Lessons from the ROAD project for future deployment of CCS

Lessons from the ROAD project for future deployment of CCS

International Journal of Greenhouse Gas Control 91 (2019) 102834 Contents lists available at ScienceDirect International Journal of Greenhouse Gas C...

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International Journal of Greenhouse Gas Control 91 (2019) 102834

Contents lists available at ScienceDirect

International Journal of Greenhouse Gas Control journal homepage: www.elsevier.com/locate/ijggc

Lessons from the ROAD project for future deployment of CCS a,e

b

a

Andy Read , Chris Gittins , Jan Uilenreef , Tom Jonker ⁎ Earl Goetheerc, Ton Wildenborgc,

a,d

c

T c

, Filip Neele , Stefan Belfroid ,

a

Maasvlakte CCS Project (ROAD), The Netherlands Taqa Energy, The Netherlands TNO, The Netherlands d Brabers, The Netherlands e Uniper, United Kingdom b c

A R T I C LE I N FO

A B S T R A C T

Keywords: CCS chain Post-combustion capture Gas reservoir Demonstration

The ROAD project was designed to demonstrate the technical and economic feasibility of a large-scale, integrated CCS-chain deployed on power generation. Post-combustion technology was to be applied to separate CO2 from the flue gases of the new 1069 MWe coal-fired Maasvlakte Power Plant 3 (MPP3) in the harbour area of Rotterdam. From the capture unit, the CO2 was to be compressed and transported through a pipeline, originally to the P18-A platform in the North Sea to inject CO2 in the P18-4 gas reservoir. An alternative storage site, the nearshore Q16-Maas, was selected in 2015. Feasibility and FEED studies were performed in the period from 2010 to 2017, when the industrial partners pulled out of the project because of lack of political and financial support for the ROAD project. Capture, transport and storage technology is available and will work; remaining questions can be answered by engineering solutions. The full-scale capture plant can be designed and procured to the standard required to enable FID. Pilot plants have proved very valuable for testing and improving the ROAD capture plant design. In all cases, safe and practical designs to transport and store the CO2 were developed.

1. Context and history The ROAD Project is the Rotterdam Opslag and Afvang Demonstratieproject (Rotterdam Capture and Storage Demonstration Project) which ran from 2009 to 2017, and was one of the integrated Carbon Capture and Storage (CCS) demonstration projects anticipated to become leading in the world. The main objective of ROAD was to demonstrate the technical and economic feasibility of a large-scale, integrated CCS chain deployed on power generation. Previously, CCS had primarily been applied in smallscale test facilities in the power industry. Large-scale demonstration projects were needed to show that CCS could be an efficient and effective CO₂ abatement technology. With the knowledge, experience and innovations gained by projects like ROAD, CCS could be deployed on a larger and broader scale: not only on power plants, but also within the energy intensive industries. CCS is one of the transition technologies expected to make a substantial contribution to achieving European and global climate objectives. ROAD is a joint project initiated in 2009 by E.ON Benelux and Electrabel Nederland (now Uniper Benelux and Engie Nederland).



Together they formed the joint venture Maasvlakte CCS Project C.V. which was the project developer. The ROAD Project is co-financed by the European Commission (EC) within the framework of the European Energy Programme for Recovery (EEPR) and the Government of the Netherlands. The grants amount to € 180 million from the EC and € 150 million from the government of the Netherlands. In addition, the Global CCS Institute is knowledge sharing partner of ROAD and has given a financial support of € 4.3 million to the project. The Port of Rotterdam also agreed to support the project through investment in the CO2 pipeline. An extensive programme of feasibility and FEED studies across the CCS chain was started up in 2010 and ended in 2017 after the industrial partners pulled out of the project. In the first phase of the project, 2009–2012, the project was developed to final investment decision (FID) based on using the P18-4 gas-field operated by TAQA as the CO2 storage location (Fig. 1). Unfortunately, the collapse in the carbon price undermined the original business case, and in 2012 a positive FID was not economically possible. The project then entered a “slow-mode” in which activities focused on reducing the funding gap, either by reducing costs or by

Corresponding author at: TNO Princetonlaan 6, 3584 CB, UTRECHT, the Netherlands. E-mail address: [email protected] (T. Wildenborg).

https://doi.org/10.1016/j.ijggc.2019.102834 Received 3 October 2018; Received in revised form 10 September 2019; Accepted 13 September 2019 1750-5836/ © 2019 Elsevier Ltd. All rights reserved.

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Fig. 1. Schematic overview of the ROAD Project using storage in P18-4.

Fig. 2. Schematic representation of the renewed set-up of the ROAD project with the Q16-Maas storage reservoir.

and financial support for the ROAD project has resulted in this decision. After a competitive FEED process, Fluor was selected as the supplier for the capture technology in early 2011. The plant was fully engineered, and long lead items contracted for, ready for an FID in early 2012. All the necessary permitting was completed, with a permit for the capture plant being granted in 2012. Following the delay to the project, an updated design was developed with Fluor in 2017 incorporating lessons learnt from research and development in the intervening years, changes to the MPP3 site, and the impact of the changes to the transport

securing new funding. In late 2014 a possible new funding structure was identified, and explored in 2015 and 2016. This included additional grants for operation and cost reductions. The cost reduction that could be successfully applied was to change storage sink to a newly developed field, Q16-Maas, operated by Oranje-Nassau Energie (ONE). The smaller field was much closer to the power plant (Fig. 2). This resulted in a remobilization of the project late in 2016, and development of the new scheme. However, in mid-2017 work was again halted, and the grant formally terminated in November 2017. Lack of political 2

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made ‘CO2 Capture Ready’, which means it can be retrofitted with a full-scale capture plant. MPP3 has already been certified according to ‘TÜV NORD Climate Change Standard TN−CC 006′. The standard contains requirements in particular regarding the technological and site-specific feasibility of retrofitting a full-size carbon capture system at the power plant location, the availability of the space which will be needed for the capture plant, the possibility of transporting CO2 from the power plant site to a CO2 storage site and the possible effects on plant safety and environment. The TÜV certificate was granted on 19 May 2009. The designed capture unit has a capacity of 250 MWe equivalent and a target capture efficiency of 90%, which equates to 169 t/h of CO2 captured. It aims to capture 1.1 Mt of CO2 per year. The capture process chosen is Fluor’s Econamine FG + process (Reddy et al., 2017), which was selected after a thorough competitive tendering process including two competitive FEED studies (see also Huizeling and Van der Weijde, 2011). It is one of the best proven technologies available for postcombustion capture, and has been licensed to 28 industrial plants in a range of applications. It is based on the conventional amine solvent MEA (monoethanolamine). Significant amount of literature and experience is available in the public domain. Due to the fact that the ROAD project would have had a limited operation time, leading to short depreciation time, this is as well why the Econamine process has been selected. The layout is a fairly conventional for a post-combustion capture amine process. The flue gas is taken from the inside of MPP3 stack via an already emplaced tie-in, and guided through an innovative direct contact cooler (DCC) to reduce the temperature to the optimum level for CO2 capture – typically 30–35 °C. The direct contact cooler also includes a small desulphurisation section to reduce sulphur levels in the flue gas to below 5 mg/Nm3. The cooled flue gases pass via a wet electrostatic precipitator (WESP) for final particulate removal and a fan to the absorber. It is in the absorber that the solvent absorbs 90% of the CO2 in the flue gas. The cleaned flue gas is then returned to the MPP3 stack. Solvent is regenerated in a stripper using steam from the power plant, cooled, and returned to the absorber (Kooistra et al., 2018). The Capture Plant which processes about 25% of the flue gas from the MPP3 plant, is designed as a demonstration of full-scale carbon capture on coal-fired power plant. Therefore, despite the cost pressures that have resulted in a minimisation of plant redundancy and spares, and the limited operational funding currently available, the Capture Plant includes all the major characteristics a full-scale commercial plant would require. These including:

and storage system. A revision to the permit was under development when the project was halted. Extensive feasibility studies were performed for the required pipeline infrastructure for transport to the P18-4 field (Uilenreef, 2011; Uilenreef and Kombrink, 2013; Uilenreef et al., 2018) and the use of the P18-4 reservoir as a store for CO2 (Arts et al., 2011, 2012, 2013; Akemu et al., 2011; Vandeweijer et al., 2011; Van de Weerd, 2011; Wildenborg et al., 2018). Unfortunately, a positive FID was not possible due to funding problems, and in 2012 technical project development on P18-4 was halted. The Q16-Maas reservoir was identified as a possible storage location only at the end of 2014, with project development running through 2015-2017. Due to funding uncertainties, the work focused on feasibility, cost estimation and concept design to the level required for permitting. Therefore a lower level of detail is available for this storage location, compared to P18-4. It should also be noted that unexpected water production was experienced from Q16-Maas in 2016, leading Oranje-Nassau Energie to issue a revised reservoir model and production plan in May 2017. Since this was only shortly before the ROAD work was halted, the ROAD plans for Q16-Maas were not fully amended to reflect this new production data. More than seven years of intensive study produced a lot of interesting findings and lessons learned, which can be of great value for future developments of CCS projects. In particular for the Netherlands where CCS has gained renewed momentum in the coalition agreement of the new government installed in 2017, by stating that CCS will be applied to CO2 intensive industry up to a scale of 18 Mt CO2 by 2030. Roundtable discussions with industry stakeholders revealed a target of 7 Mt per annum as an intermediate result. This paper summarizes important highlights and the main lessons learned from the feasibility and FEED studies which were performed in the ROAD project. It is an extension of the earlier paper on lessons learned from Read et al. in 2014. The presented findings relate to the capture, transport and storage technology and to regulation, permitting and public engagement. An extensive summary of the ROAD project is described in a series of 11 reports including a large number of appendices with more detailed background documents (see Read and Kombrink, 2018; see 5. Appendix). 2. Capture The ROAD CCS chain (Fig. 3) includes post combustion technology (Van der Weijde and van de Schouw, 2011) to capture the CO2 from the flue gases of the new supercritical 1069 MWe coal-fired power plant (Maasvlakte Power Plant 3) in the Rotterdam port and industrial area.

• Design life of 126,000 operating hours over 20 years; • The ability to follow the load of the power plant, with the same ramp rates (up to 5%/minute); • Turndown to 40% capture rate (This is a typical turn-down cap-

2.1. Description The technical features of MPP3 include a pulverized-coal fired supercritical boiler with advanced materials for highest steam parameters, advanced process design and sea water direct cooling. Furthermore, MPP3 is equipped with the required emission control technologies including ‘Flue Gas Desulphurization’ (FGD) for the reduction of SOx emissions and ‘Selective Catalytic Reduction’ (SCR) for the reduction of NOx emissions. The main characteristics of the newbuild power plant can be summarized as displayed in Table 1. The construction and commissioning of MPP3 has been completed. When operated at design conditions, MPP3 emits a flue gas stream of about 1084 kg/s, containing 13.7% CO2 (% volume, actual wet basis). The new-build plant therefore produces approximately 755 g CO2/kWh at design conditions, resulting in annual CO2 emissions of about 5.7 million tonnes in base load operation with an assumed capacity factor of 80%. To lower the net specific CO2 emissions of the plant, Uniper is taking the opportunity to co-fire biomass. The permit allows co-firing up to 30% by weight of biomass which consists mostly of wood pellets. For further reduction of the CO2 emissions in the future, MPP3 is



ability for a coal power plant, although MPP3 is designed to turndown as low as 25%.); A high level of automation and instrumentation.

2.2. Power plant integration In the period 2012–2014 several publications were written about the integration between the CCS installation and the power plant. In 2014 a presentation was given at the POWER-GEN conference (Magneschi et al., 2014) and in 2013 a special report was written for the GCCSI (Hylkema et al., 2013). Some highlights from these documents are summarized below, together with a discussion of the changes since 2012. For the complete data we refer to the original documents. There is a range of interactions between the capture plant and the host power plant, MPP3, as illustrated schematically in Fig. 4. The integration of the power plant, capture, transport and storage was and still is novel to the EU. One existing reference is the Boundary Dam project in Canada which is smaller (roughly 140 MW scale) and 3

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Fig. 3. Block diagram integrated chain (MMP3, capture plant, transport and storage). Table 1 Main design parameters of power plant MPP3 Design Parameter Unit; thermal input and electrical efficiency are quantified on an LHV (lower heating value) basis. Design Parameter

Unit

Value

Rated Thermal Input Electrical Output (Net) Live Steam Pressure Live Steam Temperature Reheat Steam Pressure Reheat Steam Temperature Steam Generator Efficiency Electrical Efficiency (Net)

MW MW bar °C bar °C % %

2 307 1 069 285 600 60 620 94.8 46.3

• • • •

uses different capture and storage technologies (Boundary Dam storage is in an onshore EOR field with test-scale aquifer injection in addition, whereas ROAD uses an offshore depleted gas field). The integration of the capture plant with the power plant, compression, pipeline and depleted gas field storage is therefore a first-of-a-kind. The ROAD design includes no intermediate storage (other than that provided by pipeline line pack) so the whole CCS chain will operate as a single integrated system. In addition, the capture plant process was subject to on-going continuous improvement by Fluor, supported by studies at the Wilhelmshaven pilot involving the parent companies of the project sponsor. The plant design would therefore have included a number of optimizations and improvements not seen in existing small-scale units. These include:

integration both improves efficiency and reduces the cooling water demand (De Miguel Mercader et al., 2012). A steam ejector, used to control the pressure of the steam from the power plant, allowing continued efficient operation of the capture plant when the power plant is at part load. The direct contact cooler (DCC) condenses water of high purity from the flue gas as it is cooled, and this is re-used in the MPP3 FGD unit. This significantly reduces the freshwater consumption of the power plant in combination with CCS (Hylkema and Read, 2014). Vacuum flash and compression system (Sanchez Fernandez et al., 2012).on the reboiler and intermediate absorber cooling in the solvent cycle to optimise the process performance (minimizing the energy required). Use of the latest packing designs and washing / scrubbing designs for optimum thermal and environmental performance.

2.3. Process performance data and CO2 capture efficiency The CO2 capture efficiency of the ROAD plant is 90% at full load. Depending on operational parameters selected, this can be maintained, and indeed exceeded, at part load. Full performance data for the capture plant design conditions cannot be given for reasons of commercial confidentiality. Some aspects can be inferred from the overall heat and materials balance and the utility consumption data. However, details of the way Fluor have optimized performance of their process is a trade secret and is therefore omitted from public reports. The single biggest costs are the use of electricity and steam by the capture plant. The steam supply from the power plant resulted in a loss of generating capacity, and ROAD compensated the power plant for this as a cost of lost electrical output. Therefore, for the purposes of assessing the overall system performance, a total electrical consumption can

• The CO

2 leaving the stripper is cooled using feedwater from MPP3 in order to recover this heat back into the power plant. This heat

4

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Fig. 4. Illustration of the interfaces between the power plant and the CCS installation, and with the outside world (Read et al., 2014).

may need to be removed. However, the performance of industrial WESP designs with fine aerosols is not accurately quantified, and some pilot data suggests it may be much better than current guarantee values (Mertens et al., 2017). Also, the acceptable level of aerosols is not accurately known for the Fluor design. Therefore a lower specification of WESP (circa 90% removal) was chosen for this design update, with provision to either include an additional WESP in future (to reach 99%), or to leave out the WESP entirely, based on the results of continuing and future research, and ongoing tests at MPP3. The WESP was located after the DCC for two reasons: this is the coolest part of the flue gas flow chain and therefore has the lowest volume flow, allowing the WESP to be smaller, and also because there is a risk that the WESP converts a percentage of SO2 to SO3, which would itself create aerosols. The DCC removes SO2 down to very low levels, so this risk is avoided by placing the WESP downstream of this polisher. The decision to locate the WESP before the blower was based on optimization of the flow path – for the ROAD layout duct distances are minimised by using a downflowing WESP upstream of the Blower. Space is available for a second WESP in case removal of aerosols to 99% is required. During the design update, quotes from a number of WESP vendors were received. However, the final choice of vendor was not made. The plan area allocated (15 by 15 m) is sufficient for all vendor designs received. The Blower (3 0HKC10 AN001), located downstream of the WESP, is used to overcome the pressure drop through the EFG + plant.

be used which is the sum of the electricity use, and the loss of generating capacity. This was estimated at 58.4 MW, of which just over half is due to steam consumption. It should be noted that this figure was not re-adjusted for the updated design developed in 2017. It is quite possible a small upward revision will be required due to additional compression costs since the new design includes a less efficient air-cooled condenser stage at the Q16-Maas well location. The WESP would also increase utility consumption (see Section 2.4). The estimate includes all compression power, so the power for transport and storage is included as well. It also includes a margin of order 3 MW to allow for some periods with off-design operation, which can result in increased cost of steam because the power plant is at reduced load, or part load operation of the capture plant. Technical solutions for reducing energy usage are not fully optimized due to time, budget and space constraints. Further performance improvement and savings in investment and operational costs are feasible for new power plants with full-scale CO2 capture (Sanchez Fernandez et al., 2014). 2.4. Wet electrostatic precipitator (WESP) The inclusion of a WESP (wet electrostatic precipitator) is intended to remove aerosols from the MPP3 flue gas to prevent them from reaching the absorber. Alternative options for the removal of aerosols can be done as well using Brownian demisters (Khakharia et al., 2014). However, due to effect of the high pressure drop by using low gas velocity, demisters lead to significant blower energy demands. Therefore, evaluation was made to incorporate WESP into the ROAD design, instead. Research at various capture pilot plants (Khakharia et al., 2013; Mertens et al., 2014, 2015) has shown that aerosols in the flue gas entering the capture plant can give rise to high solvent emissions. This was confirmed at the Wilhelmshaven pilot when aerosols were artificially added to the flue gas and this has been confirmed for different amine solvents (Khakharia et al., 2015). These high aerosols levels only occur at some coal-fired power plants, typically those with a wet stack as at Maasvlakte. Tests at MPP3 have measured SO3 aerosol levels in the flue gas to be sufficient to cause high solvent slippage from capture units, and breach environmental limits. However, these aerosol levels are very variable, and are not present at all times. This was a matter of continuing research when the ROAD project was stopped. At the current level of understanding, based on the worst case MPP3 measurements, and the available pilot data, up to 99% of the aerosols

2.5. Improved solvent management package The Fluor pilot at Wilhelmshaven had problems with solvent management, which were found to be due to iron leaching into the solvent from the coal ash, which had entered the solvent in the absorber (Schallert et al., 2014). The iron catalysed corrosion of the steel, resulting in additional iron entering the system (Dhingra et al., 2017; Rieder et al., 2017). During the resulting studies, iron removal systems were tested, and improved reclaimer designs were tested (although the initial reclaimer design did prove to be fit for purpose in the absence of iron contamination). As a result Fluor developed an improved proprietary solvent management package including reclaimer, filters and iron removal. This proved to be very successful on the Wilhelmshaven pilot in 2016, maintaining high solvent quality continuously over a 2,000 h test run, and would therefore be implemented in the ROAD design. 5

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P18-4 field included a molecular sieve dryer between the LP stages and the HP stages of compression. Thus the water knock-out applied only in the LP stages. The selection of the molecular sieve was based partly on the high dryness requirement (50 ppm), and on reducing the risk of triethylglycol (TEG, which is an: alternative technique for molecular sieve drying) contamination of the amine solvent. With the lower pipeline pressures of the Q16-Maas solution, the HP compressor was removed and the dryness target relaxed to 150 ppm. In this configuration, TEG was the preferred solution and this was to be located after the compressor just before the CO2 leaves the MPP3 site.

2.6. Conclusion Perhaps the most important high-level conclusion from this work is that the full-scale capture plant can be designed and procured to the standard required to enable FID. All the identified technical risks, costs uncertainties and permitting and project delivery challenges for the capture plant were successfully managed. The necessary technology is considered to be available for full scale post-combustion capture. Pilot plants have proved very valuable for testing and improving the ROAD capture plant design. Research done after the first design was fixed in 2011 led to a number of design improvements in the updated design of 2017. Most notable were the addition of a wet electrostatic precipitator to counter aerosols (which only occurs in some coal-fired and industrial flue gases), and improvement to the solvent management to minimise corrosion and solvent degradation. The Wilhelmshaven pilot also confirmed Fluor’s predictions on capture efficiency and thermodynamic performance, reducing the project risk. We recommend that future project developers stay close to the research community to ensure state-of-the-art engineering (Kooistra et al., 2018). A significant effort was made to optimise the integration of the capture plant with the power station, and this gave efficiency improvements, cost reductions, reduced freshwater usage and increased operational flexibility.

3.2. Transport 3.2.1. Description For Storage in P18-4 a 16″ carbon steel pipeline needs to be constructed running 5 km over land and about 20 km across the seabed to the P18-A platform in the North Sea. The pipeline has a transport capacity of around 5 million tonnes per year. It is designed for a maximum pressure of 140 bar and a maximum temperature of 80 °C. The mass flow in the ROAD project is 1.1 Mtpa, which equates to about 47 kg/s with full load during 6,500 h. The pipeline was deliberately oversized as a pre-investment for a subsequent phase of injecting in more reservoirs. For Storage in the nearshore Q16-Maas reservoir the transport of CO2 would require a shorter pipeline over land of 6 km to the current production site for Q16-Maas, operated by Oranje-Nassau Energie. The selected pipeline design would have a diameter of 24 inch and a transport capacity of in excess of 6 Mt per year. It was designed for a maximum pressure of 40 bar although in the first phase operation at 20 bar was planned (Table 2). Final compression to injection pressure (around 80 bar) would be required at the injection site (Read and Kombrink, 2018). Doing the final compression at the Q16-Maas wellhead allowed the pressure and temperature after the compressor discharge cooler to be optimized for the well itself, avoiding any need for choking at the wellhead, or overpressurising to prevent two-phase flow in the pipeline. This avoided all the issues with two-phase flow in the P18-4 design where wellhead compression was not economically feasible. The selection of 20 bar operating pressure and 40 bar design pressure was chosen to match the existing OCAP CO2 system parameters, which it was hoped that the pipeline would also connect to. This is a subcritical existing CO2 system in the Rotterdam harbour area. Aside from the dryness of the CO2, which was to avoid risk of corrosion in the pipeline, the CO2 specification was the outcome of the chosen capture technology. Amine-based capture technologies are highly selective for CO2 and therefore naturally produce a very pure stream.

3. Compression and transport After compression and dehydration, the captured CO2 stream is transported by pipeline to a subsurface gas reservoir. 3.1. Compression and dehydration Following recovery, the CO2 product must be compressed for transportation and purified to meet pipeline water and oxygen specifications. The CO2 Product Compressor in the original design compressed the carbon dioxide to 129 bar(a), the pressure required for storage at field P18. For storage in P18-4, the pipeline would operate at 80–120 bar(a) and up to 80 °C, requiring an 8 stage compressor. During development of the project an alternative storage site, the Q16-Maas condensate gas field, was selected which caused some changes to the design. For storage in Q16-Maas, the pipeline would be 19–22 bara and ambient temperature (10–30 °C), requiring a 4 stage compressor. The Q16-Maas field is much closer to the power plant, and the pipeline route to the injection well is much easier to construct. Also, because this well was drilled and is being produced from an onshore installation, this opens up the opportunity to perform the final CO2 compression close to the well. Flow assurance studies for site P18-4 had shown that the fact that the compressor and the well were separated by a long pipeline caused problems with control of the flow and formation of liquid CO2 in the pipeline during shutdown. The injection capacity is a strong function of the injection temperature. In the case of ROAD with a single source- single sink system, the temperature can be controlled via cooling at the compressor outlet. Temperature control at the injection site via heater/coolers requires additional high CAPEX and OPEX. For the ROAD project such additional wellhead temperature control was not required to obtain sufficient operational flexibility and avoid too low temperatures. This meant that compression would be split between the capture plant site and the site of the wellhead in case of the Q16-Maas field. In order to easily interface with existing infrastructure to deliver CO2 to greenhouses the pipeline pressure was selected to be 20 bar in the pipeline between the capture plant and the Q16-Maas field. More on this subject can be found in the close-out document on Transport (Uilenreef et al., 2018). The CO2 is cooled after each of the four compressor stages. Any condensed water is separated from the gas in knockout (KO) drums for each of the first three stages of compression. The original design for the

Table 2 Pipeline Design and Operating Conditions for Q16-Maas.

6

Design parameter Maximum design pressure

Value 44

Unit barg

Maximum operating pressure ROAD Normal operating pressure range Minimum operating pressure Minimum design temperature Maximum design temperature Maximum operating temperature Minimum operating temperature Technical Design Life Cover depth in pipeline corridor Cover depth for crossing pipeline corridor CO2 properties Purity H2O O2

22 19-22 1 −10 50 40 0 30 1 2.5

barg barg barg °C °C °C °C years m m

> 99% < 150 < 70

ppmv ppmv

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minimise the Joule Thomson effect and to avoid slug formation. The pipeline should be insulated to avoid heat losses. 80 °C at the pipeline inlet was found to be warm enough to avoid two-phase flow and keep the well bottom warm enough to prevent hydrate formation in the reservoir at the well bottom depth. The CO2 cools to 40–50 °C at the wellhead, and for an empty reservoir, about 10–15 °C at the well bottom. After this analysis of potential slugs during start-up, the ROAD team became increasingly confident that two-phase flow and consequent slugs can be managed without harmful effects. If the opportunity arises for further investigation, it may be possible to design the operating philosophy and equipment to tolerate two-phase flow in steady state as well as at start-up. This would make the pipeline insulation unnecessary, and allow operation of the pipeline at lower pressure, reducing the compression power requirement.

3.2.2. Slugging during restart after shutdown Two-phase flow and transient conditions of captured CO2 streams in the transport pipeline, well and reservoir requires appropriate attention to minimise slugging in the pipeline at pipeline flow start up (Uilenreef et al., 2018). Storage of CO2 in empty gas reservoirs is possible due to the specific physical and thermodynamic properties of CO2. CO2 has a critical point at 31.1 °C and 73.8 bar abs. Above this pressure the CO2 is in a dense phase, which is compressible (with an increased density at higher pressure). This creates the possibility to compress gaseous CO2 to pressures above the critical point with commercially available compressors and let the CO2 compress itself by the gravity head from the surface to the well bottom. To develop this basic idea into a practical solution for the transport and storage of CO2 the ROAD team has performed a flow assurance study in close cooperation with TNO and was made possible by the simulations with the OLGA system software, and the theoretical and practical knowledge of the TNO staff. The ROAD team has composed an extensive report on the technical issues of the transport part of the project including an explanation of the results of the flow assurance work (Uilenreef and Kombrink, 2013). The OLGA simulations indicated that at the initial phases of start-up after a plant shutdown, when the pipeline is cool, a mixed flow of liquid and vapour CO2 may occur in the pipeline. This might give operational instabilities, vibrations, unpredictable pressure drops and consequent low temperatures after mechanical constrictions. As slugging is forming a corrosive liquid, this is the reason for low water concentration in the CO2 specification. The combination of CO2 and water or O2 and water can be corrosive, but if the water is removed, there is no scope for corrosion. The water concentration was low enough to prevent preferential condensation of acids, so the composition of the liquid should be the same as the composition of the gas. However a simple and preliminary calculation of the slug behaviour suggest their moderate nature and that it is likely that the slugs do no harm to the equipment. The occurrence of slugs can further be minimised by emptying the pipeline into the well as far as possible during onshore shutdowns, and by using a low flow rate in the first phases of the start-up process. Details of the proposed control philosophy are given in Uilenreef and Kombrink (2013). The moderate behaviour of the slugs is illustrated by Fig. 5. These show the results of preliminary calculations assuming an infinite liquid slug strikes a partially open platform control valve. The peak pressure spike varies according to the assumed conditions, but the maximum calculated across a range of conditions was 110 bar. This is well below the pipeline design pressure of 140 bar. During initial operations the CO2 should be transported warm to

3.2.3. Conclusion In all cases, safe and practical designs to transport the CO2 were developed. The preferred designs were different for the two transport systems due to the different characteristics of the storage fields (offshore and very low pressure for P18-4, on-shore for Q16-Maas). This gives rise to the general lesson that the optimized transport system will depend on the storage location and characteristics. Two-phase flow and transient conditions of CO2 streams in the transport pipeline (Fig. 6) require appropriate attention to prevent slugging in the pipeline (Uilenreef et al., 2018). A task for future work is to assess whether in fact these slugs can be tolerated in steady-state operation. This would allow the pipeline to slide pressure with the reservoir, and remove the need for heating or insulation on the pipeline altogether. 4. Injection and storage 4.1. Description The CO2 would be injected from the platform P18-A into depleted gas reservoir P18-4 (Arts et al., 2012). The estimated storage capacity of reservoir P18-4 is approximately 8 million tonnes. P18-4 (Table 3) is part of the P18 block which also includes the larger P18-2 field and also a small field, P18-6. These depleted gas reservoirs are about 3.5 km below the seabed under the North Sea about 20 km from the Dutch coastline, and have a combined CO2 storage capacity of around 35 Mt. Fig. 7 shows the schematic illustration of this. A CO2 storage permit was granted in 2013, the first such permit in Europe under the EU CCS Directive (European Parliament and Council, 2009). The alternative Q16-Maas reservoir (Mikunda et al., 2015; Holleman and Last, 2017) is located just offshore from the Maasvlakte, and is reached by a long-reach well, drilled from onshore. The well is about 5 km long, and travels approximately 3 km down to reach the reservoir depth, and 3 km horizontally (off-shore) to reach the reservoir location. The reservoir is relatively new (production started in 2014) and was not due to finish production until 2022. Therefore this scheme involved the drilling of a second well to accelerate gas production and so allow CO2 injection to start in 2020. This second well would also allow co-production of modest amounts of condensate (and possibly natural gas) during CO2 injection. In a later phase, the design of the second well was changed, with enhanced hydrocarbon recovery no longer a possibility. The estimated storage capacity of reservoir Q16Maas is between 2 and 4 million tonnes (Table 3). 4.2. Storage feasibility The assessment of safe and effective storage in the P18-4 and Q16Maas gas reservoirs is completely based on existing data from the gas exploitation. No additional data needed to be acquired. The feasibility stage of the work concluded that the P18-4 gas reservoir is a suitable geological structure for CO2 storage because a thick

Fig. 5. Behaviour of CO2 vapour / liquid across a partially open Platform Control Valve. 7

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Fig. 6. Mollier diagram and compressor stages.

The Q16-Maas pre-feasibility study concluded that CO2 can be safely and securely stored in the Q16-Maas field, as the existence of the gas field proves the quality of the caprock. Two items attracted some attention, namely permeability and shallow gas. Although it can be concluded that there may be shallow gas occurrences above the Q16Maas field, the gas is unlikely to originate from this field. The storage capacity was initially estimated at 1.9 or 2.3 Mt CO2. Later reservoir analysis by ONE based on likely commercial operation including enhanced condensate recovery gave an increased estimate of the storage capacity of 2.7 Mt. In the initial stage of CO2 injection at Q16-Maas, the injected CO2 stream was meant to enhance the tail-end production of condensates. The new reservoir data released in 2017 showed a much more active aquifer in Q16-Maas than the earlier models, with faster gas production. In this scenario there is no merit in continuing production after the start of CO2 injection, ruling out enhanced condensate recovery and potential extra sales of natural gas. The estimated storage capacity is reduced slightly to 2.3 Mt. With the existing well design, the active aquifer and high reservoir pressure restricts the injection rate achievable. The target rate of 1.1 Mtpa is feasible over a short period of about 6 months; 0.2 to 0.3 Mtpa can be sustained for much longer periods. The assumed maximum down-hole pressures were 100% and 110% of the initial reservoir pressure. Due to the timing of the project termination, measures to increase the injection rate, for example by increasing the number of perforations, were not assessed. This shows the potentially strong impact of production driven field development (which includes such parameters as well lay-out and choice of production intervals) on the re-use of hydrocarbon fields for CO2 storage and, in the present case, on the potential for benefits from enhanced recovery.

Table 3 Reservoir properties of the P18-4 reservoir and Q16-Maas reservoir; numbers in italics are rough estimates. Parameter Number of wells for injection First year of gas production Gas initially in place (GIIP) Average depth of reservoir Reservoir temperature Initial pressure Abandonment pressure Average thickness Average porosity Average permeability

Unit

Year GNm3 Meter °C Bar Bar Meter mDarcy

P18-4

Q16-Maas

1 1997 3.2 3220 117 340 20 94 0.11 103

1 2014 1.6 2850 112 297 25 85 0.15 200

package of different seals is present above the storage reservoir at P184. Faults are present in the primary seal, but these faults are sealing. The reservoir has safely contained gas over millions of years. Analysis has shown that top seal integrity and fault stability are no critical factors for injection and storage at P18-4. No seismicity has occurred during production of gas at the storage location. Simulations show that in P18-4 the target rate of 1.1 Mtpa is possible and a total of 8.1 Mton CO2 can be injected. The P18-4 reservoir is bounded by a fault which separates and seals this reservoir from the P15-9 reservoir. A proper characterisation of its sealing potential is essential for the definition of the storage complex and consequently the potential measures for well abandonment in P15-9. At the start of the project it was suspected that injection of cool CO2 (8–15 °C compared with reservoir temperatures > 100 °C) may lead to the formation of thermally induced fractures so the reservoir was studied using coupled multiphase flow mechanical modelling. For P18-4, no fractures will be formed at the actual depth of the storage of 3400 m, thus injection of cool CO2 is not problematic. 8

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Fig. 7. Layout of the P18 fields, with position of wells at the top of the reservoir interval (top Bunter). Orange: P18-4 field; Red: P18-2, compartment I; Green: P18-2, compartment II; Blue: P18-2, compartment III; P18-6: field drilled by P18-06A7ST1 just north of the P18-2 field (Vandeweijer et al., 2011).

be required (only at the early phase of storage when the well pressure is low), not to install a heater and so reduce the CAPEX and the extra weight of such an installation offshore. Instead, it was decided to transport CO2 through an insulated pipeline to minimise heat loss.

4.3. Joule-Thompson cooling in the well The conventional design of dense phase CO2 in the pipeline requires it to be high pressure, and simultaneously the reservoir is low pressure. To prevent emptying of the pipeline into the well, choke valves at the wellhead or even down the well are needed. In the conceptual design phase attention was directed to the possible effects of pressure drop over choke valves in the early stages of injection. These effects may include:

4.4. Thermal effects in reservoir In the P18-4 compartment, cool CO2 will be injected into a formation with a temperature of 120 °C. The impact of fluctuations of the injection rates and that of a complete shut-in on the temperature profile away from the wellbore bottom hole within the reservoir were modelled in various scenarios. No temperatures below those of the injected fluid were observed. This means that the Joule-Thompson effect is negligible just after the start of the injection as well as immediately after a shut-in. To understand the effect of the temperature of the injected CO2 on the reservoir two injection scenarios were studied, a “warm” injection scenario with a bottom hole temperature (BHT) of 285 K and a “cold” scenario with a BHT of 259 K (Vandeweijer et al., 2011). The cold injection scenario (259 K) rapidly results in near well temperatures of 273 K, after which the reservoir simulator stopped due

a cooling down the material of the well tubing to a temperature under the minimum mechanical design temperature which can cause damage to the well tubing and equipment, b formation of solid hydrates which may plug the well piping temporarily. This process is reversible and the hydrates will decompose at higher temperature. In a feasibility study the engineering company Genesis proposed to heat the CO2 at the platform to minimise the impact of Joule-Thomson cooling in the well (Wildenborg et al., 2018). However, the ROAD team decided, considering the short period of time the heating of the CO2 will 9

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transferred to the competent authority of the Member State, subject to several conditions:

to internal model threshold. Predicting the impact of freezing conditions within the reservoir is complex. The aforementioned thermal effects are likely to be more pronounced at the lower temperatures. The cold injection may also result in freezing of the connate water in the reservoir, although CO2 injection will dry out the reservoir near wellbore and further away from the wellbore temperatures will rise. It is unknown whether freezing conditions lead to risks or technical problems during the injection. It was therefore concluded that for the moment minimising heat loss from shore to well bottom is a good policy in order avoid freezing and potential hydrate conditions in the near well area. Only after early operation or a pilot test has shown that colder injection is feasible, it may be acceptable to relax the temperature constraints of the injected CO2. Cooling of the reservoir with cold CO2 has the potential to induce thermal stresses, similar to those resulting from injection of cold water. In extreme situations the thermal stresses around the well can promote the propagation of fractures into the reservoir and possibly the caprock. This is usually called thermally induced fracturing. The fracturing will occur at the stage when the BHP exceeds the minimum horizontal stress (Shmin). Follow-up work in CATO2 (Arts et al., 2011) concluded that the lowering of this stress level due to cooling was reached at a difference in temperature between the CO2 and the reservoir rock of more than 100 °C. In case of fracturing of the reservoir rock, there is a risk of fracture growth into the caprock and mechanical damage some distance into the top seal. Although limited fracture growth into the seal may not be harmful, induced fractures still provide access routes for CO2 and connate brine penetration into the seal. The P18-4 reservoir was modelled by a modified TOUGH2/ECO2M module, which was semi-automatically coupled to the DIANA software tool (Loeve et al., 2014). The ECO2M module was modified to enable the simulation of the transition of gaseous to liquid CO2, needed for the pressure temperature conditions investigated in P18-4. From the 2D simulations and 3D simulations, it was clear that for the true depth (3400 m) of the P18-4 reservoir, no fracturing as a result of the cold CO2 is expected, which is in line with the earlier results.

• All available evidence indicates that the stored CO will be completely and permanently contained. • A minimum period after closure, to be determined by the competent 2

• •

authority has elapsed. This minimum period shall be no shorter than 20 years, unless the competent authority is convinced that the first condition above is fulfilled. The financial obligations under the financial mechanism have been fulfilled. The site has been sealed and the injection facilities have been removed. Note that the term ‘injection facilities’ is not defined in the Directive.

In ROAD’s opinion, clarity on the transfer of these responsibilities to the competent authority is one of the crucial issues, which has yet (still) to be resolved. The main concern of the ROAD project has been in which way and under which conditions the minimum period of 20 years can be reduced. Or even worse, what assurance could be provided to operators than an actual transfer of responsibilities would be allowed after 20 years. There are no technical or safety arguments as to why a minimum period would have to lapse. The greatest risk of leakage is during injection (although this risk is less than negligible, particularly for a reservoir that is only partly re-pressurised), when the well is open. After the well has been closed and decommissioned and the CO2-proof sealing has been successfully carried out, and during injection no leakages occurred, future leakages are as good as ruled out. Geomechanical analysis showed that fault stability improves as reservoir pressure increases during injection of CO2. At the end of gas production, reservoir pressure is at a minimum, causing large pressure gradients in the storage system. When no signs of leakage have been detected during the first or later phases of injection, there is no reason to assume that leakage will develop after injection is completed. The demonstration is of a limited length. A period of 20 years after injection is very costly; costs for monitoring, financial security, insurances for liabilities will continue while there is no additional income. Furthermore, a minimum period creates a great uncertainty for the ROAD project. The transfer could in theory be postponed indefinitely. The CCS Directive created a possibility to reduce the minimum period of 20 years. If all available evidence indicates that the stored CO2 will be completely and permanently contained, this minimum period can be reduced (Jonker et al., 2018). The CCS Directive only gives directions on the issues to include in permits and it was anticipated that national legislation would provide details. As Dutch legislation is not more specific where there is a gap in definition in the Directive, this gives project initiatives the opportunity to come up with their own solutions, but the disadvantage is the uncertainty every project will face in the future. The EC CCS Guidance Documents provide some guidance, but these are not legally binding, provide no detailed provisions and therefore do not harmonise the legislative provisions for different projects. Taking into account good industry practices, careful monitoring and inspection, the transfer conditions could be met relatively easily. However, in case of unforeseen circumstances, it could take a lot longer than 20 years before the competent authority agrees to the transfer, which would leave an operator (and therefore the entire CCS project) with a large amount of ‘unwanted uncertainty’. Any notional leakage duration assumed in the Financial Security calculation will be multiplied by the Emissions Trading System CO2 price for EUAs. This is an unknown multiplier making the Financial Security calculation a moving number. As part of the storage permit application and as required under the Mining Law ROAD drafted a risk management plan, a monitoring plan, a plan for corrective measures and a closure plan. These four plans

4.5. Conclusion The geological data (seismic and well data) from gas production was, for both reservoirs considered, sufficient to allow characterisation and assessment of the reservoirs for CO2 storage. No new subsurface measurements were required. The ROAD Project has shown that deeply depleted gas fields are suitable locations for CO2 storage. The fields have been selected and studied in depth. No showstoppers were found, even in detailed subsurface analysis. For P18-4, the licence process was completed and a storage licence was granted following review by the authorities. This points the way forward for future use of depleted gas fields for CO2 storage. 5. Regulation and public engagement 5.1. Regulation and permitting 5.1.1. Description The P18-4 reservoir has an irrevocable permit for the storage of CO2. To make investment decisions, long term certainty is needed. A solid understanding of the permitting procedure and planning is crucial for scheduling the project milestones including the final investment decision and properly managing delays. This in particular relates to the requirements on monitoring obligations, financial securities and transfer of responsibility (see also Jonker, 2013; Jonker et al., 2018). The CCS Directive (European Parliament and Council, 2009) states that when a storage site has been closed and decommissioned, the responsibility for all legal obligations imposed on the operator can be 10

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security, posing a heavy burden on the finance of projects. In ROAD’s opinion, clarity on the (conditions for) transfer of the responsibilities to the competent authority is one of the crucial issues that remains in the directive and still has not been solved. The current regulatory framework does not take away the risk that over time the requirements set by the authorities on the requirements for transfer of responsibility may change. After all, government policy and regulation can change over time. If one approves a plan for transfer of responsibilities today, there is still a risk that this will have changed over 20 years.

would be updated before first injection. All risks were identified and evaluated in a traffic light analysis to identify probability and consequence and a plan for mitigation. Following some requested amendments the European Commission adopted a positive opinion on the draft storage permit and the Ministry issued the permit. As outlined in all the four required plans, monitoring possibilities are very limited after the well is closed and decommissioned and the CO2 is safely and permanently stored. However the well can only be closed and decommissioned if the competent authority is confident that the stored CO2 will be completely and permanently contained. This confidence should lead to the conclusion that all available evidence indicates that the stored CO2 will be completely and permanently contained and therefore handover can be concluded after a short delay. Otherwise, the competent authority would not be able to give approval for abandonment of the well. Perhaps this part of the CCS Directive was written considering storage in aquifer formations where monitoring of the continued movement of the CO2 in the aquifer can be conducted using seismic after well closure. In a depleted pressure field the CO2 is contained in an under-pressure environment and seismic serves no purpose. In ROAD´s opinion, the CCS Directive still leaves too much room for Member States to reject permits based on the handover criteria even if all evidence indicates that the stored CO2 is completely and permanently contained. The competent authority could simply reject the closure request in order to keep the well and the monitoring possibilities open. The wells remain the only real leakage route. This creates unlimited liabilities and provides no certainty that the transfer of responsibilities will be established over time. This is unacceptable, certainly for participants in demonstration projects. Either demonstration projects need to be treated differently or depleted pressure gas fields need to be treated differently from aquifer storage, or both.

5.2. Public engagement The organisation of the ROAD project included a dedicated Stakeholder Management team, which was directed to the communication and public engagement aspects of the project (Kombrink and Read, 2018). Stakeholder management was integrated in the technical teams so that the interrelation between technical and non-technical aspects are tackled from a multi-disciplinary perspective. In this way it was prevented that the project would be locked in a purely technical tunnel vision. Stakeholder management in the ROAD project entailed the mapping of social and political issues, and of the local and regional stakeholders. This was used to develop and implement a plan for public outreach including the organisation of townhall meetings and a stakeholder roundtable. The Uniper Visitors centre was set up and a Regional Advisory Committee on CCS with public and private parties was organized. Integration of stakeholder management and project management is key in settling the many non-technical issues, which depend largely on the perceptions and interests of the stakeholders. This implies that the people in the project team should also have social skills. In engaging local communities one has to have a good insight in the local context in order to have a proper understanding of the perceptions of the local community. Engaging the public is a two-way process where pictures often say more than words can do on their own. As CCS is a measure to mitigate climate change, this transition technology has also creates socio-economic benefits for the local population.

5.1.2. Conclusion The P18-4 reservoir has an irrevocable permit for the storage of CO2. A major regulatory potential barrier lies in the treatment of the storage responsibilities and liabilities. The costs related to these long term storage responsibilities and liabilities are largely controlled by regulators and are largely out of the control of the operator. This is especially true for large-scale, long-term projects. A solid understanding of the permitting procedure and planning is crucial for scheduling the project milestones including the final investment decision and properly managing delays. One essential prerequisite for success for a CCS demo project is that the national government must strongly back the project. Without this, there is no chance to overcome the permitting, regulatory and financial challenges to the project. Timely collaboration with the government has helped ROAD to reduce the timeline between the application and issuing of the permits. Close cooperation with authorities and regulators in an early stage of the project is essential due to the complexity of CCS regulation. There is only limited experience with CCS legislation so each permit needs to be tailor made. Generally speaking, the provisions of the CCS Directive leave a lot of room for interpretation by Member States, which provides flexibility, but also leaves uncertainties for future CCS projects. The Guidance documents are only helpful to a limited extent. They are not legally binding, and are not written with a demonstration in mind or perhaps with storage in depleted pressure gas fields in mind. To make investment decisions, long term certainty is needed. This in particular relates to the freedom of member state governments to impose high barriers for projects by e.g. setting high requirements on monitoring obligations, financial securities and transfer of responsibility. As financial security requirements are not described in detail in the Directive, this leaves room for Member State governments to set the requirements on operators. This results in potential uncertainty for developers as Member States can require (unnecessary) high financial

6. ROAD highlights Capture, transport and storage technology is available and will work; remaining questions can be answered by engineering solutions. Technical solutions for reducing energy usage were not fully optimized due to time, budget and space constraints. Further performance improvement and savings in investment and operational costs are feasible for new power plants with full-scale CO2 capture. Successes included:

• FID-ready, permitted capture plant design for coal-fired power plant at 250 MWe scale • Successful design of interfaces along the whole power plant, capture, transport and storage chain • Innovative transport solution with warm CO and pipeline insulation developed. • Handling of injection of CO into low pressure depleted gas reservoirs successfully engineered. • First CO storage permit under the CCS Directive granted, with 2

2

2

permanent geological storage in TAQA’s P18-4 gas field proven to the satisfaction of Dutch and EU regulators.

Declaration of Competing Interest The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper. 11

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Appendix A. List of ROAD close-out reports https://www.globalccsinstitute.com/resources/publications-reports-research/road-project-close-out-report/.

No

Title

Scope

1 2 3 4 5 6 7 8 9 10 11

Overview Capture and Compression Transport CO2 Storage Risk Management Permitting and Regulation Governance and Compliance Project Costs and Funding Finance and Control Knowledge Sharing Public Engagement

Introduce and summarise the public close-out reports Technical report covering capture, compression and power plant integration Technical report covering CO2 pipeline transport Both technical and commercial aspects of CO2 storage for ROAD. Subsurface work required to demonstrate permanent storage is described The risk management approach used by ROAD Description of the regulatory and permitting framework and process for the ROAD project, including required changes to regulations Company structure and governance for Maasvlakte CCS Project C.V., the joint venture undertaking the ROAD Project A presentation of the projected economics of the project, with both projected income and costs Description of the financial and control systems, including the costs incurred and grants claimed Outline of the Knowledge Sharing & Dissemination plan as developed by the ROAD project and completed KS deliverables and actions Description of how ROAD organized and managed the Public Engagement process

2015.01.001. Kombrink, M., Read, A., 2018. Close-Out Report Public Engagement - Rotterdam Opslag en Afvang Demonstratieproject, vol. 11 24p. https://www.globalccsinstitute.com/ wp-content/uploads/2019/09/ROAD-Close-Out-Report-on-Public-Engagement-final. pdf. Kooistra, M., Read, A., Kombrink, M., 2018. 78p. Close-Out Report Capture & Compression - Rotterdam Opslag en Afvang Demonstratieproject, vol. 2. https:// www.globalccsinstitute.com/wp-content/uploads/2019/09/ROAD-Close-OutReport-on-Capture-and-Compression-final.pdf. Loeve, D., Hofstee, C., Maas, J.G., 2014. Thermal effects in a depleted gas field by cold CO2 injection in the presence of methane. Energy Procedia 63, 3632–3647. https:// doi.org/10.1016/j.egypro.2014.11.393. GHGT-12. Magneschi, G., Sanchez Sanchez, C., Matic, A., Stienstra, G.J., Goetheer, E.L.V., 2014. Full-scale CO2 post-combustion capture in an ultra-supercritical coal-fired power plant: an integral evaluation of capture plant configurations and heat integration options for minimising the energy penalty. VGB Powertech 4. Mertens, J., Khakharia, P., Goetheer, E., 2015. Effect of a gas–gas-heater on H2SO4 aerosol formation: implications for mist formation in amine based carbon capture. Int. J. Greenh. Gas Control 39, 470–477. https://doi.org/10.1016/j.ijggc.2015.06.013. Mertens, J., Anderlohr, C., Rogiers, P., Brachert, L., Khakharia, P., Goetheer, E., Schaber, K., 2014. A wet electrostatic precipitator (WESP) as countermeasure to mist formation in amine based carbon capture. Int. J. Greenh. Gas Control 31, 175–181. https:// doi.org/10.1016/j.ijggc.2014.10.012. Mertens, J., Khakharia, P., Rogiers, P., Blondeau, J., Lepaumier, H., Goetheer, E., Schallert, B., Schaber, K., Moretti, I., 2017. Prevention of mist formation in amine based carbon capture: field testing using a Wet ElectroStatic Precipitator (WESP) and a Gas-Gas Heater (GGH). Energia Procedia 114, 987–999. https://doi.org/10.1016/j. egypro.2017.03.1244. GHGT 13. Mikunda, T., Neele, F., Wilschut, F., Hanegraaf, M., 2015. A Secure and Affordable CO2 Supply for the Dutch Greenhouse Sector - Branche Innovation Agenda: CO2 for the Dutch Greenhouse Sector. 38p. https://www.ltoglaskrachtnederland.nl/content/ user_upload/15051.03_Rapport.pdf. Read, A., Tillema, O., Ros, M., Jonker, T., Hylkema, H., 2014. Update on the ROAD project and lessons learnt. Energy Procedia 63, 6079–6095. https://doi.org/10.1016/ j.egypro.2014.11.640. GHGT-12. Read, A., Kombrink, M., 2018. 10p. Public Close-Out Report Overview - Rotterdam Opslag en Afvang Demonstratieproject, vol. 1. https://www.globalccsinstitute.com/ wp-content/uploads/2019/09/ROAD-Close-Out-Report-Overview-final.pdf. Reddy, S., Yonkoski, J., Rode, H., Irons, R., Albrecht, W., 2017. Fluor’s Econamine FG PlusSM completes test program at Uniper’s Wilhelmshaven coal power plant. Energy Procedia 114, 5816–5825. https://doi.org/10.1016/j.egypro.2017.03.1719. GHGT-13. Rieder, A., Dhingra, S., Khakharia, P., Zangrilli, L., Schallert, B., Irons, R., Unterberger, S., Van Os, P., Goetheer, E., 2017. Understanding solvent degradation: a study from three different pilot plants within the OCTAVIUS project. Energy Procedia 114, 1195–1209. https://doi.org/10.1016/j.egypro.2017.03.1376. GHGT-13. Sanchez Fernandez, E., Bergsma, E.J., de Miguel Mercader, F., Goetheer, E.L.V., Vlugt, T.H.J., 2012. Optimisation of lean vapour compression (LVC) as an option for postcombustion CO2 capture: net present value maximization. Int. J. Greenh. Gas Control 11, 114–121. https://doi.org/10.1016/j.ijggc.2012.09.007. Sanchez Fernandez, E., Goetheer, E.L.V., Manzolini, G., Macchi, E., Rezvani, S., Vlugt, T.J.H., 2014. Thermodynamic assessment of amine based CO2 capture technologies in power plants based on European Benchmarking Task Force methodology. Fuel 129, 318–329. https://doi.org/10.1016/j.fuel.2014.03.042. Schallert, B., Neuhaus, S., Satterley, C.J., 2014. Is Fly Ash boosting amine losses in carbon capture from coal? Energy Procedia 63, 1944–1956. https://doi.org/10.1016/j. egypro.2014.11.206. GHGT-12. Uilenreef, H.J., 2011. ROAD - Control Philosophy for the Compression, Transport and Storage Sections of the MCP Project. Rotterdam, 7p. Uilenreef, J., Kombrink, M., 2013. Flow Assurance & Control Philosophy ROAD - Special Report for the Global Carbon Capture and Storage Institute. 46p. https://www. globalccsinstitute.com/publications/road-project-flow-assurance-and-control-

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