen and Round-trip time h 98.5 Assumes laden and unladen speeds the same Round-trip time days 4.1 these were used to calculate the number of ships required to service the Export facility availability % 95 modelled export hubs and to estimate fuel consumption of these shipping Ship availability % 98 operations. Having established a method for these estimates, there is no clear Combined despatch availability % 93.1 value in examining further arbitrary scenarios at this stage and no further Number of ships, theoretical rate number 5.6 Number of ships, practical rate number 4.9 scenarios were developed. Figure 12-11: Supply model for single export point shipping scenario, 50,000 DWT Single export point shipping scenario ships, cargo at -50°C
The first was a simple, single-route shipping scenario based on the distance The model develops the time profile of the shipping leg to determine the round- from the Thames to Peterhead. This was chosen on the basis of the potential trip time, then calculates the number of ships required from the product of the supply volumes estimated above, with only the Thames cluster having greater round-trip time and the offload frequency at Peterhead, all modified by the estimated volume than the maximum capacity of Peterhead. However, clearly combined availability of the export facility and the ships themselves. The number other clusters might reach this position, including Rotterdam, Le Havre and the of ships for the theoretical and the maximum practical offload frequency are both Humber, depending on development of CCS in their industrial hinterlands. calculated (the latter taking account of combined availability at Peterhead)
This single export point scenario was used to model the number of ships resulting in a range of number of ships. In practice, to achieve the maximum required to service the maximum throughput capacity of Peterhead. A snapshot practical throughput at Peterhead, the next whole number of ships up from the lower figure would be required.
ACT Acorn Consortium Page 71 of 80
D18 Expansion Options Annex 1: International CO2 Shipping Scenarios
For the single export point scenario, the input figures were varied to model a Export Export cargo temperature of -30°C and a ship size of 30,000 DWT, leading to the four hub 1 hub 2 Capacity share % 75 25 sub-scenario results shown in Table 12-6. Allocated capacity, theoretical MT/yr 13.8 4.6 Ship size, DWT 50,000 50,000 30,000 30,000 Allocated capacity, practical MT/yr 12.2 4.1 Cargo temperature, °C -50 -30 -50 -30 Voyage distance km 1000 330 Number of ships, theoretical rate 5.6 5.4 7.1 6.9 Round-trip time days 4.7 2.6 Number of ships, practical rate 4.9 4.7 6.2 6.1 Number of ships, theoretical rate number 4.8 0.9 Table 12-6: Number of ships in single export point scenario, varying ship size and Number of ships, practical rate number 4.3 0.8 cargo temperature Table 12-7: Two export point scenario – key inputs and outputs
At first, the lower number of ships required for the -30°C cases seems Four or five 50,000 DWT ships are required for the larger, more distant hub and counterintuitive, as the lower CO2 density implies a higher volume and one of less than one ship of this size is needed for the smaller, closer hub. This clearly the main constraints is the volumetric pumping rate at offload. However, the port raises options for differently sized ships or for sharing, say, five ships between throughput model is based on a cargo tonnage, meaning the -30°C figures are the two hubs. The extension to modelling the effect of different sized ships or for lower total throughput capacities as described in Section 12.5. different cargo temperatures was not made for this scenario.
Two export point scenario 12.5.3.2 Fuel consumption estimate A second scenario was developed with two export points, one larger and more Fuel consumptions for the single export point and the two export point scenarios distant and the other smaller and closer, as might represent Le Havre and were estimated from the round-trip time profiles developed and the fuel Teesside, respectively. Taking outputs from the base case of a 50,000 DWT consumption data given for a large ship (40,000T cargo) in the Tel-Tek study; ship with CO2 cargo at -50°C, the maximum capacity through Peterhead was (Skagestad, et al., 2014) given in Table 13-2 in Section 13; it is not clear from arbitrarily allocated to each exporter in a 3:1 ratio, roughly in proportion to the the Tel-Tek report what grade of marine fuel oil was assumed in the study. Three indicative supply potentials given in Table 12-5. fuel consumption rates were used: for idle time (including loading and offloading time); for port manoeuvring (including waiting time for slack tide); and for sea The model shown in Figure 12-11 was adapted, essentially duplicated to cover transit. The number of ships (all at 50,000 DWT and -50°C) was defined as 5 for each shipping route, and the number of ships required to service each export the single export point scenario, 4.5 ships (assuming sharing is feasible) for the hub was calculated. Key input data and the outputs in terms of number of ships larger hub and one ship for the smaller hub in the two export point scenario. are shown in Table 12-7.
ACT Acorn Consortium Page 72 of 80
D18 Expansion Options Annex 1: International CO2 Shipping Scenarios
Fuel consumption was calculated in terms of productive time (from the round- 12.5.4 Build-up scenarios trip profile) and stand-by time (by difference from whole year) giving a total 12.5.4.1 Capacity build-up model annual fuel consumption for each scenario. This was normalised as specific fuel The modelling described above has established that the practical throughput consumption per thousand tonnes of CO2 carried (T/kT-CO2). The specific fuel capacity for importing bulk liquid CO by ship through Peterhead Port is higher consumption for the single export point scenario was estimated as 4.3 T/kT- 2 than previous work has considered. Following this, it was decided to model a CO2; the value for the two-export point scenario was slightly higher at 4.5 T/kT- series of intermediate import quantities to explore the number and size of ships CO2. Detail of the estimation model and intermediate outputs can be made and other requirements. This may be helpful for making choices regarding the available for work to be carried out in the ACT Acorn Lifecycle Assessment design of downstream CO transport systems between Peterhead and St (D12). 2 Fergus, which is considered initially in this Expansion Options report of the ACT 12.5.3.3 Shipping scenarios modelling summary Acorn Project.
A rough-cut estimate of CO2 supply potential from industrial clusters with access The port throughput capacity model and the shipping logistics model described to the North Sea through European ports suggests there is more than enough above were combined and modified. The resulting capacity build-up model takes CO2 (in the order of four-fold excess) to satisfy the maximum practical main input variables of annual import tonnage and ship size to estimate the throughput capacity of Peterhead Port. number of ships required and the offloading frequency. This model was then Modelling of two different ship supply scenarios has allowed the likely number extended to calculate fuel consumption for combinations of annual tonnage, size of ships required to be determined. A scenario with a single export point at 800 and number of ships. km distance from Peterhead would require five ships of 50,000 DWT with CO2 Other inputs to the model were similar to those described above with certain cargo temperature of -50°C to satisfy the maximum practical throughput. A exceptions, introduced following learning from the earlier modelling and with the second scenario with two export points would require between five and six ships aim of improving the pragmatism of the model. Data for availabilities and timings of the same size; this scenario raises numerous options for varying ship sizes for Peterhead Port and the exporting port were unchanged; the voyage distance and scheduling to satisfy the total transport requirement. was set at 800km. The cargo temperature was set as -30°C, with corresponding A model for estimating fuel consumption of such shipping scenarios has been 3 CO2 density of 1077kg/m . The offloading pump capacity was set to the developed. Specific fuel consumptions for the two scenarios described are maximum included in the Petrofac study, 1069m3/h, (Giles, 2012), but with estimated as 4.3 and 4.5 T/kT-CO2, respectively. additional inputs for the number of pumps and the running rate as a percentage, from which the combined pump output was calculated. A feasibility check was
ACT Acorn Consortium Page 73 of 80
D18 Expansion Options Annex 1: International CO2 Shipping Scenarios
added to confirm that this pump output, when combined with port entry and exit Factor Unit Value Observation timings, was sufficient for the modelled offload frequency. Target tonnage Mt/yr 10 Main input
Ship deadweight DWT 50,000 Main input The model was run for a stepped series of CO2 throughput capacity levels (2.5, Non-cargo allowance % 20 5, 10, 15 and 20MT/yr) with a range of ship sizes (10,000, 30,000 and 50,000 Cargo weight t 40,000 Cargo temperature °C -30 -30 or -50, not used but sets density DWT) and with the number of offload pumps (in whole numbers) adjusted to just 1077 or 1156, using lower density for this model to fit with CO2 density kg/m3 1077 Norwegian project indications satisfy the feasibility check. A snapshot of the capacity build-up model Cargo volume m3 37,140 spreadsheet is shown in Figure 12-12 for a capacity of 10MT/yr using a fleet of Loads required number/yr 250.00 Load frequency loads/day 0.68 50,000 DWT CO2 tankers and two offload pumps. Model outputs in terms of Tidal gate, average delay h 3 Average delay for random arrival times number of ships and offload frequency are shown in Table 12-8 and Table 12-9, Port entry and docking time h 2 respectively, together with the required number of pumps. Blank results indicate Pump capacity m3/h 1069 Based on Giles, 2012, Scenario 17 Pump running rate % 75 Derating from maximum for flexibility that a number of pumps and/or ships likely to be impractical would be required. Number of pumps number 2 Manual input Pump combined output m3/h 1604 Offloading time h 23.2 Undocking and port exit time h 2 Import turnround and offload time h 30.2 Compares load frequency recalculated as hours per load Feasibility check Y or N Y with offload time, Y if 24/frequency > offload time
Combined weather availability % 91.8 Includes berthing and tug connection factors Tanker jetty availability % 98.6 Tug services availability % 97.3 Allows for pilot and tug availability Combined P/h port availability % 88.0
Export facility availability % 95 Ship availability % 95.9 Downrated to Tel-Tek rate, 15 day/yr outage Combined despatch availability % 91.1
Overall shipping system availability % 80.2
Voyage distance km 800 Cruising speed km/h 26 = 14 knots Time at sea h 30.8 Each leg. Remember to double in round trip calculation Export turnround and loading time h 18 Round-trip time h 109.7 Assumes laden and unladen speeds the same Round-trip time days 4.6
Number of ships required number 3.9
Figure 12-12: Capacity build-up model example for 10MT/yr with 50,000 and 2 offload pumps
ACT Acorn Consortium Page 74 of 80
D18 Expansion Options Annex 1: International CO2 Shipping Scenarios
Ship size Cargo Throughput, MT/yr Higher import capacities in the range 10-20MT/yr should also be achievable with DWT T 2.5 5 10 15 20 more ships of the larger size, but the offload frequency and pumping capacity Number of ships are likely to limit capacity toward the top of this range. These findings agree 10,000 8,000 4.3 8.1 generally with those of the port throughput capacity model, as expected. 30,000 24,000 1.7 3.4 6.0 8.3 12.5.4.2 Fuel consumption with capacity build-up 50,000 40,000 1.2 2.4 3.9 5.4 6.8 The fuel consumption calculation described in Section 12.5.3.2 was applied to Number of pumps these capacity build-up scenarios. Fuel consumption rates for the larger and 1 1 2 4/3 5 smaller ship sizes were from literature, (Skagestad, et al., 2014), and are given Note: 15MT/yr requires 4 pumps with 30,000 DWT ship, 3 pumps with 50,000 DWT ship. in Section 13 (Table 13-2, Table 13-3 respectively). Fuel consumption figures Table 12-8: Number of ships and offload pumps from capacity build-up model for the 30,000 DWT ship size were estimated from the larger ship data by Ship size Cargo Throughput, MT/yr interpolation, giving consumption rates for idle time, manoeuvring and transit of DWT T 2.5 5 10 15 20 3.0, 10.3 and 41.1 T/day respectively. The number of ships was rounded up to Offloads per day the next whole number from the build-up model outputs shown in Table 12-8. 10,000 8,000 0.9 1.7 Using this data the specific fuel consumption rates per thousand tonnes of CO2 30,000 24,000 0.3 0.6 1.1 1.7 carried were estimated as shown in Table 12-10. There are general trends 50,000 40,000 0.2 0.3 0.7 1.0 1.4 toward lower consumption for both increasing ship size and throughput; the Number of pumps apparent anomalies to these trends (the 50,000 DWT, 2.5MT/yr and 30,000 1 1 2 4/3 5 DWT, 15MT/yr cases) are due to increased idle time resulting from the whole Note: 15 MT/yr requires 4 pumps with 30,000 DWT ship, 3 pumps with 50,000 DWT ship. number of ships modelled. The identical values for consumption with 30,000 Table 12-9: Offload frequency and number of pumps from capacity build-up model DWT ships for both 2.5 and 5MT/yr arise as both the number of ships and the
These outputs suggest that annual CO2 imports through Peterhead of 5 to throughput double between the cases. The value for the case using 50,000 DWT 10MT/yr would be very achievable with relatively few ships (3 or 4) of an ships, with throughput capacity of 15MT/yr and specific fuel consumption of appropriate size (30,000 to 50,000 DWT), even with model inputs that de-rate 4.5T/kT-CO2 is close to that estimated for the shipping scenarios described the capacity somewhat compared to those used in the port throughput model earlier in Section 12.5.3.2. described above. This range of capacity is understood to cover the values being considered for onward CO2 transport from Peterhead to St Fergus.
ACT Acorn Consortium Page 75 of 80
D18 Expansion Options Annex 1: International CO2 Shipping Scenarios
Ship size of 50,000 DWT, the largest that can be accommodated at the jetty. This Cargo Throughput, MT/yr size estimate is constrained only by factors relating to the port itself, that is, without DWT T 2.5 5 10 15 20 applying any upstream supply constraints or downstream processing or Specific fuel consumption per thousand transport constraints. This capacity estimate is significantly higher than tonnes, T/kT-CO2 10,000 8,000 8.1 7.9 previous values discussed for import through Peterhead, which have been constrained by downstream pipeline capacity. 30,000 24,000 5.2 5.2 4.9 4.9 50,000 40,000 5.3 4.8 4.6 4.5 4.4 Sensitivity analysis on the estimate identified the main factors affecting Table 12-10: Specific fuel consumption estimates for build-up scenarios capacity as the size of the ship and the cargo offload rate (that is, the liquid CO pumping rate), with the time for ship turnround also becoming important 12.6 Summary and Conclusions 2 for smaller ships. Other factors studied had relatively little influence on overall port capacity. However, while port unavailability due to bad weather has only a Transport of liquefied CO by ship is an established operation and is under 2 moderate influence overall, it is a factor that would benefit further clarification, consideration by a number of CCS projects around the North Sea Basin. Ship particularly due to its seasonality, occurring mostly during the winter months. transport of CO2 is recognised as a viable alternative to pipeline transport in appropriate circumstances. For any ship delivery system for a bulk liquid, gaps in flow are expected either during turnround operations or through delays between shipments. The This report provides information on the bulk transport of CO by ship to 2 volume of shoreline buffer storage that would be needed to “smooth out” flow Peterhead Port from potential CO2 export hubs around the North Sea Basin. of CO2 into a downstream pipeline was estimated in this study, ranging from The work described supports the case for expansion of the Acorn Project 20,200m3 to cover average turnround operations to 90,000m3 to cover a 24h beyond the initial phase and provides information needed for lifecycle analysis. delay between shipments. It was concluded that the capital costs to provide such storage and associated systems would most likely outweigh any The study used simple spreadsheet modelling with input data from both advantage and that downstream transport systems should be designed to published and unpublished sources (obtained through personal cope with interrupted flow of CO2. communication) to explore the CO2 throughput capacity of Peterhead Port and to estimate logistic data for shipping CO2 from example export hubs, including Previously published studies of eight potential CO2 export hubs around the the number and size of ships required, round-trip time and fuel consumption. North Sea Basin were used to compile an indicative estimate of CO2 volumes The main findings are summarised below. that might be available for shipping at an arbitrary time in the future: over 65MT/yr was estimated. The purpose of this estimate is to establish that The maximum practical capacity for import of liquid CO2 through Peterhead upstream supply of CO2 for import to Peterhead can be considered Port’s tanker jetty is estimated to be about 16.2MT/yr, assuming a CO2 tanker
ACT Acorn Consortium Page 76 of 80
D18 Expansion Options Annex 1: International CO2 Shipping Scenarios
unconstrained, and no other significance should be attached to the figure Overall, this study has increased the understanding of factors affecting CO2 derived. import by ship into Peterhead Port and the confidence in projections of capacity. The port appears to have ample capacity for the levels of import Based on these potential CO2 export hubs, two different shipping scenarios were envisaged for early build-out phases of the Acorn Project, which are likely to examined to supply the maximum CO2 import capacity of Peterhead. A scenario be constrained by onward pipeline transport to St Fergus. Import quantities of with a single export point at 800km distance from Peterhead would require five CO2 in the range 5 to 10MT/yr will require a fleet of three or four tankers of ships of 50,000 DWT to satisfy the maximum capacity. A second scenario with 30,000 to 50,000 DWT size to service routes within the North Sea area. This two export points at 330 and 1000km distance would require between five and size of ship is within the range that has been considered by other projects six ships of the same size; this scenario raises numerous options for varying proposing ship transport of CO2 for CCS in the North Sea region. ship sizes and scheduling to satisfy the total transport capacity. A few areas have been identified by this study where further work or Fuel consumption was estimated for the shipping cycles in these example clarification would be useful. These include: improving the definition of the scenarios. The consumption was normalised as specific fuel consumption per capacity of pumps available to handle liquid CO2 at low temperatures; ensuring thousand tonnes of CO2 carried with values of 4.3 and 4.5T/kT-CO2, that designs for onward CO2 transport allow for interruptions in flow caused by respectively, estimated for the two scenarios. gaps between ship deliveries; improving definition of weather-related downtime at the port and, in particular, how seasonality of downtime may affect upstream Further modelling explored the system requirements of a series of scenarios and downstream elements of the CCS chain. with a stepped build-up in CO2 import quantity. The model allowed estimates to be made for the number of ships, number of offloading pumps, frequency of offloading and specific fuel consumption for a range of ship sizes (10,000 to 50,000 DWT) and a range of import quantities (2.5 to 20MT/yr), based on a single export point at 800km distance from Peterhead. Model outputs suggested that import quantities of 5 to 10MT/yr are achievable with three or four ships of 30,000 to 50,000 DWT size offloading less than once per day using one or two pumps, and with specific fuel consumption of 4.6 to 5.2T/kT-
CO2. This range of throughput capacity is understood to cover the values being considered for initial pipeline transport development from Peterhead to St Fergus.
ACT Acorn Consortium Page 77 of 80
D18 Expansion Options Annex 2: International Shipping Data
13.0 Annex 2: International Shipping Data
13.1 Shipping data
Shipping data Unit Value Note Data source
Maximum ship size DWT 50,000 Deadweight tonnes (DWT) (Peterhead Port Authority, 2018) http://www.peterheadport.co.uk/tanker_jetty.htm
Non-cargo allowance vs. % 20 Allowance for fuel etc. Adapted from Petrofac study, (Giles, 2012) DWT
Ship cruising speed km/h 26 14 knots Data provided during CATO project, (de Kler R. , 2015)
Export turnround and h 18 12h loading, 6h entry/exit Tel-Tek study, (Skagestad, et al., 2014) loading time
Export facility Allowance for maintenance and % 95 Arbitrary, assumes larger ports have high services/weather availability availability services availability Data provided during CATO project, (de Kler R. , 2015), Tel-Tek study implies Ship availability % 98 lower value of 350/365 = 0.958 Table 13-1: Basic ship and export data
Fuel consumption Unit Value Note Data source Loading, offloading or idle T/day 3.5 For 40,000 T ship, assumes power from shore for pumping Tel-Tek study, (Skagestad, et al., 2014) Port manoeuvring T/day 15.43 Also used for waiting time for tidal gate delay Tel-Tek study, (Skagestad, et al., 2014) Sea transit T/day 61.72 Tel-Tek study, (Skagestad, et al., 2014)
Table 13-2: Ship fuel consumption – large ship
ACT Acorn Consortium Page 78 of 80
D18 Expansion Options Annex 2: International Shipping Data
Fuel consumption Unit Value Note Data source Loading, offloading or idle T/day 2.5 For c.10,000 T ship, assumes power from shore for pumping Tel-Tek study, (Skagestad, et al., 2014) Port maneuvering T/day 5.22 Also used for waiting time for tidal gate delay Tel-Tek study, (Skagestad, et al., 2014) Sea transit T/day 20.87 Tel-Tek study, (Skagestad, et al., 2014)
Table 13-3: Ship fuel consumption – small ship 13.2 Peterhead Port and tanker jetty data
Peterhead general port Unit Value Note Data source data (Peterhead Port Authority, 2018) Port control availability % 100 Not used in model http://www.peterheadport.co.uk/port_services.htm Port combined weather Adapted from Stephen Paterson, Peterhead Port Authority, (Paterson, % 91.8 30 days outage per year availability 2018) Tanker jetty availability % 98.6 5 days outage per year Assumption, covering e.g. jetty maintenance, 5 days Tug services availability % 97.3 10 days outage per year Assumption, allows for tug maintenance or other service outage Tidal gate, average delay h 3 Average delay for random arrival times Stephen Paterson, Peterhead Port Authority, (Paterson, 2018) Docking time h 2 Maybe less for smaller ships Stephen Paterson, Peterhead Port Authority, (Paterson, 2018) Departure time h 2 Maybe less for smaller ships Stephen Paterson, Peterhead Port Authority, (Paterson, 2018)
Table 13-4: General port data
Peterhead tanker jetty Unit Value Note Data source data (Peterhead Port Authority, 2018) Maximum ship length m 280 Not used in model http://www.peterheadport.co.uk/tanker_jetty.htm (Peterhead Port Authority, 2018) Maximum ship draft m 11 Not used in model http://www.peterheadport.co.uk/tanker_jetty.htm Current usage % 15 Not constraining Stephen Paterson, Peterhead Port Authority, (Paterson, 2018) (Peterhead Port Authority, 2018) Maximum ship capacity DWT 50,000 Deadweight tonnes http://www.peterheadport.co.uk/tanker_jetty.htm Table 13-5: Tanker jetty data
ACT Acorn Consortium Page 79 of 80
D18 Expansion Options Annex 2: International Shipping Data
13.3 Other data
CO2 data Unit Value Note Data source Density at -50°C kg/m3 1156 (Engineering Toolbox, 2018) Density at -30°C kg/m3 1077 (Engineering Toolbox, 2018)
Table 13-6: CO2 density
Variables for model Unit Value Note Data source Non-cargo allowance vs. DWT % 20 Allowance for fuel etc. Adapted from Petrofac study, (Giles, 2012) Offloading flow rate m3/h 2883 May require multiple pumps CATO paper assumes 3333T/h=2883m3/h (de Kler, et al., 2016)
Table 13-7: Selected model input variables
ACT Acorn Consortium Page 80 of 80