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CCS PROJECT

Feasibility Assessment of the Options for Up-scaling

Proposed CCS Facility National Grid Carbon

Report No.: 16631, Rev. 1

Document No.: 1PR8T5K-10

Date: 2015-08-28

Ref. Ares(2015)4291175 - 14/10/2015

DNV GL – Report No. 16631, Rev. 1 – www.dnvgl.com Page ii

Abbreviations

Term Definition

CCS Carbon Capture and Storage

CAPEX Capital Expenditures

DWT Deadweight Tonnage

EPC Engineering Procurement and Construction

ENVID Environmental Impact Identification

FEED Front End Engineering Design

FID Final Investment Decision

LPG Liquefied Petroleum Gas

LTCS Low Temperature Carbon Steel

MTPA Million Tonnes per Annum

OPEX Operating Expense

RCI Rotterdam Climate Initiative

DNV GL – Report No. 16631, Rev. 1 – www.dnvgl.com Page iii

Table of contents

1 EXECUTIVE SUMMARY ..................................................................................................... 1

2 INTRODUCTION .............................................................................................................. 3

2.1 Background to Study 3

2.2 Objective 3

2.3 Study Basis 4

2.4 Study Methodology 7

3 PIPELINE OPTION ANALYSIS ............................................................................................ 9

3.1 System Arrangements 9

3.2 Feasibility Design & Equipment List 11

3.3 Indicative Plant Layout 12

3.4 Transportation Capacity Assessment 14

3.5 Benefits and Limitations of Pipeline Transportation 15

3.6 Indicative Project Schedule 16

3.7 Review of Offshore CO2 Pipelines Worldwide 19

4 SHIPPING OPTION ANALYSIS ......................................................................................... 21

4.1 System Arrangements 21

4.2 Equipment List 22

4.3 Indicative Plant Layout 23

4.4 Vessel Routing 27

4.5 Transportation Capacity Assessment and Logistic Optimisation 27

4.6 Benefits and Limitations of Ship Transportation 34

4.7 Review of Similar Arrangements Worldwide 34

4.8 Tank Structure for Liquid Gas Transport 35

5 COST ESTIMATION ....................................................................................................... 37

5.1 General Notes 37

5.2 Estimate Location Cost Factor 37

5.3 Estimate Date Basis 37

5.4 Exchange Rates 37

5.5 Accuracy of Estimate 37

5.6 Cost Estimating Methodology 37

5.7 CAPEX Summary 41

5.8 OPEX Summary 42

6 COMPARATIVE COST ANALYSIS ...................................................................................... 43

6.1 20 Years Operating Life 43

6.2 40 Years Operating Life 44

7 COMPARISON OF SHIPPING AND PIPELINE OPTIONS ........................................................ 46

8 CONCLUSIONS & SUGGESTED WAY FORWARD ................................................................. 48

9 REFERENCES ................................................................................................................ 50

DNV GL – Report No. 16631, Rev. 1 – www.dnvgl.com Page 1

1 EXECUTIVE SUMMARY

National Grid Carbon (NGC) is developing a carbon dioxide transportation and storage system to support

the provision of Carbon Capture and Storage technology in the Yorkshire and Humber region.

Initially, this will involve the construction of a cross country pipeline and subsea pipeline for transporting

captured CO2 to a permanent storage site in the Bunter sandstone aquifer located within Block 5/42 of

the UK sector of the Southern North Sea.

The initial CO2 load is anticipated to be supplied by the Drax power station and will be a maximum of

2.68 Million Tonnes per Annum (MTPA). However, with this load, the utilisation of the proposed CCS

facility will be well below its capacity. NGC anticipates a second CO2 load from the Don Valley Power

project to enhance the aquifer utilisation. In addition, NGC is also seeking to review potential options for

up-scaling the CCS facility by transporting additional CO2 from Rotterdam via ship or pipeline into the

proposed injection facility.

DNV GL have been engaged by NGC to carry out a feasibility study to assess two options for up-scaling

the proposed carbon capture and storage facilities. Option 1 proposes to transport CO2 from Rotterdam

directly to the injection facility in the Southern North Sea (Pipeline Option) whilst Option 2 proposes to

transport CO2 by ship from Rotterdam to a reception facility on the River Humber, from where a pipeline

will connect into the proposed CCS Cross Country pipeline at Camblesforth multi-junction (Shipping

Option).

Three flow rates have been assessed for each option; (A) 2 MTPA, (B) 5 MTPA, and (C) 7.32 MTPA

The findings and recommendations from this study are presented in this report.

Conclusions and Suggested Way Forward

1. CO2 transportation using ships is still in the early stage of deployment. The cargo capacities of

ships in operation are below those required for the volumes in this study. However, there are

large LPG carriers in operation which are similar in design to CO2 ships. Therefore, there is no

constraint with respect to the availability of suitable ships as existing LPG ships can either be

converted or new ones built for this application.

2. The transportation of liquid gases, including liquid CO2 using ships is well established and duly

regulated, whereas specific regulations and standards applicable to pipeline transportation of CO2

are yet to be fully developed.

3. Although neither the shipping option nor the pipeline option has been implemented at the scale

being proposed for this NGC application, the study has not identified any technical challenge that

could make their implementation impracticable. Therefore, it can be broadly stated that there is

no practical limit to the amount of CO2 that could be transported using either the shipping or the

pipeline option.

4. The cost estimation results, presented in the table below in cost/tonnes CO2 transported, shows

that, in all cases, ship transportation is by far the more attractive option.


Flow Rate

Cost/tonne CO2 Transported

20 Year Operating Life 40 Year Operating Life

Shipping

Option (GPB)

Pipeline

Option (GPB)

Shipping

Option (GPB)

Pipeline

Option (GPB)

2 MTPA 9.13 16.73 4.68 8.43

5 MTPA 5.31 9.52 2.73 4.81

7.32 MTPA 4.42 8.47 2.28 4.27

5. The capital outlay associated with the pipeline option is largely responsible for this high cost of

transportation. The distance between Rotterdam and the injection platform, as well as the high

transportation pressure required means the pipeline option is unlikely to be competitive even at

very high flow rates.

6. Due to the uncertainties around the projected volumes of CO2 at Rotterdam, the ability to scale

up transportation capacity with increasing CO2 volumes, and the possibility of using the vessels

for dual service (CO2 and LPG) is considered to be a very strong enabler for the shipping option.

7. Given the attractiveness of the shipping option, it is recommended that further studies be carried

out to investigate alternative system arrangements that could improve on some of the

weaknesses highlighted in this report. The following studies are suggested:

a. Investigate the technical, logistical, and financial viability of replacing the onshore

process and intermediate storage facilities with floating storage and regasification units

in Rotterdam and UK. Using a Floating Storage (FSO) in Rotterdam and a Floating

Storage Regasification Unit (FSRU) in the UK could provide a more financially attractive

alternative due to its likely lower CAPEX and OPEX. The FSRU technology is matured and

all the required rules and regulations are in place to support their successful operation.

b. Investigate the technical and economic feasibility of direct transfer of CO2 from ship to

the injection platform. Although this arrangement will require a more specialised vessel

with a higher CAPEX compared to the one considered in this study, the overall lifecycle

cost could potentially be lower due to the elimination of land based infrastructure,

including the inter-connecting pipeline.

c. Should NGC wish to pursue further the land based loading and unloading arrangement

considered in this study, it is recommended that a more detailed analysis of the onshore

facilities be carried out to improve the accuracy of the cost estimates.


2 INTRODUCTION

2.1 Background to Study

National Grid Carbon (NGC) is developing a proposed carbon dioxide transportation and storage system

to support the provision of Carbon Capture and Storage technology in the Yorkshire and Humber region.

Initially, this will involve the construction of a cross country pipeline and subsea pipeline for transporting

captured CO2 to a permanent storage site in the Bunter sandstone aquifer located within Block 5/42 of

the UK sector of the Southern North Sea. The anticipated initial load will be a maximum of 2.68 Million

Tonnes per Annum (MTPA).

A second CO2 load is expected to be supplied by the Don Valley Power project and to enhance the aquifer

utilisation further, NGC is also seeking to review potential options for up-scaling the CCS network by

transporting additional CO2 from Rotterdam via ship or pipeline into the new injection facility.

DNV GL have been engaged by NGC to carry out a study to assess two options for up-scaling the

proposed carbon capture and storage facilities and determine their feasibility. Option 1 proposes to

transport CO2 from Rotterdam directly to the injection facility offshore North Sea (Pipeline Option) whilst

Option 2 proposes to transport CO2 by ship from Rotterdam to a facility on the River Humber, from

where a pipeline will connect into the proposed CCS Cross Country pipeline at Camblesforth multi-

junction (Shipping Option).

Figure 1 shows a schematic of the pipeline and shipping transportation options for the study

Figure 1: Shipping and pipeline transportation options

2.2 Objective

The objective of this study is to determine the feasibility of implementing pipeline and ship

transportation options for up-scaling the proposed CCS facility, and to assess the options from a cost and

technical perspective.


2.3 Study Basis

The information and assumptions that have been applied to this study are described in the following

sections.

2.3.1 CO2 Infrastructure Capacity

The proposed cross country pipeline will have a transportation capacity of 17 MTPA. However, NGC

stated that the offshore injection capacity at the Bunter sandstone aquifer is limited by the number of

injection wells to 10 MTPA and that the initial maximum CO2 supply will be 2.68 MTPA. This leaves about

7.32 MTPA of CO2 load to be supplied from other sources using either pipeline or ship transportation.

2.3.2 Proposed CO2 Flow Rate

The choice of Rotterdam as a CO2 source for the NGC CCS facility is based, among other reasons on the

availability of a large quantity of CO2 emissions in and around the area. Although the amount of CO2 that

will be available will depend on the level of implementation of CCS projects in Rotterdam, this study has

assumed that there will be no constraints with respect to availability of CO2.

To assist with understanding likely CO2 volumes that could be available from Rotterdam, DNV GL has

carried out a review of publicly available reports on Rotterdam CCS initiatives. The findings show that

carbon capture and storage in Rotterdam is a key strategy in reducing CO2 emissions by 50% in 2025

compared to 1990 levels [1]. The area surrounding the Port of Rotterdam contains a high concentration

of industrial CO2 emitters as shown in Figure 2. This high concentration of industry, together with the

proximity of the Port to the depleted gas reservoirs of the North Sea means it is ideally placed as a CO2

distribution hub.

Figure 2: CCS Developments in Rotterdam (Source: the Rotterdam Climate Initiative)


A roadmap for implementing CCS in Rotterdam produced by Rotterdam Climate Initiative (RCI) states

that over the following ten years (2015 to 2025) the amount of CO2 transported to North Sea fields for

storage will rise from 5 MTPA to 20 MTPA [1].

From the above, the projected volume of CO2 available from Rotterdam is in excess of the injection

capacity of the Bunter aquifer and as such 7.32 MTPA remains the maximum CO2 flow rate that may be

transported from Rotterdam to this injection point without drilling additional wells to increase the

capacity of the injection facility.

Given the possibility of sourcing all the CO2 needed to fully utilise the capacity of the injection facility,

and the need to understand how the two transportation options compare at different flow rates, this

study has analysed low, intermediate, and high CO2 volumes of 2 MTPA, 5 MTPA, and 7.32 MTPA

respectively. Each CO2 volume is considered to be a standalone development and analysis has been

made on this basis.

2.3.3 Rotterdam CO2 Hub

The assumption is that the Port of Rotterdam will become a CO2 hub at a future date, gathering CO2

from multiple sources and distributing CO2 for storage in multiple offshore sinks. The CO2 entering the

onshore network from emitters is assumed to be compressed and transported in dense phase (~100-120

bar). Typically, upon arrival to the CO2 hub, the CO2 will either:

Be liquefied and stored in vessels, ready for shipping to offshore locations (note that liquefied here refers to lowering of pressure and temperature of the CO2 from the dense phase for

transportation purposes. This is distinct from the dense phase CO2). Be pumped to increase pressure, ready for entering the offshore pipelines.

In some instances, CO2 will be liquefied at the emitter site and onshore transportation to the storage

vessels at the hub will be via barges. It will also be possible to vaporise the stored liquefied CO2 for

transport in the offshore pipelines. Figure 3 shows a schematic of possible CO2 routes and conditions at

the Rotterdam CO2 hub.

Figure 3: Rotterdam CO2 hub schematic from the Rotterdam Climate Initiative


2.3.4 Battery Limits For the purpose of this study, the inlet and outlet boundary limits are assumed to be as follows.

Pipeline Option:

Inlet Battery Limit: Dense phase CO2 at the port of Rotterdam

Outlet Battery Limit: Tie-in to the injection header on the injection platform, Southern North Sea

Shipping Option:

Inlet Battery Limit: Liquid CO2 at the port of Rotterdam

Outlet Battery Limit: The CO2 storage and pumping facility at the import terminal on the Humber.

For both options, the costs of the facilities required to transport CO2 from the emitters to the hub is excluded from the analysis.

Note that the shipping option requires an onshore pipeline to transfer CO2 from the import terminal to

the cross country pipeline at the multi junction. The design and costing of this onshore transfer pipeline

is outside of the DNV GL study boundary. NGC has however provided the size and costs of this pipeline

to be added onto the cost of facilities provided by DNV GL.

2.3.5 Process Design Conditions

The following conditions were applied to the sizing of process equipment and pipelines

2.3.5.1 CO2 Quality

Given that CO2 will be sourced from multiple emitters at Rotterdam, the quality of the CO2 to be

transported is not yet known. However, it has been assumed that it will meet NGC’s specification for

pipeline transportation of CO2. The gas composition provided by NGC in Table ‎2-1 represents predicted

worst case values and has been used in this study.

Table ‎2-1: CO2 Composition

Species Average Mol %

Carbon Dioxide 96.000 Argon 0.170 Nitrogen 0.802 Oxygen 0.001

Water 0.005 Hydrogen 2.000 Hydrogen Sulphide 0.002 Carbon Monoxide 0.200 Methane 0.800 NOx 0.010 SOx 0.010

2.3.5.2 CO2 Conditions at Rotterdam

CO2 is assumed to be in the dense phase at Rotterdam for the pipeline option and in the liquid phase for

the shipping option. The conditions assumed for liquid CO2, as shown in Table ‎2-2, are consistent with

available ship designs. It is worth noting that the CO2 composition provided above cannot exist in the

liquid phase at the assumed conditions due to the presence of contaminants, especially H2 (pressure

needs to be above 70 bar for it to be in the liquid phase). However, for the purpose of this study, it has

been assumed that the liquefaction process will include the removal of impurities such that the CO2 will

be liquid at the assumed conditions. This assumption has been made because if the impurities are not

removed and liquid CO2 is stored at high pressures, the shipping option is likely to become impracticable


as a new design of ships and applicable regulations will have to be developed for high pressure

transportation.

Table ‎2-2: CO2 Conditions

Shipping Option (liquid CO2)

Pressure (bar) 7 [2] Temperature (oC) -50 [2]

Pipeline Option (dense phase) Pressure (bar) 100 [3] Temperature (oC) 50 [3]*

*The maximum operating temperature of the CO2 gathering system in the referenced document has been specified as

50OC. Although it is unlikely that this high temperature will be seen in the system, it has been conservatively used in

this study to represent the worst case.

2.3.6 Injection Facility Design Conditions

The design conditions of the offshore injection facility were provided by NGC and are presented in

Table ‎2-3.

Table ‎2-3: Injection Facility Design Conditions

Minimum CO2 Delivery Pressure (barg) 100

Injection Header Design Pressure (barg) 200 Maximum allowable operating pressure (barg) 182 Injection Header Min/Max Design Temp (OC) -30 / +80

2.3.7 Ambient Conditions

Table ‎2-4 presents the ambient conditions that have been applied to the study.

Table ‎2-4: Ambient Conditions

Minimum (oC) Maximum (oC)

Rotterdam (Monthly Average) 0 (1) 22 [4] Humber (Monthly Average) 2 (2) 22 [5] North Sea 6 (3) 17 [6]

2.3.8 Equations of State

Process modelling has been performed using GERG-2008 equation of state. GERG-2008 is widely

accepted as the most accurate model currently available for describing CO2 rich streams [7]. GERG-2008

was developed by Kunz and Wagner and uses Helmholtz equations of state for modelling the contribution

of components to the stream properties, giving rise to more accurate predictions than many other

models [8].

2.4 Study Methodology

Two possibilities were considered for developing the CCS infrastructure for transporting CO2 from

Rotterdam to the North Sea injection point. One possibility is to consider the low, intermediate, and high

flow rates to be three stages of development. Alternatively, each flow rate could be considered to be a

standalone development. The latter approach has been taken in this study and this was reflected in the

facility development strategy as well as the CAPEX investment profile.


In order to deliver the requested scope of work, DNV GL used a combination of proprietary software

packages and in-house models to perform technical analysis whilst a specialist cost estimation

consultancy, Project Control Partnership, provided cost estimation support. For easy identification, the

cases analysed have been named as described in Table ‎2-5.

Table ‎2-5: Description of Cases

Case Description

Case 1A Pipeline option and 2 MTPA CO2 Case 1B Pipeline option and 5 MTPA CO2 Case 1C Pipeline option and 7.32 MTPA CO2

Case 2A Shipping option and 2 MTPA CO2 Case 2B Shipping option and 5 MTPA CO2 Case 2C Shipping option and 7.32 MTPA CO2


3 PIPELINE OPTION ANALYSIS

3.1 System Arrangements

The pipeline option comprises the onshore pumping station and the offshore pipeline. The system was

designed to deliver CO2 to the injection platform over the range of operating pressures for the proposed

offshore injection system, i.e. from 100 barg minimum to 182 barg maximum.

3.1.1 Pumping Station

As shown in Figure 4, the main equipment items at the pumping station are the CO2 pumps, supported

by utilities and the inlet facilities (pressure control valves and metering system). The CO2 pumps were

configured to have a 3x50% arrangement, i.e. two of the pumps will be in operation whilst one will be a

common spare. This arrangement ensures that there is redundancy in the system to enable continuity of

operation during unplanned downtime or a planned maintenance activity.

Figure 4: Pipeline Option Schematic

In this analysis, the minimum arrival pressure of CO2 at the injection platform is 100 barg. This is higher

than the critical point of the CO2 composition used in this study, so the requirement to ensure that CO2

remains in the dense/liquid phase throughout transportation is always met. Figure 5 shows the

conditions of CO2 from the pump suction at Rotterdam to the pump discharge and, through the pipeline

to the injection platform. The high discharge temperature of the pump can be attributed to pumping of

supercritical fluid (50OC Suction temperature). At a lower suction temperature, below the critical point,

the discharge temperature will be much lower, and consistent with temperature rises that would

normally be seen when pumping liquids.

Figure 5: CO2 Conditions during Transportation

0

50

100

150

200

250

-100 -50 0 50 100 150

Pre

ssu

re (

bar

g)

Temperature ( deg C)

dew point bubble point Case 1ACase 1B Case 1C

Pump Suction

Injection Header

Pump Discharge


The required pump discharge is dependent on the selected pipeline size and the expected arrival

pressure offshore. Larger pipeline sizes will result in lower pressure losses and conversely, smaller

pipeline sizes will result in higher pressure drops. The balance between pump duty (which impacts pump

CAPEX and OPEX) and pipeline CAPEX has been considered in selecting the pipeline sizes

3.1.2 Pipeline Routing

An infrastructure map of the North Sea was used to identify potential pipeline routes from Rotterdam to

the injection platform. Two possible routes were initially considered; Route 1 and Route 2, marked on

the North Sea infrastructure map in Figure 6. Taking into account congestion, existing pipeline routes,

and the number of crossings, route 2 has been selected as the preferred route because the proposed

pipeline could be laid alongside existing pipelines (Zeepipe and Franpipe). It is thought that due to the

existence of these large, long distance pipelines, the likelihood of obtaining the necessary permits for the

proposed pipeline will be high, and unlike route 1, deviations and construction complexity will be

minimised due to the long stretch of straight lines and less number of crossings. The total pipeline length

is estimated to be about 475 km at 60 m water depth.

Note that a detailed study has not been carried out at this stage and so the route shown in Figure 6 are

indicative and considered to be suitable for a feasibility level study. If the pipeline option was chosen,

then further investigations should be performed during pre-FEED study to optimise the routing, taking

into account costs and installation constraints.

Figure 6: Indicative Pipeline Route


3.2 Feasibility Design & Equipment List

3.2.1 Inlet Facilities

The inlet facilities are located downstream of the CO2 pipeline exit connection point at the hub and are

required to measure the flow rate and quality of CO2 to the pumping station. CO2 is controlled at the

inlet facilities to ensure that the suction pressure of the pumps is maintained within specified design

limits and any pressure changes are as smooth as possible.

3.2.2 Pipeline & Riser

As indicated in the pipeline routing schematic, the pipeline is estimated to be about 475 km at about 60

m water depth. For the purpose of this study, it has been assumed that the profile is flat at the sea bed.

In order to select a suitable pipeline size for each case, pressure drop calculations were performed for

multiple pipeline sizes. Decisions on appropriate sizes were based on high level judgements of the

balance of incremental CAPEX investment associated with larger pipeline sizes against the likely OPEX

savings on the pumping station.

The pipeline system includes a pig launcher and receiver for maintenance purposes and subsea isolation

valves, and a back pressure control valve on the platform. Based on the estimated maximum operating

pressure and temperature, standard pipeline sizes of carbon steel, API 5L Gr X65 have been selected.

Table ‎3-1: Pipeline Dimensions

Case CO2 Flow Rate

(MTPA)

Nominal

Diameter

Outside

Diameter (mm)

Wall Thickness

(mm)

Design Pressure

(barg)

Case 1A 2.00 18’’ 457 20.6 240 Case 1B 5.00 24’’ 610 27.0 250 Case 1C 7.32 30’’ 762 31.8 240

3.2.3 Pumps

The maximum duty required by the pumping station for each flow rate occurs when the injection facility

is operating at the maximum pressure. The pump duties have therefore been estimated based on the

requirement to deliver CO2 to the injection platform at the maximum operating pressure of 182 barg and

the pipeline sizes selected above.

In line with the assumed configuration, each pump has been sized for 50% of the total flow. Pumps

required for this application are likely to be multistage types because they are able to transport dense

phase CO2 and can reach much larger pressure heads than single stage pumps. Although there are

potentially different pump types and configurations that could be used to achieve the required flow

capacity and pressure, it has been assumed for the purpose of this exercise that a single multistage

pump will be used.

Table ‎3-2: Pumps Sizing Information

Case Flow

rate/pump

(m3/h)

Pump Discharge

Pressure (barg)

Offshore Arrival

Pressure (barg)

Pump Discharge

Temp (oC)

Head

(m)

Duty/Pump

(MW)

Case 1A 361 212.4 182 110 3629 1.5 Case 1B 903 221.8 182 115 3926 4.1 Case 1C 1322 210.2 182 110 3551 5.5

DNV GL is not aware of pumps of similar sizes that are operational in CO2 applications. However, upon

enquiry, a pump manufacturer, Flowserve, have claimed that the estimated operating parameters are

within the range of their heavy duty pumps for CO2 transportation;


An example of a Flowserve multistage double casing barrel pump (shown in Figure 7) is claimed to be

capable of operating in this range:

Flows up to 4000 m3/h Heads up to 6500 m Pressure up to 650 bar Temperature up to 450 OC Speeds up to 8000 rpm

Figure 7: Typical Multistage CO2 Compressor (Source: Flowserve)

3.2.4 Utilities

Utilities are required for continuous and safe operation of the land based major equipment mentioned

above. The following systems are required as a minimum:

Power Supply (primary, back-up and emergency) Vent Firewater

Instrument and Plant Air

Closed Drains Water Supply and Management (water supply, waste water, surface water)

A depressurisation system for the pipeline has not been considered for the onshore facilities because it is

assumed that a depressurisation system has already been considered for the offshore injection platform.

However, if onshore depressurisation is required at Rotterdam, the CAPEX would increase.

3.3 Indicative Plant Layout

The indicative plant layout is based on the estimated minimum separation distances at the operating

conditions and the definitions of the different areas of equipment, as specified in the NGC/MP/HS/08

guidance [8]

3.3.1 Definition of Class of Equipment

Class 1 - All areas containing a small number of valves, flanges or instrumentation and

fittings. These usually carry out a single function, such as a block valve site or a minimum

connection arrangement onto an existing pipeline system. A simple block valve installation is an

example of a Class 1 site.

Class 2 - Certain areas constructed to include a single pig trap only (e.g. the start of a pipeline

at a power station site) or a single collection of equipment (e.g. a single filter with associated

instrumentation and connections or a single meter with associated instrumentation and

connections) are classified as Class 2. They require slightly larger separation distances than a

standard Class 1 site. This could include the whole of some of the simpler Above Ground

Installations (AGIs).


Class 3 - Areas containing the range of equipment listed for Class 1 and Class 2 but, in addition,

including items such as multiple pig traps, meters, filters and pressure reduction equipment. A

typical multi-junction site would be classed as Class 3. Class 3 sites would include some more

complicated AGIs and sites with more than one pre-heater, for example.

Class 4 - Areas that contain a wide range of equipment, including items from the following:

rotating equipment, such as pumps and compressors, after coolers, separator vessels or pipe

racks, as well as the equipment present in a Class 3 area. The compressor units on a compressor

installation will be Class 4. Sites that are Class 4 will often have associated occupied buildings

and will include, for example, COMAH upper and lower tier sites.

3.3.2 Separation Distances

The minimum separation distances for the different equipment classes have been calculated for the

proposed operating conditions using the CO2 site layout tool and are detailed in Table ‎3-3 and Table ‎3-4

below. Releases of diameter 2mm, 3mm, 10mm, and 25mm have been used for the four areas,

following the approach in NGC/MP/HS/08 and calculated using the dense phase CO2 Site Layout Tool [9].

Table ‎3-3: Minimum separation distances from hazardous equipment containing dense phase

CO2 at 100 barg and 50°C (Pump Suction, Rotterdam)

Category of Plant Area

Min. Separation Distances (m)

Unprotected Equipment

Ordinary occupied buildings

Control rooms with separated

ventilation linked to gas detection

Site Boundary

Class 1 3 3 3 5

Class 2 3 4 3 7

Class 3 7 14 5 22

Class 4 13 35 13 57


CO2 at 250 barg and 110°C (Pump Discharge, Rotterdam)







Site Boundary

Class 1 3 4 3 6

Class 2 3 5 3 8

Class 3 3 17 7 27

Class 4 4 43 18 70

The estimated plot area for Case 1C based on the application of the above separation distances is 150m

x 140m (Figure 8). It is recognised that the plot size for other cases will be slightly less due to smaller

equipment footprint. However, the difference is expected to be marginal, so the estimates have not been

made for individual cases. Also, note that the sterile area for the vent stack has not been estimated, this

will need to be calculated in detail at a later stage of the project.


Figure 8: Indicative Plot Plan for Pipeline option

3.4 Transportation Capacity Assessment

There is no practical limit to the volume of CO2 that can be transported via a pipeline. However, project

economics and manufacturing limitations on auxiliary equipment may make other solutions more

attractive when considering very large flow rates. For example, for a given pipeline size, the inlet

pressure increases with increasing flow rate, so whilst the pipeline itself may not limit CO2 flow rates, the

pumps needed to achieve the required pressure head and discharge pressure may not be available, or

complex configurations may be required to make available pumps work.

9

1

2

3

5

4

6 8

7

10

70

m

43m70m70m

5m

6m

16

0m

160m

No Description

1 Inlet Facilities

2 CO2 Pumps

3 Pig Launcher

4 Closed Drain Tank/Sump

5 Drainage Interceptors

6 Instrument and Plant Air Package

7 Fire Water Pumps and Fire Water Tanks

8 Switch Room

9 Offices, Workshop, Control Room and Stores10 Vent Stack


A capacity assessment of the selected pipeline sizes and auxiliary equipment has been carried out to

understand the range of flows that can be safely transported. As shown in Figure 9, the maximum flow

rates are 4.0 MTPA, 8.9 MTPA and 15.4 MTPA for Cases 1A, 1B, and 1C respectively. For the same pump

discharge pressure, the highest flow rates occur at the minimum arrival pressure of 100 barg.

Figure 9: Pipeline Capacity Profile

3.5 Benefits and Limitations of Pipeline Transportation

3.5.1 Benefits

Some unique benefits of pipeline transportation of CO2 are listed below:

Subsea pipelines are widely used in the oil and gas industry to transport production fluids and

the design of CO2 pipelines are similar in many respects. The experience that has been gained

from many years of construction and operation of subsea oil and gas pipelines can be transferred

to CO2 applications.

The entire pipeline transportation system does not require novel technology or equipment.

Although the flow rates and the distance being considered in this instance may exceed existing

operating boundaries, there is no concern with regards to the practicality of implementation.

The thermodynamic behaviour of CO2 is known to be sensitive to some impurities. As a result, it

is common practice to remove unwanted impurities to levels that would make its transportation

possible at favourable conditions, e.g. the removal of impurities before liquefaction. Where such

impurities are not necessarily required to be removed due to end user specifications, pipeline

transportation offers a good solution since less purification will be required.

Pipelines generally have a long operating life and can continue to be used well beyond their

design life, or reused for other purposes if required

The pipeline is a simple continuous process with no requirement for managing complex logistics

0

2

4

6

8

10

12

14

16

18

80 100 120 140 160 180 200

Flo

w r

ate

(M

TPA

)

Offshore Arrival Pressure (barg)

Case 1B Case 1A Case 1C


3.5.2 Limitations

Issues that could limit the application of pipelines for CO2 transportation are listed below:

Pipeline solutions involve a large initial capital outlay, which may not be economical especially at

low flow rates. Pushing the boundaries in terms of the pipeline distance and the transportation

capacity as is likely to be the case in this application may result in even higher capital outlay.

Pipeline routes may pass through multiple territories/jurisdictions, each with a different

permitting processes and varying approvals and standards. Where this is the case, obtaining

necessary permits could be time consuming. Consequently, the total time to implement a

pipeline project could be significantly impacted. For example, it has been reported that the 808

km Cortez pipeline in the US took 8 years to complete, with only 2 of this being construction

time. The delay was caused by the need to obtain state by state permits for the pipeline routing.

Incremental development is not practicable. Upfront investment is usually required even when

the capacity of the pipeline will not be fully utilised until a distant future.

Regulations specific to pipeline transportation of CO2 are either not available or have not been

fully developed in many parts of the world. In Europe, directive 2009/31/EC which is applicable

to the geological storage of CO2 states that the framework used for natural gas pipelines is

adequate to regulate CO2 applications as well. Whilst this suggests regulatory issues would not

likely be insurmountable, it could potentially influence the perception of investors and the public

on the risks of a long CO2 subsea pipeline.

3.6 Indicative Project Schedule

The description outlined below follows a conventional approach for a facility development project with

the following key aspects:

Pre-FEED (+/-30% Cost estimate)

FEED (+/-15% Cost Estimate)

Permitting

Commercial Negotiations

Final Investment Decision (certain percentage of contract costs agreed)

Engineering, Procurement and Construction (EPC)

Commissioning and Start-up

Figure 10 is an indicative project schedule for the pipeline option. It is recognised that any CO2 export

project is likely to be carried in parallel to the gathering network projects, this schedule has not

considered any interaction with parallel projects.

With activities that can be carried out in parallel taken into account, the overall EPC schedule is therefore

estimated to be 36-40 months.


Figure 10: Indicative Project Schedule

3.6.1 Pre-Front End Engineering Design (Pre-FEED)

The aim of the Pre-FEED study is to reduce the risks in the cost estimates and schedule by evaluating a

limited number of pre-defined options and performing a “base case” design in more detail. The key

deliverables are sufficient engineering definition to prepare:

Level 2 Cost estimate (+/- 30%)

Level 2 Project Schedule

Basis of Design for the FEED

Additional Deliverables could be

Risk and Opportunity Register

HAZID Assessment

ENVID Assessment

Permitting/Consents Plan

High Level Operating Philosophy

Stakeholder Management Plan

FEED Prequalification

The timescale for a Pre-FEED study is variable depending on the extent of the options that the project

developer wishes to evaluate and the level of detail in the pre-defined deliverables. A minimum duration

to develop the basic documentation and review a few options is about 3 months. This could extend to 4

to 6 months if several options need to be evaluated or if the project is particularly difficult.

DNV GL has assumed 4 months in this analysis. Man-hour commitment and therefore costs will be

market dependent.

A prequalification and selection process for the Pre-FEED can take 2 to 3 months. DNV GL has assumed

2 months for this process.

Overall the Pre-FEED phase may therefore last 5 to 9 months. DNV GL has assumed 6 months.

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54

PreFEED

Contractor Selection

PreFEED Study

FEED


FEED Study

Permits

FID

EPC


Detail Engineering

Procurement

Construction

Commissioning

Month

Year 1 Year 2 Year 3 Year 4 Year 5


3.6.2 Front End Engineering Design

The aim of the FEED study is to reduce the risks in the cost estimates and schedule by such an extent

that an investment decision is possible. This means that the complete facility design needs to be agreed

to a significant level of detail.

The timescale for a FEED study is variable depending on the requirements of the project developer and

can typically take 6 to 9 months. DNV GL has assumed 6 months for this project phase. Manhour

commitment and therefore costs will be market dependent.

The whole prequalification and selection process can take 2 to 3 months. DNV GL has assumed 2

months for this process.

Overall the FEED phase has been assumed to be 8 months. Much of the prequalification phase can be

performed during the Pre-FEED stage of the project. However, the tender will need to include the results

of the Pre-FEED study so the time saved could potentially be about 1 to 1½ months.

3.6.3 Permits

During the pre-FEED phase identification of the required permits and local body approvals should be

initiated and a plan for obtaining the appropriate permits should be developed. During the FEED the

process for obtaining a range of permits to operate will need to be initiated.

The permitting requirements fall into 4 main categories which are environmental, safety, planning and

construction. The length of time to obtain these consents is highly project and location specific. The

permits normally can be categorised as either, local or national. Local permits are often quite hard to

achieve as they are more transparent to the local population who are more likely to lobby for changes or

cancellation. On a schedule basis however, they are often relatively short in award timescales. National

permits are usually the opposite, lengthy bureaucratic procedures but with a high degree of success.

Obtaining all the permits can typically take between 12 to 24 months.

Given that permits are likely to be required in both the UK and the Netherlands for this project, DNV GL

has assumed that permits can be obtained in 18 months.

3.6.4 Final Investment Decision

The Final Investment Decision (FID) can only be taken when:

There is sufficient belief in the certainty in the design

Permits have been obtained

Financing has been approved

The future scenarios have been tested and the project is considered to be economically robust

Diagrammatically, FID is often observed to be a point on the schedule. In reality, the FID is a process

whereby all the concerned stakeholders will re-assess the project viability from their own perspectives.

The process may take 2 to 6 months if the financial authority within the sponsoring organisation is highly

structured, for example, a government owned organisation, as it often takes longer to get all the

appropriate commitments.

DNV GL has allowed 2 months in the schedule for FID. This can be started prior to completion of the

FEED phase if required.


3.6.5 Engineering, Procurement and Construction

A typical Engineering, Procurement, and Construction (EPC) schedule comprises the following key stages:

Prequalification and contractor selection process which can take 2 to 4 months. DNV GL has

assumed 2 months for this process. This is usually started before the end of the FEED stage.

Detailed engineering design, building on the FEED documentation so that individual equipment

items can be specified in sufficient detail for procurement purposes. DNV GL has assumed 6


Procurement of equipment can vary considerably depending on the complexity of the equipment,

materials of construction, etc., and whether they are ‘one offs’ or standard ‘off the shelf’ items.

The time is also dependent on how busy the fabricators are and time of year. Based on

experience and vendor information DNV GL has assumed 12 months for this process and it is

considered to be dictated by time to procure long lead items.

Site preparation can take place in parallel with the detailed engineering and procurement phases

and is not seen as a critical path item. DNV GL has assumed 4 months for this process.

Construction can vary depending on the amount of off-site fabrication versus on-site fabrication.

Adverse weather conditions can also cause delays to the schedule. DNV GL has assumed 24


Commissioning and start-up phase follow construction and includes setting-to-work and

performance testing prior to handover of the plant. DNV GL has assumed 3 months for this

process.

3.7 Review of Offshore CO2 Pipelines Worldwide

Pipeline transportation of CO2 has been practiced for many years. Most of these have been for enhanced

oil recovery purposes, especially in the USA. Available data shows that there are over eighty CO2 pipeline

facilities/projects around the world and the majority of these are based onshore in the United States. In

the USA alone, over 5,800 km of CO2 pipeline are in operation [11]. However, there are fewer offshore

pipeline facilities/projects. In fact, the only operational offshore CO2 transport pipeline at commercial

scale is the 200 mm (8”), 153 km Snøhvit pipeline, transporting 0.7 MTPA of CO2 at 100 bar from

Hammerfest to the subsea injection well at the Snøhvit field in the Norwegian sector of the North Sea.

The Snøhvit pipeline began operation in May 2008. Other offshore CO2 pipelines that are either planned

or projects that have been cancelled are listed in Table ‎3-5


Table ‎3-5: List of Proposed/Operational Offshore CO2 Pipelines

No Project Name Country Status Length Capacity

(MTPA)

Onshore/

Offshore Sink

1 Peterhead UK Planned 116 0.7 Both Porous sandstone

2 Longannet UK Cancelled 380 10 Both Depleted oil/gas field

3 White Rose UK Planned 165 2 Both Saline aquifer

4 Kingsnorth UK Cancelled 270 20 Both Depleted oil/gas field

5 Don Valley CCS UK On Hold 390 10 Both Depleted oil/gas field

6 Teesside Low Carbon UK Cancelled 250 2.45 Both Depleted oil/gas field

7 ROAD Norway Planned 25 5 Both Depleted oil/gas field

8 Naturkraft Kårstø Norway Cancelled N/A N/A Both Porous sandstone

9 Zero Emission Porto

Tolle

Italy Cancelled N/A N/A N/A N/A

10 CarbonNet Australia Planned N/A N/A N/A N/A

11 Korea CCS 1&2 Korea Research N/A N/A N/A N/A


4 SHIPPING OPTION ANALYSIS

The shipping option consists of four different parts as shown in Figure 11. The onshore terminal in

Rotterdam for intermediate storage of the liquefied CO2 and loading to the vessel(s), the vessel(s), the

offloading terminal and intermediate storage facility on the River Humber, and the onshore pipeline

which will connect the offloading port facility with the proposed CCS Cross Country pipeline at

Camblesforth multi-junction

Figure 11: System Lay-out Block Diagram

The system layout is the same for all flow rates but the number and size of each component differ.

4.1 System Arrangements

4.1.1 Intermediate Storage Facility

CO2 is stored at the boiling point in semi-pressurized storage tanks until the ship berths at the quay.

Semi-pressurized storage is common for other liquefied gases such as LPG and ethylene. The most

common methods are: semi-pressurized spheres, semi-pressurized cylindrical tanks, or underground

storage in caverns. For the purpose of this study, above ground spherical tanks have been assumed. The

cylindrical tank option was rejected due to the manufacturing limitation in tank diameter and holding

capacity. Underground storage was also rejected due to its complexity. The underground storage options

may be investigated at a later stage if a detailed study of the storage options is performed.

4.1.2 Loading and Unloading Facilities

The loading and unloading facilities consist of the quay and the loading/unloading system. The

loading/unloading system at the quay transfers liquefied CO2 from the storage tanks to the ship. The

loading/unloading system includes all the necessary piping between the tanks and the ship, as well as

pumps, loading and offloading arms and a return line for CO2 vapour generated at the ship. The

approach for managing boil off gas has not been investigated as part of this study. It has been assumed

that this will be studied in detail during a pre-FEED study.

The loading/unloading systems and materials should be carefully chosen, taking into consideration their

resistance to corrosion and low temperature as well as maintenance and cost of operation.

Due to the potential for liquid CO2 to form dry ice, care must be taken in the entire process (process

plant, storage and loading and unloading) to avoid dry ice formation.

4.1.3 Vessels

Economic large-scale transport of CO2 by ship could be carried out by using semi-refrigerated (semi-ref)

vessels at pressures and temperatures near to the triple point of the CO2 being transported e.g. at 6.5

bar and -52 °C. In semi-ref ships the CO2 is kept in the liquid phase on the saturation line by a pressure

Intermediate

Storage Facility

Loading

Facility Vessel(s)

Unloading

Facility

Intermediate

Storage

Facility

Onshore

Pipeline

River Humber Receiving Facility

Rotterdam Supplying Facility


higher than atmospheric pressure and a temperature lower than the ambient temperature. An additional

advantage of transporting CO2 under these conditions is that it has the highest density possible in these

conditions in the liquid state, resulting in a lower unit cost for transportation. Semi-ref ships are usually

designed for a working pressure of 5 to 7 bar and operate at low temperatures (-48°C for LPG, -104°C

for ethylene).

The most common type of semi-ref ship is the LPG tanker. The largest semi-ref LPG tankers currently

under construction and in operation can transport approximately 20,000 m3. Such vessels generally have

2 to 6 tanks, and each tank may have a capacity of 4,500 m3.

Due to the lack of large CO2 carriers suitable for this application, semi-pressurized LPG vessels have

been used as reference vessels to develop the operational profile, OPEX and simulation of the logistic

chain. Also, the technical data for the reference vessels have been used to calculate the fuel

consumption and voyage costs.

4.1.4 Onshore pipeline

The onshore pipeline will connect the offloading port facility with the proposed CCS Cross Country

pipeline at the Camblesforth multi-junction. This will require a 60km pipeline with a diameter depending

on the flow rate. NGC has predicted the pipeline sizes to be 14”, 20”, and 22” for cases 2A (2 MTPA), 2B

(5 MTPA), and 2C (7.32 MTPA) respectively.

4.2 Equipment List A high level list of equipment for the shipping system arrangement is shown in Table ‎4-1 and Table ‎4-2

Table ‎4-1: Equipment List -Port of Rotterdam

S/N Equipment Comments

1 Centrifugal Pump (cryogenic service) Flow rate 1048 m3/h per pump

2 Electrical Power Supply

3 Loading Arms (8”) 2 arms, flow rate 1051 m3/h

4 Vapour return (6”) 1 line, flow rate 591 m3/h

5 Storage Tank (cryogenic service) Spherical Type C tanks

6 Vent System

7 Control and Instrumentation System

8 Service water, portable water, closed drains, open drains


Table ‎4-2: Equipment List -Onshore UK

S/N Equipment Comments

1 Centrifugal Pump (cryogenic service) Flow rate 1048 m3/h per pump

2 Electrical Power Supply

3 Unloading Arms (8”) 2 arms, flow rate 1051 m3/h

4 Vapour return (6”) 1 line, flow rate 591 m3/h

5 Storage Tank (cryogenic service) Spherical Type C tanks

6 Vent System

7 Heater Water bath or similar

8 Control and Instrumentation System

9 Service water, portable water, closed drains, open drains

4.3 Indicative Plant Layout

4.3.1 Separation Distances

The minimum separation distances for the different equipment classes have been calculated for the

proposed operating conditions using the CO2 site layout tool and are detailed in Table ‎4-3 below.

Releases of diameter 2 mm, 3 mm, 10 mm and 25 mm have been used for the four areas, following the

approach in NGC/MP/HS/08 and calculated using the dense phase CO2 Site Layout Tool.


CO2 at 7 barg and -50°C (Rotterdam)




Ordinary occupied

buildings



Site Boundary

Class 1 5 5 3 6

Class 2 6 6 3 9

Class 3 13 18 7 29

Class 4 22 50 16 81



CO2 at 147 barg and -43.5°C (Pump Discharge UK)






ventilation linked

to gas detection

Site Boundary

Class 1 7 7 3 5

Class 2 9 9 3 7

Class 3 20 20 6 31

Class 4 37 48 15 77


CO2 at 146.5 barg and 5°C (Pipeline Inlet UK)






ventilation linked

to gas detection

Site Boundary

Class 1 5 5 3 5

Class 2 7 7 3 7

Class 3 17 17 6 28

Class 4 32 43 14 71

The estimated plot area for Case 2C in Rotterdam and in the UK based on the application of the above

separation distances are 260m x 260m and 280m x 260m respectively (Figure 12 and Figure 13). It is

recognised that the plot size for other cases will be slightly less due to smaller equipment footprint.

However, the difference is expected to be marginal, so the estimates have not been made for individual

cases. Note that the sterile area for the vent stack has not been estimated, this will need to be

calculated in detail at a later stage of the project.


Figure 12: Indicative Plot Plan for Shipping Option at Rotterdam

5

4

6

8 7

9

1 1

1 1

2

3

240m

260

m

81

m

50

m

81m81m24m

No Description

1 Intermediate Storage Tanks and Pumps

2 Loading Arms

3 Offices, Workshop, Control Room and Stores





8 Switch Room

9 Vent Stack


Figure 13: Indicative Plot Plan for Shipping Option at the Humber

54

6

8

7

9

1 1

1

2

3

10

11

12

77m37m

7m

77m

37m

37m

37m

50m

77m

260m

260m

No Description

1 Intermediate Storage Tanks and Pumps

2 Loading Arms

3 Offices, Workshop, Control Room and Stores





8 Switch Room

9 Vent Stack

10 CO2 Pumps

11 Pig Launcher

12 Heater


4.4 Vessel Routing

The distance between Rotterdam and River Humber is estimated to be about 210 nm. The transit time

varies depending on the speed but at this stage, with a high level operational profile assumed, the

sailing time for the different speeds is calculated as shown in

Table ‎4-6

Table ‎4-6: Vessel Transit Times

Speed (knots) Transit time (hours)

10.5 20 11 19.1

11.5 18.3 12 17.5

12.5 16.8

13 16.2

13.5 15.6 14 15

4.5 Transportation Capacity Assessment and Logistic Optimisation

Although the system arrangement is the same for all flow rates, there are significant differences in the

number and size of storage tanks, as well as the number and size of ships required for each case.

To estimate the storage tank capacities, the following principles have been applied.

Rotterdam: It has been assumed that the onshore intermediate storage tank capacity will be

approximately 2 times larger than the vessel capacity. The additional capacity is included as a buffer in

case there is disruption in the vessel schedule and the vessel cannot be at Rotterdam on time to load the

cargo. The CO2 capture, flow, and supply are assumed to be continuous and therefore a tank buffer is

needed to prevent overflow.

Onshore UK: For the discharging terminal in the UK, the capacity of the intermediate storage tank is

assumed to be equal to the vessel capacity. It is considered that the cargo will be transferred

immediately to the pipelines after discharge and therefore will not require such big holding capacity as in

Rotterdam.

The above assumptions will ensure the tanks are adequately sized to provide enough holding capacity as

well as operational margin during the storage, loading/unloading.

To overcome any challenges with constructing large storage tanks, multiple tanks of smaller sizes have

been assumed for very large storage requirements.

The main sizing parameters for the shipping option are presented in the following sections.

4.5.1 Case 2A – Shipping option and 2 MTPA CO2

Assuming continuous flow of CO2 into the Camblesforth multijunction, the flow rate is calculated as

shown in Table ‎4-7

Table ‎4-7: CO2 Flow Rate (2 MTPA)

Annual Volume (tons) 2,000,000

Annual Volume (m3) 1,739,130 Daily Volume (tons) 5,479 Daily Volume (m3) 4,765


Vessel

The details of the CO2 carrier vessel required to transport 2 MTPA CO2 is shown in Table ‎4-8.

Table ‎4-8: Vessel Profile (12k DWT)

VESSEL SPECIFICS

Liquid gas capacity 10,000 m3

Cargo tank utilization* 95%

Deadweight (DWT) 12,000 tons

Gross Tonnage 9,500 tons

Length Overall 135 m

Breadth 20 m

Main Engine installed power 5,826 kW

Service speed** 15 knots

Auxiliary Engine (3 units) installed power (per engine) 1,024 kW

*5% of the cargo tank capacity must be left in the tank for keeping the tank cold when it is empty

** Service speed is the speed that the vessel has been designed to sail and does not mean that this is the speed it

will actually operate. The average sailing speed is given in the table below

Considering the operational profile of the vessel given above, and the required CAPEX/OPEX, it was

estimated that one (1) vessel will be required, calling in Rotterdam every second day. The number of

trips per year has been calculated as shown in Table ‎4-9

Table ‎4-9: Vessel Trips per Year (Case 2A)

Operational Profile

Loading time 4.8 hours

Discharge time 4.8 hours

Maneuvering and Vessel Preparation Rotterdam 2.0 hours

Sailing speed (average including slow steaming at port limits)

13 knots

Sailing Rotterdam - UK 16.2 hours

Maneuvering and Vessel Preparation UK 2.0 hours


Sailing UK - Rotterdam 16.2 hours


Operational days per year 360 days

Total 50 hours

Total 2 days

Trips per year 173


Figure 14 shows a graphical representation of the time schedule to complete a full roundtrip.

Figure 14: Example Ship Schedule (Case 2A) Fuel consumption and storage tank sizes that have been used in calculating the CAPEX and OPEX estimates are presented in Table ‎4-10 to Table ‎4-12.

Table ‎4-10: Fuel Consumption (7.5k DWT Ship)

Speed Fuel Consumption (t/day)

14 knots 18.0

13 knots 14.6

12 knots 11.5

Table ‎4-11: Intermediate Storage Tanks – Rotterdam (Case 2A)

Storage Tanks - Rotterdam

Number of tanks 2

Capacity of each tank* 10,000 m3

Tank diameter 27 m

Required capacity 10,000 m3

Additional capacity 10,000 m3

Size of storage capacity compare to vessel capacity 2 x

Total Capacity 20,000 m3

*the size of the tanks is restricted by the tank diameter (maximum possible diameter: 27m)

Table ‎4-12: Intermediate Storage tanks – UK (Case 2A)

Storage Tanks – Onshore UK

Number of tanks 1


Tank diameter 27 m


Additional capacity -

Size of storage capacity compare to vessel capacity Same size


0 10 20 30 40 50

Case 2

A -

Vessel

1

Hours

Loading time (00:00-05:00)

Maneuvering Rotterdam (05:00-07:00)

Sailing Rotterdam - UK (07:00- 23:00)

Maneuvering UK (23:00-01:00)

Discharge time (01:00-06:00)

Maneuvering UK (06:00-08:00)

Sailing UK - Rotterdam (08:00-00:00)

Maneuvering Rotterdam (00:00-02:00)

DAY 1 DAY 2 DAY 3


4.5.2 Case 2B – Shipping option and 5 MTPA CO2 Assuming continuous flow of CO2 into the Camblesforth multijunction, the flow rate is calculated as shown in Table ‎4-13

Table ‎4-13: CO2 Flow Rate (5 MTPA)



Vessels

The details of the CO2 carrier vessel required to transport 5 MTPA of CO2 is shown in Table ‎4-14:


Vessel Specifics





Length Overall 158 m

Breadth 21.3 m

Main Engine installed power 5,826 kW

Service speed ** 15 knots

Auxiliary Engine (3 units) installed power (per engine) 1,024 kW

*5% of the cargo tank capacity must be left in the tank to keep the tank cold when it is empty



Considering the operational profile of the vessel given above and the required CAPEX/OPEX, it was

estimated that two (2) vessels will be required, each vessel calling in Rotterdam every third day. The

number of trips per year has been calculated as shown in Table ‎4-15

Table ‎4-15: Vessel Trips per Year (Case 2B)

Operational Profile

Loading time 7.6 hours

Discharge time 7.6 hours


Sailing speed (average including slow steaming at port limits)

10.5 knots







Total 63 hours

Total 2.63 days

Trips per year (per ship) 137


Figure 15 shows a graphical representation of the time to complete a full roundtrip with 2 vessels in

operation:

Figure 15: Example Ship Schedule (Case 2B)

Fuel consumption and storage tank sizes that have been used in calculating the CAPEX and OPEX

estimates are presented in Table ‎4-16 to Table ‎4-18.

Table ‎4-16: Fuel Consumption (16k DWT ship)

Speed Fuel Consumption

14 knots 18.3 t/day

13 knots 15.1 t/day

12 knots 11.9 t/day

Table ‎4-17: Intermediate Storage tank - Rotterdam (Case 2B)


Number of tanks 4


Tank diameter 25 m


Additional capacity 16,000 m3

Size of tank compare to vessel capacity 2 times bigger



Table ‎4-18: Intermediate Storage Tank – UK (Case 2B)


Number of tanks 2


Tank diameter 25 m


Additional capacity - m3

Size of tank compare to vessel capacity Same size


0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75

Vessel 2

Vessel 1

Hours

Loading time (Ves. 1: 00:00-08:00)(Ves. 2: 09:00-17:00)

Maneuvering Rotterdam (Ves 1: 08:00-10:00)(Ves. 2: 17:00-19:00)

Sailing Rotterdam - UK (Ves. 1: 10:00- 06:00)(Ves. 2: 19:00-15:00)

Maneuvering UK (Ves. 1: 06:00-08:00)(Ves. 2: 15:00-17:00)

Discharge time (Ves. 1: 08:00-16:00)(Ves. 2: 17:00-01:00)


Sailing UK - Rotterdam (Ves. 1: 18:00-14:00)(Ves. 2: 03:00-23:00)

Maneuvering Rotterdam (Ves1: 14:00-16:00)(Ves. 2: 23:00-01:00)


Maneuvering Rotterdam (Ves 1: 00:00-02:00)

DAY 1 DAY 2 DAY 3 D4

Loading

Manoeuvring

Sailing

Discharge


4.5.3 Case 2C – Shipping option and 7.32 MTPA CO2

Assuming continuous flow of CO2 into the Camblesforth multijunction, the flow rate is calculated as

shown in Table ‎4-19

Table ‎4-19: CO2 Flow Rate (7.32 MTPA)



Vessels

The details of the CO2 carrier vessel required to transport 7.32 MTPA of CO2 is shown in Table ‎4-20


Vessel Specifics





Length Overall 159.7 m

Breadth 26.6 m

Main Engine installed power 7310 kW

Service speed** 16.5 knots

Auxiliary Engine (3 units) installed power (per engine) 1024 kW

*5% of the cargo tank capacity must be left in the tank to keep the tank cold when it is empty



Considering the operational profile of the vessel given above and the required CAPEX/OPEX, it was

estimated that two (2) vessels will be required, each vessel calling in Rotterdam every 2.5 days. The

number of trips per year has been calculated as shown in Table ‎4-21

Table ‎4-21: Vessel Trips per Year (Case 2C)

Operational Profile

Loading time 10 hours

Discharge time 10 hours


Sailing speed (average including slow steaming at port

limits)

14.5 knots







Total 57 hours

Total 2.37 days

Trips per year (per ship) 152


Figure 16 shows a graphical representation of the time to complete a full roundtrip with 2 vessels in

operation:

Figure 16: Example Ship Schedule (Case 2C)

Fuel consumption and storage tank sizes that have been used in calculating the CAPEX and OPEX

estimates are presented in Table ‎4-22 to Table ‎4-24.

Table ‎4-22: Fuel Consumption (24k DWT Ship)

Speed Fuel Consumption

14 knots 25.6 t/day

13 knots 21.1 t/day

12 knots 17.1 t/day

Table ‎4-23: Intermediate Storage Tanks - Rotterdam (Case 2C)


Number of tanks 4


Tank diameter 27 m


Additional safety capacity 19,000 m3

Size of tank compare to vessel capacity 1.9 times bigger



Table ‎4-24: Intermediate Storage Tanks - UK (Case 2C)


Number of tanks 3


Tank diameter 25 m


Additional safety capacity 3,000 m3

Size of tank compare to vessel capacity 1.1 times bigger


0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75

Vessel 2

Vessel 1

Hours


Maneuvering Rotterdam (Ves 1: 08:00-10:00)(Ves. 2: 17:00-19:00)

Sailing Rotterdam - UK (Ves. 1: 10:00- 06:00)(Ves. 2: 19:00-15:00)


Discharge time (Ves. 1: 08:00-16:00)(Ves. 2: 17:00-01:00)


Sailing UK - Rotterdam (Ves. 1: 18:00-14:00)(Ves. 2: 03:00-23:00)

Maneuvering Rotterdam (Ves1: 14:00-16:00)(Ves. 2: 23:00-01:00)


Maneuvering Rotterdam (Ves 1: 00:00-02:00)

DAY 1 DAY 2 DAY 3 D4


4.6 Benefits and Limitations of Ship Transportation

Some unique benefits of CO2 transportation using ships are listed below:

Shipping can be a cost-effective transport option especially for smaller projects with low volumes

and projects that are still at an embryonic stage, and for projects with long transport distances

Short delivery time of CO2 ships from order can offer a competitive advantage

Offers the flexibility of using the ships in several projects and therefore the ship operators can

have full utilization of the ship

Ships offer the ability to collect CO2 from existing industrial sources with moderate capital costs

compared to new pipelines.

Increase transport capacity at relatively low capital cost by adding further ships to the system

A further advantage may arise from the capability of ships designed for CO2 transport to carry

LPG as an alternative cargo, meaning the ships and operators can utilize additional revenue

streams.

Shipping of liquid CO2 at large scale is feasible with known technologies and can provide a

transport system that is flexible in terms of space and time

Regulations covering the vessel design, construction and safe operation are in place, fully

developed and tested for many years in the LNG and LPG industry

An existing semi-ref LPG carrier could be converted for CO2 duty, thus minimising initial CAPEX

Lower CAPEX than pipeline option.

4.6.1 Limitations

There are also a number of issues that need to be considered for the shipping option, but without

necessarily being showstoppers to the investment. Some of these are listed below:

Intermediate storage of liquid CO2 is necessary between liquefaction and ship loading and this

requires additional CAPEX and OPEX for the holding facilities

Unexpected downtime of the ship might be experienced due to a potential mechanical failure or

collision/grounding/bad weather and this will affect the logistics. A higher intermediate holding

tank capacity might be needed in case of emergency in order to be able to handle CO2 overflow.

Higher yearly operational costs (vessel, crew, port fees etc.)

Shipping operations will be an entirely new business area to NGC

4.7 Review of Similar Arrangements Worldwide

The use of ships for transporting CO2 is in its embryonic stage. Existing experience in liquid CO2 shipping

is limited to a small fleet of small ships used in the European trade of CO2 for industrial uses. The total

European trade volume in CO2 as an industrial gas is mostly utilized in the food and drinks industry

Much of this is derived as a co-product of hydrogen production by the major industrial gas suppliers and

is generally transported by truck or train overland. The ammonia producer, Yara International, trades

much of its CO2 by-product and transports it by sea from production sites in Norway and the Netherlands

to seven import and distribution terminals around western European coasts. Of their original fleet of four

tankers, three are now operated by Larvik Shipping: Yara I and II, at 900 t each, and Yara III, 1200 t


(Larvik, 2014). Yara themselves have two recently reconditioned LPG tankers for CO2 transport, Yara

Embla and Yara Froya, each carrying 1800 t (Yara, 2013). All these ships are rated for higher pressures

than discussed above, they carry CO2 at 15-20 bar and around -30°C.

The Dutch shipping company Anthony Veder also operates one 1250 m3 CO2 tanker rated for 18 barg

and -40°C (Anthony Veder, 2014). This is variously listed as an LPG tanker, so is probably dual purpose.

This ship carries CO2 for the Linde group, mainly in the Baltic. The operator may have other dual-

purpose LPG tankers in use for carrying CO2. Beyond this, the shipping company IM Skaugen has six

10,000 m3 ships in their fleet which are rated to 7 bar, -104°C, and are registered for carrying liquid CO2,

however, their normal cargo is LPG. The company has been involved in CCS project development but it is

not clear if the ships have yet been used for CO2 transport.

4.8 Tank Structure for Liquid Gas Transport

CO2 carriers are designed according to the same standard, the International Gas Carrier Code, as other

liquid gas carriers, such as LNG (Liquefied Natural Gas) and LPG (Liquefied Petroleum Gas) carriers, and

it is expected that future designs will draw heavily on experience from existing gas carriers and will be

similar in design.

The LPG market is well developed and there are more than 1,000 LPG tankers of various sizes in traffic:

Pressure type: capacity < 5,000 m3

Semi-refrigerated (‘semi-ref’) type: capacity 5,000-20,000 m3

Low temperature type: capacity > 20,000 m3

Semi-ref LPG carriers come in sizes larger than existing CO2 carriers and have storage conditions similar

to those required for CO2, which makes a strong case for converting LPG tankers for CO2 and/or

alternating between LPG and CO2.


Semi-pressurized ships are usually designed for a working pressure of 5 to 7 bara and operate at low

temperatures (-48°C for LPG, -104°C for ethylene). This is the most common type of ship for LPG

transport up to nearly 20 000 m3. Such vessels normally have 2 to 6 tanks, and each tank may have a

capacity of 4500 m3. CO2 exists in liquid form at pressures between 5.2 bara, triple point (TP), and 73

bara, critical point (CP), hence semi-pressurized ships must be used for the transport of CO2.

Most of the particular design requirements for CO2 carriers are system related. Taking into account the

design pressures, temperatures and the density of CO2 (heavier than water), no special structural tank

design considerations are necessary beyond what are normally required for traditional type C-tanks.

Type C-Independent Tanks

Type C-tanks are normally spherical or cylindrical capable of containing cargoes with gauge pressure

higher than 2 bar. If appropriate low-temperature steels are used in the tank construction, they can, in

addition to semi-pressurized, also be used for fully-refrigerated carriage. For semi pressurized ships the

tanks may be designed for gauge pressures up to 8 bar.

The material typically used for such application is the carbon-manganese steel for low temperature

service shown in the table below. The table is extracted from the DNV Rules for Ships / High Speed,

Light Craft and Naval Surface Craft, January 2014, Pt.2 Ch.2 Sec.2 Rolled steel for boilers, pressure

vessels and special applications.


5 COST ESTIMATION

The overall estimates are a combination of CAPEX and OPEX costs from Project Control partnership (PCP),

DNV GL, and NGC. PCP provided the CAPEX and OPEX estimates for the pipeline option as well as the

land facilities associated with the shipping option. DNV GL provided CAPEX and OPEX estimates for the

ship whilst NGC provided the CAPEX and OPEX estimates for the onshore pipeline required to transfer

CO2 from the Humber to the multijunction.

The following sections describe the assumptions, methodology, and summary of the estimates. A more

detailed analysis of the costs can be found in Appendix A and Appendix B.

5.1 General Notes

The basis of this estimate was to use Level 1 estimating techniques from PCP’s Conceptual Estimating

manual. This manual is intended to enable the user to prepare a conceptual estimate with only a limited

amount of engineering information.

5.2 Estimate Location Cost Factor

The cost estimating system is based on construction in Northern Europe so no further adjustment is

required.

5.3 Estimate Date Basis

The estimate has been prepared on a 2Q 2015 basis and no forward escalation is included.

5.4 Exchange Rates

The estimate has been prepared in British Pounds.

This estimate reflects the following exchange rates:

£1.00 GBP = $1.55 USD

£1.00 GBP = €1.38 EUR

5.5 Accuracy of Estimate This estimate was prepared using a Level 1 estimating methodology basis and should be considered to have an accuracy of +/-50%

5.6 Cost Estimating Methodology

5.6.1 Process Equipment Pricing

Major process equipment items were estimated using PCP in-house proprietary software based on the

key technical parameters. For the purposes of the estimate it has been assumed that the large scale CO2

storage will be in LTCS spheres with a maximum diameter of 27m.

Offsites & Utility Units have been priced based on analysis of the historical relationship between these

units and the total process units cost based on data from the analysis of other oil and gas production

facility projects. It is assumed the sites will be standalone with imported power supply.

5.6.2 Process Plant ‐ Other Direct Costs

The cost of bulk materials, such as piping, instrumentation, electrical materials, civil works, structural

steel and their field erection have been pro-rated from the equipment cost using factors from PCP’s


Conceptual Estimating manual. These factors have been developed from an extensive analysis of the

historical construction costs of similar CO2 processing units.

5.6.3 Shipping, Customs Clearance and Land Transport

It is assumed that the majority of materials will be purchased from European suppliers. Shipping &

customs clearance has been estimated using rates developed from historical analysis of similar projects.

5.6.4 Construction Management

It is assumed that the field erection will be performed by a series of specialist subcontractors for each of

the main disciplines such as civil works, piping etc. and the EPC contractor will verify the quality of the

work, co-ordinate the contractors & generally to manage the construction effort.

These construction management costs have been taken as a percentage of the total field erection costs

based on experience from other similar projects. This includes for the managing contractors construction

staff, quantity surveyors, secretaries, clerks, staff, accommodation and travel. It also includes the

temporary offices, warehouses, lay down areas, office, supplies and reproduction costs, general support

(e.g. drivers, cleaners, warehousemen, material, offloading gang, etc.), electricity, fuel and maintenance,

catering and communications.

5.6.5 Design & Engineering, Procurement and Project Management

The engineering design, procurement, and project management hours have been developed using data

from the Conceptual Estimating Manual as a ratio to total construction manhours.

These engineering hours were priced at GBP £80 per hour; this rate assumes that all the engineering

activities will be carried out in Europe.

5.6.6 Offshore Pipelines

Pipeline material costs have been developed from PCP proprietary estimating systems and cross-checked

against recent quotations obtained for other projects. It should be noted that the lengths used as the

basis of the estimate include an allowance for route deviation and ‘overage’ developed from analysis of

similar historical projects.

Weights for the anodes were generated using calculations from the PCP Subsea Estimating Systems and

priced using in-house data from recent projects.

The types, length, and thicknesses of corrosion coatings were generated using PCP’s proprietary

estimating system.

The quantities and lengths of the Tie-In Spools were developed from the PCP Subsea Estimating Systems

priced at current average costs per tonne from recent projects in the region. Tie-in spool installation

durations were developed based upon the spool dimensions and weights and norms from the PCP Subsea

Estimating Systems.

Route and Geophysical Survey durations and costs have been taken from the PCP Subsea Estimating

Systems.

Pipeline installation durations and costs have been developed using the PCP Estimating Systems and are

based on previous lay experience in the region.

Pipeline installation consumables are the items used during the pipeline installation including welding

materials, spacers, etc. They have been included in the estimate based on a cost per pipeline joint for

the PCP Subsea Estimating Systems which varies depending upon the line size etc. Pre/Post Lay Survey


durations have been based on continuous monitoring of the pipeline installation and rock dumping

activities and priced at current project actual rates from recent project analysis.

It has been assumed that Pipeline trenching and backfill will not be required.

Quantities for gravel dumping has been taken from the PCP Subsea Estimating Systems and costs

developed based upon the pipeline lengths, diameters, and criteria in the PCP Pipeline Estimating System,

including typical span lengths and berm profiles. It is assumed that gravel dumping will only be required

for span protection and limited lengths of pipeline protection.

It has been assumed that the entire length of each of the tie-in spools will be protected with concrete

mattresses; quantities of mattresses required for spool protection have been calculated from the spool

dimensions using a typical mattress size of 6m x 3m. Installation durations and mattress costs have

been developed from a recent similar project in the region.

Hydrotesting and commissioning durations and costs have been developed based upon criteria from the

PCP Subsea Estimating System.

5.6.7 Ship CAPEX

Since there are no CO2 vessels with large carrying capacity, semi refrigerated LPG carriers of similar

sizes have been used as reference. Specific CAPEX assumptions, taken from the Clarkson’s database and

the DNV GL internal database, with prices reported for 2014, are considered to be representative of the

market today and have been applied as follows:

Case 2A – Vessel Newbuild Price: 3,650 USD/m3 (2,348 GBP/m3)

Case 2B – Vessel Newbuild Price: 2,400 USD/m3 (1,543 GBP/m3)

Case 2C – Vessel Newbuild Price: 1,950 USD/m3 (1,250 GBP/m3)

5.6.8 Owner’s Costs

Owner’s management costs cover salaries, departmental overhead costs, travel costs and outside

consultants employed by the owner to control and manage the work.

Allowance is also included for insurance and 3rd party verification which would normally come under the

Owner’s scope.

5.6.9 Contingency

Contingency is normally applied to an estimate to provide a reasonable level of confidence of avoiding

project overruns. Owners’ contingency is normally applied to cover project scope changes and other

unforeseen items. It is not to cover items that could be reasonably anticipated, such as piping clashes,

for which an allowance has been included in the base estimate. Contingency has been added at 15% of

the total EPC Cost.

5.6.10 Operating Costs

The figures for maintenance, operating personnel and insurance costs have been calculated based upon

the Capital Costs, using percentages developed from recent project experience. Maintenance costs

include for regular inspection, repair, and replacement where necessary for all project elements.

Property overhead costs can vary very dramatically between different projects and locations depending

upon local authorities and government policy. They have therefore been excluded from this operating

cost estimate.


Imported Power has been based on a historical cost per kWh. Fuel Gas for the Gas Heaters is currently

excluded

The shipping option has also included voyage related costs, the VOYEX1. The VOYEX parameters include

the annual fuel cost and the port fees for the vessel(s) to call in the ports of Rotterdam and UK. For the

port fee calculation, the port fee calculation methodology and prices stated in the Rotterdam Port Guide

has been used and a 25% discount is applied as a frequent caller. The vessel is burning Marine Diesel Oil

(MDO) during operation due to emission control areas (ECA) established in the North and Baltic Sea. In

order to calculate the annual fuel cost for each vessel the following assumptions have been used:

360 operational days

Fuel consumption for each vessel as stated in chapter ‎4

MDO fuel price is assumed to be 600 USD/ton (385 GBP/ton)

From the VOYEX calculation, the tug assistance and use of a pilot have been excluded. It is assumed that

the vessel will have the required manoeuvrability capacity to navigate independently in the port and the

captain of the vessel will receive the pilot exemption certificate from the port authorities.

5.6.11 4. Exclusions

Land Purchase Values and Pipeline ROW

Major Site Preparation works such as large scale cut & fill, land reclamation etc.

Operating & Capital Spares

Import Duties and Local Taxes.

License Fees.

Finance Charges.

Forward Escalation

1 VOYEX: Voyage costs are variable costs incurred in undertaking a particular voyage compare to OPEX which is a fixed annual costs. The main

items are fuel costs, port dues, tugs, pilotage and canal charges. This is a common way in shipping of differentiating between the different

vessel related costs


5.7 CAPEX Summary

As can be seen in Figure 17, the CAPEX for the pipeline option is significantly higher than for the

shipping option in all cases. A large proportion of the pipeline CAPEX is associated with the costs of

routing and installation, which is common to all cases irrespective of size.

Figure 17: CAPEX Summary

A breakdown of the CAPEX in Table ‎5-1 shows that the biggest CAPEX contributor for the shipping option

is the onshore facilities, accounting for 90% of total CAPEX in all cases, whereas the vessel only accounts

for about 10% of the total CAPEX. The cost of the vessel in Case 2C is not significantly higher than Case

2B due to the economies of scale for building larger ships as well as operationally managing higher flow

rates by increasing the number of voyages and not by adding more ships.

Table ‎5-1: CAPEX Breakdown

Cost Items Shipping Option (Million GBP)

Pipeline Option (Million GBP)

2 MTPA CO2 Vessel - (1 x 10,000 m3) 23.4 -

Pipeline EPC cost 97.5 444.1

Onshore Facilities Port of Rotterdam EPC cost 69.9 23.8

Onshore UK EPC Cost 48.9 -

Owners Management 12.4 52.5

3rd Party Inspection & Certification 1.2 9.5

CAR Insurance 0.89 9.5

Owners Contingency 20.0 78.1

Total: 274.3 617.5

5 MTPA CO2 Vessel – (2 x 16,000 m3) 49.3 -

Pipeline EPC cost 103.0 616.6


Onshore UK EPC Cost 76.5 -





Total: 381.6 865.9


Cost Items Shipping Option (Million GBP)

Pipeline Option (Million GBP)

7.32 MTPA CO2 Vessel – (2 x 21,000 m3) 54.6 -

Pipeline EPC Cost 105.3 809.3


Onshore UK EPC Cost 107.5





Total: 452.2 1,130.5

5.8 OPEX Summary

Figure 18 show that OPEX for the shipping option is approximately twice the corresponding pipeline

option. The higher OPEX associated with the shipping option is largely due to the operation of land based

facilities at both ends of the transport system.

Figure 18: OPEX Summary

As shown in Table ‎5-2 the total OPEX for the shipping option is dominated by costs associated with the

land based facilities, which accounts for 65 – 75% of the total OPEX. It should be noted that the second

element, VOYEX includes port fees (about 5-10% of total OPEX), which carries a certain degree of

uncertainty because it can be negotiated with the port authorities in Rotterdam and the Humber. Cases

2B and 2C can also benefit from the synergy derived from operating two vessels instead of one. For

example, the costs for spare parts, management & administration fee and maintenance. However, in the

overall context, these cost savings are not expected to result in significant reduction of the shipping

option OPEX.

Table ‎5-2: OPEX Breakdown

Cost Element Pipeline Option (Million GBP) Shipping Option (Million GBP)

Case 1A Case 1B Case 1C Case 2A Case 2B Case 2C

Facilities OPEX 7.9 13.3 17.2 9.1 13.6 17.3

Ship OPEX & VOYEX 3.1 6.4 8.8

Total 7.9 13.3 17.2 12.2 20.0 26.1


6 COMPARATIVE COST ANALYSIS

For the purpose of performing the comparative cost analysis, the project CAPEX has been assumed to be

a one off cost item in 2015 (year 0). OPEX is assumed to be constant and a discount rate of return of 12%

has been applied to obtain the present value of OPEX over the lifetime of the asset. Total life cycle cost

estimate was then calculated as the sum of the CAPEX and the discounted OPEX. The analysis was

performed for an operating life of 20 and 40 years.

6.1 20 Years Operating Life

6.1.1 Life Cycle Cost Estimate Analysis

Based on a 20 year operating life, the discounted (Present Value) life cycle cost estimate has been

calculated and presented in Figure 19. The results show that from a cost perspective, transporting CO2

by ship is by far the more attractive option. The capital outlay for the pipeline options significantly

outweighs its lower OPEX, even at high flow rates.

Figure 19: Life Cycle Cost Estimate (20 Year Operating Life)

6.1.2 Cost/Tonne CO2 Transported

The cost/tonne of CO2 transported is presented in Figure 20. The cost ratio for both options is unchanged

with increasing flow rates

Figure 20: Cost/Tonne CO2 Transported (20 Year Operating Life)


6.2 40 Years Operating Life

6.2.1 Life Cycle Cost Estimate Analysis

Based on a 40 year operating life, the discounted (Present Value) life cycle cost estimate has been

calculated and presented in Figure 21. The results show that from a cost perspective, transporting CO2

by ship is by far the more attractive option. Increasing the operating life to 40 years only resulted in a

marginal improvement in the pipeline option

The capital outlay for the pipeline options significantly outweighs its lower OPEX, even at high flow rates.

Figure 21: Life Cycle Cost Estimate (40 Year Operating Life)

6.2.2 Cost/Tonne CO2 Transported

The cost/tonne of CO2 transported is presented in Figure 22. The cost ratio for both options is unchanged

with increasing flow rates

Figure 22: Cost/Tonne CO2 Transported (40 Year Operating Life)

6.2.3 Distance vs. CAPEX Analysis

To gain an understanding of how the options compare with transportation distance, a high level analysis

of CAPEX and distance has been carried out. For simplicity, it was assumed that pipeline CAPEX has a

simple linear relationship with transportation distance, and the ship CAPEX effectively remain unchanged

for all distances. Figure 23 shows the distances at which ship transportation becomes more attractive

(based on CAPEX only). The figure shows a turning point of about 250km for 2.5 MTPA and 5 MTPA and


200km for 7.32 MTPA. These numbers are in agreement with the result of similar studies that DNV GL is

aware of and could be used for high level screening of CO2 transportation options.

Figure 23: CAPEX vs. Distance Curve


7 COMPARISON OF SHIPPING AND PIPELINE OPTIONS

The pipeline and shipping options have been compared along the broad themes of Cost, Project Risk,

Enablers, Operability, and Regulation

Theme Shipping Pipeline

Project Cost Low capital outlay compared to

pipeline transportation

Overall life cycle cost estimate is

significantly less than the

pipeline option for all flow rates

CO2 emission from ship voyages

could potentially increase its

OPEX when accounted for

High capital outlay compared

to ship transportation

No significant difference in

OPEX compared to the

shipping option, consequently

the overall life cycle cost

estimate is higher

Project Risks Likely to be first of its kind in

terms of the scale of operations

High risk and negative public

perception of the storage of

large volumes of CO2 on land

Contracting and alignments of

multiple stakeholders, especially

if shipping operation in

subcontracted

Likely to be first of a kind in

terms of the scale of

operations

Obtaining permits could take a

long time

CCS projects likely to receive

support from government

Difficult to find alternative use

of the pipeline should CCS fail

to achieve the projected scale

of commercial implementation

and economics

Enablers Transferrable technology and

experience from the ship

transportation of LPG

Permit requirements likely to be

less onerous

CCS projects likely to receive

support from government

Shortfall in CO2 capture

projections can be managed by

reducing the number of ship

voyages

Re-use of ships for the

transportation of LPG or similar

should CCS fail to achieve the

projected scale of commercial

implementation and economics

Transferrable technology and

experience from the

installation and operation of

offshore HC pipelines

No known risks with respect to

the installation of subsea

pipelines

Public exposure is limited both

during construction and

operation


Implementation and

Operability

Construction of large tanks for

onshore storage may be

challenging

Complex logistics involved in

planning, loading and unloading

Training of manpower with CO2

handling skills

Operations is scalable, i.e.

additional ships, storage tanks,

or land equipment can be added

as flow rate increases

It is currently assumed that CO2

will be liquefied by the

emitter/third party, ready for

transportation. Should NGC be

required to liquefy before

transportation, the project

CAPEX could significantly

increase

Lack of shipping experience

within NGC but there is an option

to subcontract the whole

shipping operation

Large pumps required – may

require qualification

Not scalable i.e. fixed pipeline

size has to be installed

Regulation Regulation for the transportation

of LPG are applicable to liquid

CO2 carriers

No pipeline safety regulation

specific to CO2 transportation

in the UK

Applicable European

legislation not fully developed,

especially for subsea pipelines

Relevant standards for

pipelines in general are

available but do not

necessarily address specific

issues on CO2 transportation

for all phases (gaseous,

supercritical, and liquid)


8 CONCLUSIONS & SUGGESTED WAY FORWARD

The following conclusions can be drawn from the study:

8. CO2 transportation using ships is still in the early stage of deployment. The cargo capacities of

ships in operation are below those required for the volumes in this study. However, there are

large LPG carriers in operation which are similar in design to CO2 ships. Therefore, there is no

constraint with respect to the availability of suitable ships as existing LPG ships can either be

converted or new ones built for this application.

9. The transportation of liquid gases, including liquid CO2 using ships is well established and duly

regulated, whereas specific regulations and standards applicable to pipeline transportation of CO2

are yet to be fully developed.

10. Although neither the shipping option nor the pipeline option has been implemented at the scale

being proposed for this NGC application, the study has not identified any technical challenge that

could make their implementation impracticable. Therefore, it can be broadly stated that there is

no practical limit to the amount of CO2 that could be transported using either the shipping or the

pipeline option.

11. The cost estimation results, presented in the table below in cost/tonnes CO2 transported, shows

that, in all cases, ship transportation is by far the more attractive option.

Flow Rate

Cost/tonne CO2 Transported

20 Year Operating Life 40 Year Operating Life

Shipping

Option (GPB)

Pipeline

Option (GPB)

Shipping

Option (GPB)

Pipeline

Option (GPB)

2 MTPA 9.13 16.73 4.68 8.43

5 MTPA 5.31 9.52 2.73 4.81

7.32 MTPA 4.42 8.47 2.28 4.27

12. The capital outlay associated with the pipeline option is largely responsible for this high cost of

transportation. The distance between Rotterdam and the injection platform, as well as the high

transportation pressure required means the pipeline option is unlikely to be competitive even at

very high flow rates.

13. Due to the uncertainties around the projected volumes of CO2 at Rotterdam, the ability to scale

up transportation capacity with increasing CO2 volumes, and the possibility of using the vessels

for dual service (CO2 and LPG) is considered to be a very strong enabler for the shipping option.

14. Given the attractiveness of the shipping option, it is recommended that further studies be carried

out to investigate alternative system arrangements that could improve on some of the

weaknesses highlighted in this report. The following studies are suggested:

a. Investigate the technical, logistical, and financial viability of replacing the onshore

process and intermediate storage facilities with floating storage and regasification units


in Rotterdam and UK. Using a Floating Storage (FSO) in Rotterdam and a Floating

Storage Regasification Unit (FSRU) in the UK could provide a more financially attractive

alternative due to its likely lower CAPEX and OPEX. The FSRU technology is matured and

all the required rules and regulations are in place to support their successful operation.

b. Investigate the technical and economic feasibility of direct transfer of CO2 from ship to

the injection platform. Although this arrangement will require a more specialised vessel

with a higher CAPEX compared to the one considered in this study, the overall lifecycle

cost could potentially be lower due to the elimination of land based infrastructure,

including the inter-connecting pipeline.

c. Should NGC wish to pursue further the land based loading and unloading arrangement

considered in this study, it is recommended that a more detailed analysis of the onshore

facilities be carried out to improve the accuracy of the cost estimates.


9 REFERENCES

[1] Rotterdam Climate Initiative. CO2 Capture, Transport and Storage in Rotterdam, Report

2009. Schiedam : DCMR Environmental Protection Agency, 2009

[2] decarboni.se. CO2 Terminal at the Port of Rotterdam. decarboni.se, Solutions to Climate

Change. [Online] [Cited: 11 05 2015.] http://decarboni.se/publications/co2-liquid-logistics-

shipping-concept-llsc-safety-health-and-environment-she-report/81.

[3] CO2 Europipe Consortium. Development of large scale CCS in The North Sea via Rotterdam

as CO2-hub. s.l. : CO2 Europipe, 2011.

[4] Royal Netherlands Meterological Institute. Kilmaattabel Rotterdam, langjarige

gemiddelden, tijdvak 1981-2010. 2013.

[5] Met Office. Climate Normals 1981-2010. 2012.

[6] Norwegian Coastal Administration. About the North Sea: Key Facts. 2008.

[7] Accurate thermodynamic-property models for CO2 rich mixtures. Span, Roland, Gernert,

[8] The GERG-2008 Wide-Range Equation of State for Natural Gases and Other Mixtures: An

Expansion of GERG-2004. Kunz, O and Wagner, W. 2012, Journal of Chemical Engineering

Data, Vol. 57, pp. 3032-3091.

[9] NGC/MP/HS/08, ‘National Grid Carbon Management Procedure for Site Location and Layout

Studies for Carbon Dioxide transportation Systems’, National Grid carbon 2014

[10] GL Report 10771, ‘Site Layout Tool for Carbon Dioxide’, September 2011, K. Brazenaite and

A. Halford, GL Report Issue 1.1

[11] CRS Report for Congress. Carbon Dioxide (CO2) Pipelines for Carbon Sequestration:

Emerging Policy Issues, January 2008..

[12] Drewry Maritime Research, Ship Operating Costs, Annual Review and Forecast, Annual

report 2014/2015

[13] M.Bario et al, Ship-based transport of CO2

[14] Dr. Peter Brownsort, SCCS, Ship transport of CO2 for enhanced oil recovery – literature

survey, 2015


APPENDIX A - DETAILED COST AND ANALYSIS

CAPEX

Case 1A – Pipeline option and 2 MTPA CO2

Onshore Facilities Port of Rotterdam EPC cost 23,807,776 GBP

Pipeline EPC Cost 441,238,064 GBP

Offshore Facilities EPC Cost 2,900,000 GBP

Owners Management 52,547,270 GBP

3rd Party Inspection & Certification 9,459,985 GBP

CAR Insurance 9,507,249 GBP

Owners Contingency 78,073,967 GBP

Total: 617,534,311 GBP

Case 1B – Pipeline option and 5 MTPA CO2








Total: 865,932,416 GBP

Case 1C – Pipeline option and 7.32 MTPA CO2








Total: 1,130,502,292 GBP

0

200

400

600

800

1000

1200

Case 1A Case 1B Case 1C

CA

PEX

(M

illio

n G

BP

)

Owners Contingency

CAR Insurance

3rd Party Inspection &CertificationOwners Management

Offshore Facilities EPCCostPipeline EPC Cost

Onshore Facilities Port ofRotterdam EPC cost


Case 2A – Shipping option and 2 MTPA CO2

Vessel - (1 x 10,000 m3) 23,440,300 GBP

Onshore pipeline connection 97,427,539 GBP


Onshore UK EPC Cost 48,947,456 GBP



CAR Insurance 891,464 GBP


Total: 274,269,043 GBP

Case 2B – Shipping option and 5 MTPA CO2

Vessel – (2 x 16,000 m3) 49,320,960 GBP








Total: 381,631,838 GBP

Case 2C – Shipping option and 7.32 MTPA CO2

Vessel – (2 x 21,000 m3) 54,587,000 GBP








Total: 452,228,749 GBP

0

100

200

300

400

500


Millio

ns

CAPEX SUMMARY

Owners Contingency

CAR Insurance

3rd Party Inspection &Certification

Owners Management

Onshore UK EPC Cost

Onshore Facilities Port ofRotterdam EPC cost


OPEX


OpEx (for 1 vessel) 1,175,226 GBP

VoyEx - Fuel cost (for 1 vessel) 1,316,995 GBP

VoyEx - Port fees (for 1 vessel) 595,948 GBP

Onshore pipeline connection maintenance 3,015,927 GBP

Maintenance & Operating Costs 2,971,546 GBP

Insurance, Utilities, Catalysts & Chemicals 3,118,526 GBP

Total: 12,194,168 GBP

Case 2B – Shipping option and 5 MTPA CO2

OpEx (for 2 vessels) 2,954,120 GBP

VoyEx - Fuel cost (for 2 vessels) 2,020,929 GBP

VoyEx - Port fees (for 2 vessels) 1,435,988 GBP




Total: 19,992,201 GBP

Case 2C – Shipping option and 7.32 MTPA CO2

OpEx(for 2 vessels) 3,623,292 GBP

VoyEx - Fuel cost (for 2 vessels) 2,409,111 GBP

VoyEx - Port fees (for 2 vessels) 2,730,223 GBP




Total: 26,074,402 GBP

0

5

10

15

20

25

30


Millio

ns

OPEX SUMMARY

Insurance, Utilities, Catalysts &Chemicals

Maintenance & Operating Costs

Onshore pipeline connectionmaintenance

Vessel Voyex - Port fees

Vessel Voyex - Fuel cost

Vessel OpEx


20 Year Operating Life Cost Analysis – Pipeline Option


Total CO2 throughput for 20 years 40,000,000 tons

CAPEX 617,534,311 GBP

Annual OPEX 6,891,872 GBP

PV 669,012,760 GBP

£ / ton of transported CO2 (CAPEX Contribution on total cost) 15.44 £/ton

£ / ton of transported CO2 (OPEX Contribution on total cost) 1.29 £/ton

£ / ton of transported CO2 16.73 £/ton

Case 1B– Pipeline option and 5 MTPA CO2


CAPEX 381,631,838 GBP


PV 530,962,464 GBP




Case 1C– Pipeline option and 7.32 MTPA CO2


CAPEX 452,228,749 GBP


PV 646,990,033 GBP





40 Year Operating Life Cost Analysis – Pipeline Option



CAPEX 274,269,043 GBP


PV 374,795,038 GBP




Case 1B– Pipeline option and 5 MTPA CO2


CAPEX 381,631,838 GBP


PV 546,443,087 GBP




Case 1C– Pipeline option and 7.32 MTPA CO2


CAPEX 452,228,749 GBP


PV 667,180,305 GBP





20 Year Operating Life Cost Analysis – Shipping Option


Total LCO2 throughput for 20 years 40,000,000 tons

Required vessels 1

CAPEX 274,269,043 GBP

Annual OPEX & VOYEX 12,194,168 GBP

PV 365,352,691 GBP

£ / ton of transported LCO2 (CAPEX Contribution on total cost) 6.86 £/ton

£ / ton of transported LCO2 (OPEX & VOYEX Contribution on total cost) 2.28 £/ton

£ / ton of transported LCO2 9.13 £/ton

Case 2B– Shipping option and 5 MTPA CO2


Required vessels 2

CAPEX 381,631,838 GBP


PV 530,962,464 GBP




Case 2C– Shipping option and 7.32 MTPA CO2


Required vessels 2

CAPEX 452,228,749 GBP


PV 646,990,033 GBP





40 Year Operating Life Cost Analysis – Shipping Option



Required vessels 1

CAPEX 274,269,043 GBP


PV 374,795,038 GBP




Case 2B– Shipping option and 5 MTPA CO2


Required vessels 2

CAPEX 381,631,838 GBP


PV 546,443,087 GBP




Case 2C– Shipping option and 7.32 MTPA CO2


Required vessels 2

CAPEX 452,228,749 GBP


PV 667,180,305 GBP





APPENDIX B – ITEMISED COST ESTIMATES

Carbon Capture Storage Upscaling:Capital Cost Estimate - Rev B2.pdf

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