amec project no. 1720 2000 - teesside collective · 2015-07-01 · this project is seeking to...

AMEC Project No. 1720 2000 Client Ref: TVU Industrial CCS

Document No. 2000-0005-DC00-RPT-003 Revision : R1

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Revision Changes Notice

Rev. Location of Changes Brief Description of Change

Changes within the document from the previous issue are indicated by a change triangle

List of HOLDS

HOLD No. Location of HOLD Reason for HOLD

P2



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Table of Contents

Revision Changes Notice .................................................................................................................... 2

List of HOLDS ..................................................................................................................................... 2

Table of Contents ................................................................................................................................ 3

Glossary of Terms ............................................................................................................................... 5

1.0 Executive Summary ................................................................................................................. 6

2.0 Introduction .............................................................................................................................. 6

2.1 Background to the Tees Valley Industrial CCS Project ................................................. 6

3.0 Scope and Format ................................................................................................................... 7

3.1 Work Pack 5 Scope ...................................................................................................... 7

3.2 Work shop purpose ...................................................................................................... 7

4.0 Onshore Infrastructure ............................................................................................................. 8

4.1 Gas vs. Liquid – Pressure vs. Cost .............................................................................. 8

4.2 Operational considerations ........................................................................................... 8

5.0 Operational Limits .................................................................................................................... 8

5.1 Possible Operating Conditions ..................................................................................... 8

5.2 Current Operational Experience ................................................................................. 10

5.3 Effect of contaminants ................................................................................................ 11

5.4 Gas Transmission ...................................................................................................... 12

5.5 Gas Pressure ............................................................................................................. 13

5.6 Liquid Transmission ................................................................................................... 15

5.7 Cost Influences in Operating Phase Selection ............................................................ 19

6.0 Costing of Concept Options ................................................................................................... 22

6.1 Costing tool ................................................................................................................ 22

6.2 Tested Solution .......................................................................................................... 23

6.3 Test Outcome ............................................................................................................ 24

6.4 Conclusions on Network Cost .................................................................................... 24

7.0 Location Factors .................................................................................................................... 25

7.1 Area Assessment ....................................................................................................... 25

7.2 Major Equipment ........................................................................................................ 26

7.3 Plant size ................................................................................................................... 26



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7.4 Test Layout Impacts ................................................................................................... 27

8.0 Comparison and Conclusion .................................................................................................. 29



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Glossary of Terms

Abbreviation Description

TVU Tees Valley Unlimited

FEED Front End Engineering Design

CCS Carbon Capture and Storage

GDP Gross Domestic Product

PTA Purified Terephthalic Acid

SSI Sahaviriya Steel Industries

UK United Kingdom

LEP Local Enterprise Partnership

INCA Industry Nature Conservation Association

HDD Horizontal Directional Drill

EU ETS European Union Emissions Trading Scheme



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1.0 Executive Summary

The purpose of this document is to define the operating system pressure of the onshore network.

Consideration has been given to the following;

Operational conditions and constraints

Technical limitations due to the phase change, etc

Cost impacts

o With initial compression

o With initial compression

o Pipeline only

Location

Layout

Utility provision

In summary the choice is between the operational pressures of 35 or 100 bar due to technical and operational issues around the potential of phase changes in a pipeline. Comparison on a cost basis are neutral for the integrated case, but favour the higher pressure in the transporter and pipeline only cases.

Layout and the need to provide independent utilities with additional cost impacts also favour the higher pressure solution.

Therefore the higher operational pressure of 100 bar has been selected for further study.

2.0 Introduction

2.1 Background to the Tees Valley Industrial CCS Project

The Teesside Process Industry Cluster is one of the largest in the UK covering a diverse sector base of chemicals, petrochemicals, steel and energy companies. The cluster employs c. 20,000 people, has a GDP of c.£10bn and exports of c. £4bn per annum. The nature of these industries also makes Teesside one of the most carbon intensive locations in the country. The sector has taken huge strides in improving energy efficiencies in recent years; however emissions of carbon dioxide are an inherent part of many of the processes and a real step change in emissions can only be made by implementing carbon capture and storage.



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The Tees Valley’s economic vision is to build on the strengths of the existing cluster and establish Teesside as an integrated carbon-efficient industrial hub, achieving economic stability and growth through the production of low carbon energy and products.

Through the City Deal Tees Valley Unlimited (TVU) the Local Enterprise Partnership (LEP) has commissioned two projects, one examining the business case and this project providing pre-FEED concept selection and engineering.

This project is seeking to address pre-FEED design options for four industrial sites, onshore and offshore networks and cost estimates to support a business case model.

3.0 Scope and Format

3.1 Work Pack 5 Scope

The onshore transportation scope of work involves defining a route for an onshore pipeline or pipelines linking the four CO2 emission sites (Lotte, Growhow, BOC and SSI) together, and undertaking a preliminary design on the pipeline

The total CO2 emissions to be captured from the four sites are uncertain, but are likely in the range 3.5 – 4.5 million tonnes per annum, calculated as follows

~2.7 million tonnes from the SSI site if 90% of the power generation emissions are captured. This could increase by up to a further 1 million tonnes if other sources on the site were to be captured.

~600,000 tonnes from the Growhow site (100% capture assumed as all the CO2 is already captured and emitted)

~225,000 tonnes from the BOC site (assuming 90% capture rate)

50,000 tonnes from the LOTTE site (assuming 90% capture rate)

Two scenarios are to be assessed:

Pipeline sized to just take the proposed volumes from the 4 sites (preliminary estimates suggest this will be 12 -16 inches diameter)

Pipeline deliberately oversized to collect ~15 million tonnes of CO2 in the Teesside area (preliminary estimates suggest this will be 28-32 inch diameter)

3.2 Work shop purpose

The work shop format is focused on raising constraints and drivers for potential pipeline routes on Teesside. It does not down select routes, providing only criteria and data for route selection and screening of options in other elements of Work Pack 5. There are some technical issues for discussion and constraints/drivers that will help to inform route selections.



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The intent of the workshop is discuss issues that require resolution prior to routing and derive constraints and drivers that affect route selection.

4.0 Onshore Infrastructure

4.1 Gas vs. Liquid – Pressure vs. Cost

One of the issues raised by the initial workshop on onshore infrastructure was the operational pressure of the infrastructure.

The fluid phase is a critical determining factor. For gas pipelines the pipeline risk profile maybe lower, but the pipe diameter larger for the same mass flow. Gas systems will need to operate a relatively low pressure to ensure that phase transitions do not occur due to changes in temperature, typically gas pressure would be limited to under 40 barg in UK conditions. Gas pipelines however require compression prior to the trunk pipeline to storage, this adds additional facilities and cost to any infrastructure.

Liquid pipelines are smaller in diameter to transport the same mass flow. They are however a different risk category and marginally more difficult to route. Typically higher costs of pipeline are outweighed by the provision of smaller diameter pipelines and savings for the infrastructure provider in onward compression or pumping costs.

4.2 Operational considerations

There are other operational considerations that impact on the phase design of a network,

Operational limits

Required end of network conditions

Compressor/pump siting philosophy

Availability of re-used infrastructure

Entry specification

These need to be considered alongside the pipeline size and hence, cost choices.

5.0 Operational Limits

5.1 Possible Operating Conditions

5.1.1 Safety margins around the saturation line

The presence of two phase flow in a pipeline is not a desirable condition. Operation in this regime means that vapour/liquid interactions occur including phase changes, mass transfer of



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contaminants and flow regime issues that may lead to slug flow, bisected flow or introduce surge/slug behaviour. Therefore avoidance of the two phase region of a fluid being transported is preferred.

For Carbon Dioxide the saturation line is effectively within the ambient (temperature/pressure) and operating conditions expected for CO2 transport by pipeline. Therefore to avoid the transition occurring in a pipeline a coarse safety margin is applied, setting upper or lower bound limits of pressure and temperature within a pipeline.

5.1.2 Design pressure

The design pressure typically recommended is expressed as a design margin added to the Maximum Operating Pressure (MOP). For example typical margins applied in design are MOP+10% for the range 10-70 bar, and +7 bar for MOP at 70-140 bar. The design pressure should not be set at the saturation pressure for a vapour as small increments in temperature could cause phase transition to occur, for example at 3°C ambient conditions a move to -1°C results in transition from vapour to liquid. Whilst moving, gas temperatures are unlikely to equalise to such levels, it may only occur in stagnant conditions, but should be considered. Therefore a ±10% safety margin is applied to the saturation line.

Whilst in theory setting the design pressure at the saturation pressure (Psat) for a given temperature may be acceptable it is not preferable. Therefore a margin of 1.5 to 2 bar is also recommended. At typical UK ground conditions this would result in a MOP of 32.4 barg, equivalent to 0.9Psat – 1.5 bar and a Maximum Allowable Working Pressure (MAWP or Design Pressure) of 35.5 barg. The MAWP is allowed to approach encroach on the 0.9Psat margin as it represents an excursion pressure, not an operating limit.



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Figure 1 Phase Transition Margins – Pure Carbon Dioxide

5.2 Current Operational Experience

The current operational experience for CO2 pipelines is predominantly in the US, with pipelines also in service in Canada, Algeria, Turkey and Norway. Current distance deployed is 6000km, over 5000km of which is in North America.

The fluid is used exclusively in North America for Enhanced Oil Recovery, as a reservoir fluid that is able to improve recovery of otherwise immobile deposits. As such the operating envelope and compositional requirements vary, however EOR takes place in the liquid or supercritical (dense phase) region.

Typical operational limits are;

Temperature

o Minimum: 4°C

o Maximum: 38°C

Pressure

o Minimum: 8619 kPa



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o Maximum: 17250 kPa

Figure 2 Carbon Dioxide Phase Diagram – Typical EOR Operating Regime

5.3 Effect of contaminants

The effects of contaminant or other constituent parts of a CCS related CO2 stream are discussed in a separate report, 2000-000-DC00-RPT-003 Entry Specification.

Overall the evidence based on current property methods indicates that at high contamination levels, 5%, the critical point tends to be driven up and the phase envelope changes in favour of higher pressures, Figure 3. The critical point shifts in most cases to around 80bar and 20°C. This is a coarse measure using only binary mixtures, but gives a clear indication that a 95% CO2 mixture will tend towards this point. Therefore applying a 10% margin to establish a minimum pressure to this point gives a recommend lower allowable working pressure (LAWP) of 88 bar. Typically in previous studies this has been rounded to 90 bar. For gas systems the pure CO2 stream properties are considered, although mixtures may provide a wider a margin it is prudent to maintain the design pressure as discussed in Section 5.1.2.



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Figure 3 - Indication of the effect of contaminants

5.4 Gas Transmission

5.4.1 Introduction

Transmission of CO2 as a gas is not generally considered for storage or EOR, as the density, viscosity and solvent effects required for a fluid in EOR or one entering a store are typically higher than that of the gas phase. Proposals for the gas phase transmission have been considered before in the FEED project at Longannet in 2010. However the driver here was the availability of existing infrastructure available to the project for re-use. That asset was a natural gas pipeline that was considered redundant or under-utilised part of the National Transmission System (NTS) owned and operated by National Grid.

Transport in gas phase can occur but is limited by design pressure issues, phase transition and the capacity to put a mass of gas down a pipeline. The potential volume down a pipeline is lower for gas phase. The Major Accident Hazard Potential (MAHP) is lower than for liquid pipelines for gas pipelines.

5.4.2 Gas flow

Gas transmission is possible, however the pressure envelope is key and transition to liquid is not allowed. As heat transfer from a pipeline is complicated by flow rate, topography and soil types, generic prediction is conservative. However the loss of temperature is generally slow so modelling of a pipeline needs to consider a set of issues to determine the operating band for gas in that line. For buried lines the temperature loss may not allow the line to cool sufficiently



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with pressure drop to avoid the saturation line. Other factors that affect the heat transfer are the flow rate, pressure and flow regime.

Figure 4, shows some examples for the profile issues for gas phase. It considers a single 350km pipeline without re-compression. Entry temperature is 25°C, pipeline diameter is 36” (889mm ID) and ambient conditions are 3°C minimum or 10°C nominal, the ambient temperature profile in the pipeline is linear. No topography changes are allowed, so the pipeline model is fairly simple.

The illustration shows the profile of a fluid injected as gas at 56 bar, the profile for high flow 1080 tonnes/hr shows a transition to liquid, cooling to 3°C in the pipeline is reached at about 50km, halving the flow actually flattens the pressure profile and shortens the gas phase distance of the pipeline. Lowering the pressure inevitably reduces the mass that can be transported due to pressure drop issues. The next three profiles illustrate this and the effect of ground temperature changes. The first two cases show the differences caused by ground ambient temperature changes. Here the lower the ambient conditions the closer to the saturation curve, the more extended the profile. Reinforcing the view that the minimum ground temperature is critical. The final curves illustrate profiles based on MOP (the MOP is defined by the pressure at the pipeline entry point) at saturation pressure (Psat) and 0.9Psat.

The design point for gas pipelines, particularly those for re-use is therefore based on the consideration of the lower ambient conditions. The design pressure needs to be considered with care as the profile is dependent on distance for pressure and temperature losses. It should be defined by modelling the pipeline at a number of conditions, but including topography. However the recommended start point is that the design pressure should not initially exceed Psat at the minimum ground temperature. More typical would be to set the design pressure as described in Section 5.1.2.

5.5 Gas Pressure

Gas transmission pressure is possible and the exact limits are dependent on the pipeline size and network design. Typically for modelling of gas systems at a concept level 35 bara is used. This pressure allows a wide margin away from the phase envelope even at low ambient conditions, where high ambient cooling may occur. The ground temperature range in the UK is commonly 10-3°C, and at 3°C, 35 bara is Psat. A cooling excursion due to severe weather down to -1°C which would require a significant period of very low ambient conditions would only result in the saturation pressure being reached, not exceeded.

A network pressure could be lower, however the optimum point for dehydration is between 30-40 bara. This also needs to be considered.

Pressure drop in a pipeline is not a significant factor here so the typical gas pressure for network entry as a gas is 35 bar.



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Figure 4 - Gas Operations Example Profile Limitations



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Figure 5 - Ambient conditions influence on gas network pressure selection

5.6 Liquid Transmission

5.6.1 Introduction

The common method of transport of CO2 in pipelines is as a dense phase or supercritical fluid. This form of operations above the saturation line provides higher density fluids and is therefore preferred for EOR. At high pressures the density remain high and the surface tension and viscosity lessen, it is these parameters that make Carbon Dioxide a valuable commodity for EOR.

For CCS projects with or without EOR the high pressure characteristics enable dissolution in saline aquifers, or injection into reservoirs (including blowdown if necessary) but also excellent transport properties. At high pressures low viscosity at high densities, result in low pressure drops, enabling long distance pipelines with minimal compression/pumping. For example a 36” pipeline can typically carry 5000t/h (44 million tonnes per annum) upto 400km before re-pressuring may be needed. This would enable UK based pipelines to access most of the central North Sea without offshore pressure boosting.



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5.6.2 Definition of Terms

In considering liquid phase there are a number of terms that require definition.

Supercritical – Above critical temperature and critical pressure

Dense Phase – typically the region above critical pressure, but below critical temperature

The two terms can often be misleading and become interchangeable, which should be avoided.

Figure 6 - Phase Diagram Definitions

5.6.3 Operating Conditions

The issue for liquid phase pipelines is that there has to be a lowest pressure, a lower allowable working pressure (LAWP) as opposed to the normal Maximum Allowable Working Pressure (MAWP). Like a gas pipeline, a liquid pipeline approaching the saturation curve can cause problems of phase transition and over pressurisation if heat is applied.

Current EOR operations in North America typically operate around 4-38°C and 86 to 172 bar, Figure 2. The required pressure for EOR at the well head is often different than the transportation pressures and is generally pressurised at the well head as required by the reservoir profile and required production rate.



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For any pipeline the temperature of the fluid will move towards equilibrium with the ambient conditions, therefore they are subject to ground temperature if buried, air temperature if exposed and sea floor temperature if offshore. As the fluid transits the pipeline the pressure also drops and fluids that were dense phase or supercritical on entry to the pipeline move to true “liquid” phase. In terms of pipelines this is acceptable. The example in Figure 7, shows the profile down a simple 36”, 500km long pipeline transporting 4000t/h (35 million tonnes/year) a typical offshore pipeline for a network system. The entry conditions are 150 bar and 25°C, assuming post compression cooling to 25°C (or temperature rise due to pumping). The delivery point conditions are 65 bar and 16°C in the liquid phase.

Figure 7 - Liquid Pipeline Example Operating Profile

The issue is then two fold. Is the delivery pressure high enough and how is it handled on an offshore facility. If the pipeline becomes exposed to warmer water at shallower depths or rises onto a platform then the lower pressure can cause problems as temperatures increase. If the temperature does increase then there could be a phase transition. In the example given at 65 bar and 16°C a temperature increase of 10°C, from heating from ambient or process conditions would transition to gas phase, hence increasing the pressure. These issues can be managed but careful consideration needs to be given during design.

For the purposes of guidance the saturation pressure at the ambient temperature can be used. Typically the North Sea air temperature range is broad, warmer in the south than the north. Northern North Sea can be expected to be as high as 20°C1, whilst southern platforms may

1 http://www.tititudorancea.com/z/weather_sleipner_a_norway.htm#sci_graphs



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see 25°C2. For these ambient temperatures the saturation pressures are 57 and 65 bar respectively. Appling the guidance on design pressures discussed for gas, an added 10%, drives the desired pressures to 63 and 72 bar. The same conditions apply onshore, but the higher ambient conditions will exacerbate the effect.

Whilst careful operation and design can mitigate these issues a minimum operational pressure needs to be considered. It is recommended however that caution is exhibited operating below 80 bar, (critical pressure + 10%), Figure 8. Therefore the lower design pressure in CO2 pipelines is 10% above saturation pressure at maximum ambient conditions. This typically removes the phase change issues in high ambient conditions.

However this indicated value can be lower than discussed in Section 4.1.2, so the pressure floor for pipelines is taken from section 4.3 and set at 90 bar. Below 90 bar caution is advised.

Figure 8 - Pipeline Lower Design Pressure

In terms of designing onshore infrastructure at a concept level the floor of 90 bar is adopted to prevent unintentional exposure to risks of operating around the saturation line. The inlet pressure is more debatable as US experience sees pressures up to 176 bar onshore. The acceptance of dense phase pipelines in the UK is broadly acceptable in the current regulations, although the competent authority the HSE expects an “as low as reasonably practical” approach to risk and hazard potential.

2 http://www.wunderground.com/weatherstation/WXDailyHistory.asp?ID=M62145&day=31&year=2011&month=8&graphspan=year



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On Teesside the network is geographically small and pipeline lengths short even compared to some single emitter schemes such as the Capture Power Ltd, White Rose CCS project. Maintaining the floor pressure is important and practically the balance between pressure drop and power needs to be balanced. The network typically could exist as a 95 bar pressure system the distances being so short. Changing the pressure to reduce pipeline size at such flow rates is necessarily significant in small networks.

Here comparing a range from 95 bar to 300 bar the step change in cost savings is around the 100 – 110 bar range, Figure 9. As the pressure increases pipeline costs may fall, but compression costs also rise, from 100 bar to 300 bar typically by a factor of 2.6. The need to balance pipeline cost savings versus compressor savings in a small network is immaterial, moving from 100 bar to 110 bar adds 7% to compression costs, but the pipeline saving is equivalent to 5%. It is more cost effective to have a larger pipeline than more powerful compression.

Figure 9 - Network pipeline cost vs. Pressure

Considering the lack of savings in the pipeline system from increased pressure the recommended dense phase system pressure is therefore minimised in line with the recommendation of the HSE for ALARP risk. Reduction to 95 bar may be possible however and operational margin and some line pack capacity is provided by 100 bar. A pipeline cost saving of 14% is still outweighed by the total system increase in compression, but is beneficial in terms of the transporter option where initial compression is excluded. Therefore a dense phase system pressure of 100 bar is selected.

5.7 Cost Influences in Operating Phase Selection

The primary differentiator in selection of gas or dense phase transportation is cost. The cost is defined by the cost of the pipeline and also that of the prime mover (compressor or pump) options associated with such a network.



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Dense phase systems reduce the networks physical size in terms of pipeline diameters by carrying higher density fluids leading to a lower diameter/tonne ratio. Generally dense phase pipeline are thicker walled due to the higher pressure than gas lines. Typically smaller pipelines in dense phase also weigh more than their equivalent gas pipeline given the difference in wall thickness. The raw line pipe material is only one factor in the costing of a pipeline and feeds into a cost equation, but the decision between dense phase and gas does have a tipping point where gas is more economical compared to dense phase. Remove the cost of the pipeline completely such as in re-use scenarios and the economics of gas improve greatly.

The pipeline cost is only one element. The cost of the prime mover is also considered. For gas networks the provision requires an initial compressor and subsequently at the end of the network another compressor to push the fluid to dense phase for onward transmittal, Figure 10. For dense phase there are two options, initial compression to the desired onward pressure delivery or an intermediate pressure.

Emitters

Gas Phase <36 bar

Compressor

Compressor

Store

Emitter Site – “Capture Facility”

Dense Phase >90 bar

Figure 10 - Typical Gas Transmission Arrangements

The intermediate pressure is more common onshore where there are concerns about the routing of pipelines and higher major accident hazard potential. Here initial compression is to the dense phase region and a pump, Figure 11, not a compressor, provides onward pressure boosting.

Emitters

Pump

Compressor

Store

Emitter Site – “Capture Facility”

Dense Phase >90 bar

Figure 11 - Typical Dense Phase Transmission Arrangements



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In both cases two prime mover sites are required, one at the host emitter site adjacent to the capture plant and one slightly more remote. In both cases there are a number factors influencing cost of such installations, Figure 12. These typically include the provision of utilities contained within the site solely for compression or those that can be provided by the host site, such as water, air and drainage, processes on the site (such as cooling on compressor sites), footprint and normal land use issues.

PRIME MOVER

UTILITY PROVISION (ISBL)

WATER

PLANT AIR

FOUL SERVICES

LUBE OIL

(COMPRESSOR ONLY)

COOLING WATER

EXTRACTION /

RETURN

SITE CIRCUIT

UTILITY PROVISION (OSBL)

POWER

GAS

PLANNING

ENVIRONMENTAL

LOCATION CONSTRAINTS

ACCESS

FOOTPRINT

Figure 12 - Major Influences on Prime Mover Costs

Facilities that are hosted by a parent facility, such as a capture plant, also see a cost benefit. Whilst provision of extension or tie-in to existing utilities and services will have a cost implication to a project it is typically lower than providing a new facility. The obvious saving can be in land and access costs, but utility connections and supply are typically marginal increases unless reinforcement of the existing is needed. Even then saving can occur in reduction of control architecture, manning, land costs and planning costs.

The cost differential of “hosted plants” can be seen in the following graph, Figure 13. Here two cost lines are considered for CCS compression, one hosted at a facility, one not and the cost are expressed in simple terms, compared to power, MW, required for the specified flow rate. The two Longannet compressors (Blackhills and ACC) are equal power compressors, the cost of the hosted “ACC” plant, significantly less than the remote Blackhills, the differential is almost 50%. This may not be unrealistic, but highly dependent on location, but a discount can be applied possibly 80%, given a possible reduced land use or purchase and tie-in to a minimum number of existing systems.



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Figure 13 - Cost comparison MW Compressor vs Cost (£)3

6.0 Costing of Concept Options

6.1 Costing tool

The concept options are tested and priced using a modified version of the IEA GHG R&D programme tool produced in “Upgraded Calculator for CO2 Pipeline Systems”4. The spreadsheet calculates the line sizes of a network and provide compressor power estimates, applying cost metrics to both. Calibration of the software and metrics used has required correction given emerging experience and methods. The model produces an estimate for both pipelines and compression, for comparison sake the options typically are considered as a deviation from an average. For example the average cost of all options is taken as 1, a network option with a 20% higher CAPEX, reports as 1.2. This comparison method is simple and only valid if the network is considering the phase differences, the number of emitters and network shape must be the same.

6.2 OPEX as a neutral factor

Consideration can be given to OPEX in looking at solutions. However unless it is for detailed models it is typically a percentage take on CAPEX for Fixed OPEX and a broad interpretation

3 “0225-003 Calculating the Cost of Transporting CO2” AMEC, Internal Guidance Document, 2013 4 “Upgraded Calculator for CO2 Pipeline Systems”, report Number 2009-3, March 2009, IEA GHG R&D programme



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of variable OPEX based on energy costs. Typically the differential between options on OPEX would be the energy required to overcome the pressure drop in the system. The amount of energy put in to pressurising the gas and fluid is equal in each option, the differences arise due to the separation of the stages. For such a geographically close network the pressure losses are negligible in both cases so the energy differential between gas and liquid is marginal. A difference does exist of course but screening would require a more detailed economic analysis over a period of time to account for the potential savings made over a liquid or gas system in OPEX and CAPEX. In general terms what you may save in terms of a gas system, with a marginally lower pressure drop, over a liquid network is lost by the cost of compression at the beach or trunk line compressor station. Hence OPEX here and at such a high level is considered a neutral factor.

6.3 Tested Solution

The tested network consider 3.5 to 4.5 million tonnes per year and a route designated “Blue” route, Figure 14. The route takes a path including Tunnel 2 under the Tees. The emission volumes are varied at this stage to provide a cross section of costs.

1

1

2

3

45

6 7

8

9

10 1112

13

14 15

16

17

18

1920

2122 23

24 2533

343

5

36

37

38

4140

39

26

27

28

29

30

31

32

2

4

3

STN

1. Growhow

2. BOC

3. Lotte

4. SSI

Figure 14 - "Blue" Route Concept

The tested solution considers transport as a whole. Typically a network provider considers the “transport” solution to start at the fence line of the capture plant, post initial compression. In this test we consider both, including and excluding the initial compression.



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6.4 Test Outcome

The cost test of the network illustrates issues associated with geographically small networks. Here the network is geographically close and small so the pipeline costs are dominated by the cost of compression. On a larger network this is less so and the influence is more balanced. In terms of pipeline costs the network selection makes a small difference but is clearly lower cost at the higher pressure, Table 3.

Considering the overall transport costs, Table 1, including initial compression the costs are close regardless of the network selection. Differentiation between the options is difficult as the least cost solution changes as the tonnage increases. In general below 4 million tonnes the costs favour dense phase, unless a host plant discount is applied, and this variable is not easily defined.

Considering the normal appraisal of the transport costs, excluding initial compression, Table 2, the case is much clearer, dense phase is significant lower cost than a gas system, typically by a factor of two.

6.5 Conclusions on Network Cost

Therefore there are two issues to consider for phase selection from an economics point of view. The first is that the overall cost of transport, including initial compression is close, within the margin of error of the correlation used to cost both pipeline and compressor. The bulk of the cost lies in the initial compression and there are unknown variables around integration and cost impacts of the host plant. For that reason the overall solution effectively has been considered, but no selection on that basis alone can be taken.

The second consideration is that of the more typical transport solution. A transport provider may or may not want to control the initial boosting, this can be termed as the “transporter solution”. So far cluster studies have generally assumed initial compression is out of the transporters scope. If this is assumed here then the lower cost of the dense phase network is obvious and significantly outside the margin of error (+/-30%) of the initial screening correlations.

Transported, million tonnes/year

Cost Index

(CAPEX compared to Average CAPEX)

100 bar 100 bar (80% discount for hosted facility)

35 bar 35 bar (80% discount for hosted facility)

4.5 1.24 1.2 1.03 1.06

4 0.98 0.94 0.96 0.99

3.5 0.88 0.85 0.9 0.93

Table 1 - Overall Transportation Cost



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Cost Index


100 bar 35 bar

4.5 0.7 1.47

4 0.64 1.36

3.5 0.59 1.26

Table 2 - Transportation Costs, excluding initial compression


Cost Index – Pipeline Only


100 bar 35 bar

4.5 0.93 1.08

4 0.92 1.08

3.5 0.92 1.07

Table 3 - Overall Pipeline Costs

7.0 Location Factors

7.1 Area Assessment

The placement of the shoreline prime mover, pump or compressor, is generally driven by the desire to be as close to the shoreline as practicable. Balanced with the needs of the plant, land availability, access and the availability of a suitable plot. A full area assessment has not been made for this study. However past work as part of the Eston Grange and Teesside Low Carbon projects has highlighted the same area for their shore line pressure raising and landfall.

A simple review of available areas, Figure 15, highlights a number of issues with sites being too small, access restricted, in use or with a planned future use. This leaves the site highlighted by previous projects as the most likely candidate site. This is however also a green field development with no immediately available supporting utilities. The area to the north, adjacent to a golf course is effectively sterilised due to the access point for the CATS pipelines straddling the area, this area can however be utilised for the pipeline run to the water line.



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Figure 15 - Potential Shoreline Prime Mover Positions

7.2 Major Equipment

The basic equipment required in each option is summarised in Table 4. There are options to consider and the drive type for the prime mover impacts on footprint and utility provision.

7.3 Plant size

The scale of a compressor or pump facility is different, the latter footprint and utility requirements significantly smaller. Pump stations are typically less expensive than the equivalent flow and power provided by a compressor station. In part the physical sizes of the core equipment is smaller, but additional coolers and a cooling circuit is not required for pumps, nor are recycle lines and coolers that enable compressor turndowns. The Blackhills compressor, part of the Longannet project has an installation size of 3 million tonnes/year or in area terms 400m x 300m. The proposed Barmston pump station5 as part of White Rose ultimately sees flows of 17.5 million tonnes/year with a footprint of approximately 150m x 250m. The equivalent pump at 3 million tonnes occupies a tract approx. 20m x 100m, although this could be reduced. So physical connection and size parameters also come into play. A test

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2.10%20BARMSTON

%20PUMPING%20STATION%20Illustrative%20Site%20Layout.pdf.URL



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layout is considered to check to see if an area can potentially accommodate a facility’s footprint.

Equipment Utility Pump

(Dense Phase)

Compressor

(Gas)

Pump Yes No

Compressor

Cooling

Pig Reciever/Launcher

Metering

Utility Fuel gas GT Only GT Only

Instrument/Plant Air

Cooling water supply

Dependent on selection of cooling water or air cooled equipment

Chilled coolant Dependent on pipeline specification

Electricity Fixed or variable speed drive only

Fixed or variable speed drive only

Table 4 – Option Equipment and Utility Requirements

7.4 Test Layout Impacts

At up to 5 million tonnes per year the gas case would require a compressor, the dense phase a pump for onward transmission offshore. Some assumptions have to be made for an assessment. In this case we consider data that is currently available. As part of the Longannet CCS Demonstration Project the Blackhills Compression facility raised the pressure from approx. 28-32 bar to approx. 120 barg with a flow capacity of 3 million tonnes per annum. The facility was split into a duty/duty/standby configuration of three compressors, the capacity of the site in total is 4.5 million tonnes per year.

The layout is shown as a compressor station (grey) overlaid by a pump station (blue) and common facilities (red). The compression facility is significantly larger than the pump facility for the same flow rate. The utility provision is also significantly higher, adding cooling water or air-cooling equipment and the associated footprint. Passing consideration also has to be given to expansion options in the future.

In considering this and other available areas the reduction in footprint offered by pumps opposed to compressors is preferred. The smaller utility footprint is also an advantage.



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i) Site Layout Overlays

ii) Location Plan

Figure 16 - Test Layouts



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8.0 Comparison and Conclusion

In summary the selection of the proposed network pressure can be summarised in Table 5.

100 bar 35 bar

With initial compression (integrated model)

Without initial compression (transporter model)

Pipeline only

Layout/Footprint

Utility provision

Table 5 – Summary Comparison and Conclusions

Selection in terms of cost for the whole system including initial compression cannot be differentiated. The margin of error in the modelling tools does not support selection on this basis.

Considering the more typical transporter model, in terms of cost, pipeline only, layout and utility provision all favour the dense phase model and selection of a 100 bar system.

Therefore this system pressure, 100 bar, is selected as the network pressure in this study.

amec project no. 1720 2000 - teesside collective · 2015-07-01 · this project is seeking to...

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