6.2-platform-and-pipeline-basis-of-design-for-studies.pdf

KCP-GNS-PCD-STU-0001

Revision: 04

Project Title: Kingsnorth Carbon Capture & Storage Project Page 1 of 68

Document Title: Basis of Design for Studies – Phase 1A

Kingsnorth CCS Demonstration Project

The information contained in this document ( the Information) is provided in good fai th.

E.ON UK plc, i ts subcontractors, subsidiaries, affi l iates, employees, advisers, and the Department of Energy and Cl imate Chan ge (DECC) make no representation or warranty as to the accuracy, rel iabil i ty or complet eness of the Information and neither E.ON UK plc nor any of i ts subcontractors, subsidiaries, affi l iates, employees, advisers or DECC shal l have any l iabil i ty whatsoever for any direct or i ndirect loss howsoever arising from the use of the Information by a ny party.

Basis of Design for Studies – Phase 1A


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Table of Contents

1. Introduction .................................................................................................................. 11

2. System Infrastructure .................................................................................................. 12

2.1. Onshore Facility .................................................................................................... 12

2.2. Offshore Facility .................................................................................................... 12

2.3. Offshore Electrical Power/Electrical Heating Infrastructure .................................... 12

2.4. Electrical Power Source ........................................................................................ 13

2.5. Fuel Gas Source ................................................................................................... 13

2.5.1. Fuel Gas Composition ............................................................................. 13

2.5.2. Fuel Gas Pressure ................................................................................... 13

2.5.3. Fuel Gas Temperature ............................................................................. 13

2.6. Valve Actuation ..................................................................................................... 13

3. Flow Assurance Basis of Design ................................................................................ 14

3.1. CO2 Physical Properties ........................................................................................ 14

3.1.1. Phase Envelope ...................................................................................... 15

3.1.2. Hydrates .................................................................................................. 16

3.1.3. Wax and Other Organic and Inorganic Solids .......................................... 16

3.1.4. Equation of State ..................................................................................... 17

3.2. Demonstration CO2 Production Rate/Cumulative Through Time............................ 17

3.2.1. Operating Conditions ............................................................................... 17

3.2.2. Flowrates ................................................................................................. 18

3.2.3. Number of Wells ...................................................................................... 18

3.2.4. Fluid Phase .............................................................................................. 18

3.2.5. Production Profile .................................................................................... 19

3.2.6. CO2 Production Profile after Demonstration Period .................................. 19

3.2.7. Zero Flow Periods .................................................................................... 19

3.2.8. Constraints Imposed by Reservoir ........................................................... 19

3.2.9. Wellhead Choking .................................................................................... 20

3.3. Process Facilities Assumed for Flow Assurance Work .......................................... 20

3.3.1. CO2 Plant Outlet Temperature ................................................................. 20

3.3.2. Offshore Compression ............................................................................. 20

3.3.3. Method of Heating CO2 Offshore ............................................................. 20

3.3.4. Pigging Requirements ............................................................................. 20


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3.4. Pipeline Configuration for Flow Assurance Work ................................................... 20

3.4.1. Landline ................................................................................................... 20

3.4.2. Sealine .................................................................................................... 20

3.4.3. Topography / Bathometry for Proposed Route ......................................... 21

3.4.4. Pipeline Diameter .................................................................................... 22

3.4.5. Design Pressure Sensitivities – Wall Thickness Assumptions .................. 22

3.4.6. Roughness .............................................................................................. 23

3.4.7. Insulation ................................................................................................. 24

3.5. Wellbore Data for Flow Assurance Work ............................................................... 25

3.5.1. Geometry ................................................................................................. 25

3.5.2. Wellbore Heat Transfer Coefficient .......................................................... 27

3.5.3. Annulus ................................................................................................... 27

3.6. Reservoir Data for Flow Assurance Work .............................................................. 27

3.6.1. Reservoir Characteristics ......................................................................... 27

3.7. Environmental Conditions for Flow Assurance Work ............................................. 29

3.7.1. Ambient Temperature .............................................................................. 29

4. Environmental Conditions ........................................................................................... 30

4.1. Water Depth .......................................................................................................... 30

4.2. Environmental Data ............................................................................................... 30

5. Additional Wells Data ................................................................................................... 31

5.1. No. of Wells Available for Injection as a Function of Field Life ............................... 31

5.2. Detailed Well Trajectory ........................................................................................ 31

5.3. Details of Well Availability Over Time .................................................................... 31

5.4. Well Completion Details (For Each Well) ............................................................... 31

5.5. Casings/Conductor Design .................................................................................... 32

5.6. Well PI (or Forchheimer Coefficients) for Each Well .............................................. 32

5.7. Initial Reservoir Pressure, and Expected Rise in Pressure Through Field Life ....... 32

5.8. Near Wellbore Thermal Profile .............................................................................. 32

5.9. Well Geothermal Gradient ..................................................................................... 33

5.10. Well Minimum/Maximum Temperature Limits - Any Time Limited Excursions Allowed 33

5.11. Well Flow/Flow Regime Limitations ....................................................................... 33

6. Well Service Data.......................................................................................................... 34


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6.1. Well Utility System Requirements .......................................................................... 34

6.1.1. Kill Fluid ................................................................................................... 34

6.2. Bed / Manning Requirements ................................................................................ 34

7. Additional Process Data .............................................................................................. 35

7.1. CO2 Plant Outlet Temperature ............................................................................... 35

7.2. CO2 Plant Outlet Pressure Requirements .............................................................. 35

7.3. Solids Content ....................................................................................................... 35

8. Metering Requirements ................................................................................................ 36

9. Platform / Facilities ....................................................................................................... 37

9.1. Platform Location .................................................................................................. 37

9.2. Foundation Conditions........................................................................................... 37

9.3. Platform Drilling/Workover Requirements .............................................................. 37

9.4. Design Life Requirements ..................................................................................... 38

10.Ecological Survey Data ....................................................................................................................................... 39

10.1. Onshore Ecological Survey Data ........................................................................... 39

10.2. Offshore Ecological Survey Data ........................................................................... 39

11.Subsea / Pipelines ....................................................................................................................................... 40

11.1. Design Life ............................................................................................................ 40

11.2. Materials ................................................................................................................... 40

11.2.1. Line Pipe Material .................................................................................... 40

11.2.2. Corrosion Resistant Alloys ....................................................................... 40

11.2.3. External Corrosion Protection .................................................................. 40

11.2.4. Concrete Weight Coating ......................................................................... 40

11.3. Pipeline Hydrotest Parameters .............................................................................. 40

11.4. Onshore Pipeline Location Class ........................................................................... 40

11.5. Onshore Pipeline Routing (HOLD 49) .................................................................... 41

11.5.1. Description of Proposed Route ................................................................ 41

11.5.2. Routing Constraints (Onshore) ................................................................ 42

11.6. Offshore Pipeline Routing ...................................................................................... 43

11.6.1. General .................................................................................................... 43


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11.6.2. Routing Contraints (Offshore) .................................................................. 43

11.6.3. Additional Routing Constraints ................................................................. 44

11.7. Onshore Pipeline Installation and Construction ..................................................... 45

11.7.1. General .................................................................................................... 45

11.7.2. Landfall .................................................................................................... 45

11.8. Offshore Pipeline Installation and Construction ..................................................... 46

11.8.1. General .................................................................................................... 46

11.8.2. Trenching and Burial ................................................................................ 46

11.8.3. Crossings and Third Party Ownership Considerations ............................. 46

11.9. Offshore Pipeline Protection Design ...................................................................... 46

11.10. Connections Design ................................................................................. 47

11.11. Risk Assessment ..................................................................................... 47

11.12. Pigging ........................................................................................................ 47

11.13. Future Expansion of System .................................................................... 47

11.14. Pipeline Safety and Control Systems ....................................................... 47

11.15. Condition Monitoring ................................................................................ 48

11.16. Onshore Pipeline Sectional Valves .......................................................... 48

11.17. Offshore Pipeline SSIVs .......................................................................... 49

11.18. Onshore Pipeline Design Data ................................................................. 50

11.18.1. Design Code ............................................................................................ 50

11.18.2. Design and Operating Conditions ............................................................ 50

11.18.3. Fluid Classification ................................................................................... 50

11.18.4. Mechanical Design .................................................................................. 50

11.18.5. Minimum Wall Thickness ......................................................................... 51

11.18.6. Materials .................................................................................................. 51

11.18.7. Corrosion Allowance ................................................................................ 51

11.18.8. External Corrosion Protection .................................................................. 51

11.18.9. Onshore Pipeline Routing ........................................................................ 51

11.18.10. Environmental Data .............................................................................. 53

11.19. Offshore Pipeline Design Data ................................................................. 53

11.19.1. Process Data ........................................................................................... 53

11.19.2. Environmental Data (Preliminary – HOLD 71) .......................................... 54


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11.19.3. Third-Party Considerations ...................................................................... 66

12. ........................................................................................................................ References ....................................................................................................................................... 67


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Table of Figures

Figure 3-1 Phase Envelope (HOLD 7) .................................................................................................. 15

Figure 3-2 Hydrate Curve (HOLD 8) ..................................................................................................... 16

Figure 3-3 Assumed Onshore Pipeline Profile HOLD 9 ....................................................................... 21

Figure 3-4 Assumed Offshore Pipeline Profile (Option C) HOLD 10 ................................................... 22

Figure 3-5 Overall Heat Transfer Coefficient ........................................................................................ 25

Figure 3-6 Tubing Geometry ................................................................................................................. 26

Figure 3-7 Injectivity Index .................................................................................................................... 29

Figure 11-1 Outline Onshore Pipeline Route ........................................................................................ 42

Figure 11-2 Outline Offshore Pipeline Outline Route ........................................................................... 44


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Table of Holds HOLD ITEM HELD

1 Source of Fuel Gas

2 Fuel Gas Composition

3 Fuel Gas Operating Pressure

4 Fuel Gas Design Pressure

5 Fuel Gas Operating Temperature

6 Fuel Gas Design Temperature

7 Pipeline Fluid Phase Envelope

8 Pipeline Fluid Hydrate Curve

9 Onshore Pipeline Route Profile

10 Offshore Pipeline Route Profile

11 Cleared

12 Cleared

13 Cleared

14 Cleared

15 Cleared

16 Cleared

17 Cleared

18 Cleared

19 Cleared

20 Cleared

21 Cleared

22 Wind Rose With Wind Speeds

23 Min & Max Temperatures – Air (Onshore & Offshore)

24 No of Wells Available for Injection as a Function of Field Life

25 Detailed Well Trajectory

26 Details of Well Availability Over Time

27 Well Completion Details (For Each Well)

28 Casings/Conductor Design

29 Well PI (or Forchheimer Coefficients) for Each Well

30 Initial Reservoir Pressure and Expected Rise in Pressure Through Field Life

31 Initial Reservoir Temperature

32 Well Geothermal Gradient

33 Well Minimum/Maximum Temperature Limits- Any Time Limited Excursions Allowed

34 Conductor Sizes

35 Well Utility System Requirements

36 Bed/Manning Requirements


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HOLD ITEM HELD

37 Design Pressure of Pipelines

38 HIPPS System Required/Not Required

39 Onshore Metering Requirements

40 Topsides Metering Requirements

41 Well Metering Requirements

42 Vent Meter Requirement

43 Vent Meter Accuracy

44 No of Wells For Extended Capacity Case

45 Platform Drilling/Workover Requirements

46 Spacing and Arrangement Details For Platform Wells

47 Onshore Ecological Survey Data

48 Offshore Ecological Survey Data

49 Onshore Pipeline Routing

50 Pipeline Bend Radii Requirements

51 Straight Length Requirements Following Route Deviations

52 Onshore Pipeline Design Pressure

53 Maximum Allowable Operating Pressure – Onshore Pipeline

54 Maximum Design Temperature – Onshore Pipeline

55 Minimum Design Temperature – Onshore Pipeline

56 Minimum Design Temperature – Materials - Onshore Pipeline

57 Landfall Valve Easting Location

58 Landfall Valve Northing Location

59 Kingsnorth Pipeline ESD Valve Easting Location

60 Kingsnorth Pipeline ESD Valve Northing Location

61 No of Onshore Third Party Service Crossings

62 No of Onshore Pipeline Crossings

63 Ground Water Properties

64 Onshore Pipeline Soil Conditions

65 Offshore Pipeline Design Pressure

66 Maximum Allowable Operating Pressure – Offshore Pipeline

67 Maximum Design Temperature – Offshore Pipeline

68 Minimum Design Temperature – Offshore Pipeline

69 Minimum Design Temperature – Materials - Offshore Pipeline

70 Arrival Conditions at Hewett

71 Offshore Pipeline Environmental Data

72 Marine Growth

73 Offshore Pipeline Soil Conditions


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HOLD ITEM HELD

74 Landfall Data

75 Water depth

76 Wells ability to cope with zero flow

77 Tubing sizes

78 Instrument Air Systems Design Philosophy Document Number

79 Maximum content of trace components in gas composition

80 Well Locations

81 Method of adjusting the choke valves

82 Casing pressure monitoring and venting requirements

83 Well Flow/Flow Regime Limitations/Bottom Hole Temperature Limitations

84 Allowable solids content for wells


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1. Introduction

E.ON UK are considering investment in a new state of the art, coal fired power plant at Kingsnorth. The CO2 that this new plant produces is intended to be captured in the depleted Hewett reservoir, which is approximately 40 km east of Bacton and approximately 270 km from Kingsnorth. Pre-FEED studies are currently underway to evaluate the potential of investing in a replacement power station with Carbon Capture and Storage (CCS).

The broad concept has been selected: CO2 will be captured from the flue gas at the proposed E.ON coal fired power plant located at Kingsnorth. The captured CO2 will be compressed and dried at a new onshore plant at Kingsnorth before being transported in a new pipeline to a new offshore platform, which is located at the Hewett reservoir.

This document provides the basis of design for all of the study work that follows and this document should be used as a reference source for all data that will be used during Phase 1A of the Project.

Much data is still held and assumptions made. These holds and assumptions will be declared as such in this document and provision or confirmation of this data must be made before the project can successfully move to the next phase.


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2. System Infrastructure

There is a potential for stepwise growth in transport volumes from the Demonstration flowrate (6600 tonnes/day) to 4 x Demonstration (26 400 tonnes/day), and then to full pipeline capacity. However, the impact on the topsides of flowrates greater than 26 400 tonnes/day will not be assessed in the current scope of this study, apart from incorporating a 36 inch flanged connection on the topsides for the tie-in of additional facilities.

2.1. Onshore Facility

The onshore facility for the CO2 Transport System takes compressed and cooled CO2 from the carbon capture plant and directs the fluid to the onshore pipeline for transportation to the offshore facility.

The base case for the onshore facility for the CO2 Transport System includes an onshore meter, which is used for fiscal metering of the CO2 and for leak detection purposes.

An onshore permanent pig launcher is also provided for initial system commissioning, pipeline inspection and for sweeping the CO2 from the pipeline system into the reservoir.

The onshore blowdown facility for venting and dispersing CO2 will be designed by others

2.2. Offshore Facility

A subsea solution is not required for the offshore CO2 handling system.

The base case is a single platform, which is rated to handle the CO2 that is flowing in the pipeline when in the gaseous phase of the CO2 phase envelope and then is to be upgradeable to cope with the dense phase operation. This base case option has a well capacity for 4 wells and has a CO2 handling capacity of 6600 tonnes/day. This flowrate is approximately equivalent to the CO2 that is produced onshore when generating 400 MW(gross).

Consideration needs to be given to the base case to allow for future expansion and to allow for the transition to a full flow dense phase case to be accommodated in the future. The full flow case is the for a total of 12 wells and a CO2 handling capacity of 26 400 tonnes/day.

2.3. Offshore Electrical Power/Electrical Heating Infrastructure

It should be noted that both electrical heating and fuel gas fired (direct and indirect) heating is being considered at the moment.

The base case option is to assume that any electrical cable that is supplying power to the offshore facility is only to be rated to handle the electrical power requirements for the facility when the pipeline is operating in the gaseous phase of the CO2 phase envelope.

Two alternative electrical heating cases that need to be evaluated are:-

The base case option will be supplemented at a later date by an additional A/C electrical cable, which allows the facility to produce enough heat electrically in order to handle the dense phase CO2 that would be produced from a 1600 MW(gross) onshore power plant.

A single A/C cable being run initially, which allows the facility to produce enough heat electrically, in order to handle the dense phase CO2 that would be produced from a 1600 MW(gross) onshore power plant.


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2.4. Electrical Power Source

Electrical power will be supplied from the nearest suitable onshore location, which most probably will be Great Yarmouth. The most practical location will be identified in a separate study. However, for the alternative cases, then the option of powering the offshore 1600 MW(gross) facility from Kingsnorth with D/C power will be evaluated.

2.5. Fuel Gas Source

Fuel gas may be potentially supplied to the offshore facility for heat generation from Bacton area. It is assumed that E.ON will have managed to acquire gas from the grid. (HOLD 1).

2.5.1. Fuel Gas Composition

The composition is as follows: - HOLD 2.

For the purposes of assessing the topsides processing requirements, then it will be assumed that the gas will be 100% methane. It will also be assumed that the gas will be suitably dewpoint controlled by the fuel gas supplier (water and hydrocarbons), so that liquid dropout in the pipeline and on the offshore facility would not occur.

2.5.2. Fuel Gas Pressure

The fuel gas operating pressure is assumed to be 70 barg- HOLD 3

The fuel gas design pressure is assumed to be 85 barg – HOLD 4

2.5.3. Fuel Gas Temperature

The fuel gas operating temperature from the grid is – HOLD 5

The fuel gas design temperature is – HOLD 6

The temperature of the gas arriving at the offshore facility may be assumed as being at seabed temperature.

2.6. Valve Actuation

In accordance with the Instrument Air Systems Design Philosophy, Doc. No. (HOLD 78), which was issued in draft form by E.ON. An Instrument Air System will not be provided on the offshore facility. It is assumed that CO2 will not be used as a motive medium due to low temperatures and solids forming when venting. Hydraulic power is to be the preferred motive medium for valve operation.


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3. Flow Assurance Basis of Design

3.1. CO2 Physical Properties

The CO2 unique physical properties are summarised below.

Property Value

Molecular Weight 44.01

Critical Temperature 31.1 °C

Critical Pressure 73.9 bar

Critical Density 467 kg/m3

Triple Point Temperature -56.5 °C

Triple Point Pressure 5.18 bar

Boiling (sublimation) point (1 atm) -78.5 °C

Table 3-1 CO2 Physical Properties

The composition to be analysed is presented in Table 3-2. This composition was provided by E.ON. (Reference S14). The maximum content of trace components is Held (HOLD 79).

Component Composition (mol %)

H2S Nil

COS Nil

CO2 99.94

CO Nil

H2 Nil

N2 Less than 350 ppmv

Ar Nil

CH4 Nil

O2 Less than 200 ppmv

Table 3-2 Gas Composition

A normal water content of less than 24 ppmv is to be assumed, which could rise to a figure of less than 100 ppmv in an upset condition.


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3.1.1. Phase Envelope

The phase envelopes for the given compositions are obtained by Multiflash and are presented below.

0

10

20

30

40

50

60

70

80

90

100

-60 -50 -40 -30 -20 -10 0 10 20 30 40

Pre

ssu

re (b

ara

)

Temperature (°C)

CO2 Phase Envelope

99.5% CO2 95% CO2

Critical Point

Figure 3-1 Phase Envelope (HOLD 7). Note - Percentage relates to mol%.


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3.1.2. Hydrates

The hydrate curves for the given compositions are obtained by Multiflash and presented below.

0

10

20

30

40

50

60

70

80

-10 -8 -6 -4 -2 0 2 4 6 8 10 12

Pre

ssu

re (b

ara

)

Temperature (°C)

CO2 Hydrate Curve

99.5% CO2 95% CO2

Figure 3-2 Hydrate Curve (HOLD 8.) Note - Percentage relates to mol%.

Hydrate curves for 99.5 mol% CO2 will be presented alongside the same curve with a margin of 3 °C.

3.1.3. Wax and Other Organic and Inorganic Solids

Wax formation is not expected in the system, however, it should be noted that liquid and supercritical CO2 are good solvents for oils and waxes and certain inorganic solids and will strip such material from bearings or rotating seals if they are exposed to the CO2.

The parties responsible for the carbon capture and compression parts of the plants should be made aware of this issue, since any compounds dissolved in the CO2 during its journey though these sections is likely to be deposited in the cooler pipeline sections of the transport system.


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3.1.4. Equation of State

Reference should be made to “EOS Prediction of CO2 Properties” Doc No. KCP-GNS-FAS-DRP-0001 [S17].

CO2 reaches supercritical conditions at relatively low pressure and temperature. In the near critical region, a specialised Equation of State such as Span and Wagner is recommended.

The near critical region is defined approximately as:

0.95 < Tr, Pr < 1.05

Where,

Tr = T / Tc T = actual temperature Tc = critical temperature

Pr = P / Pc P = actual pressure Pc = critical pressure

However, during the operation of the system, supercritical conditions will be avoided so the operating pressure and temperature are away from the critical point, i.e:

0.95 > Tr, Pr > 1.05

Therefore, if necessary outside the near critical region the Soave-Redlich-Kwong (with a Peneloux temperature correction) will be used as the equation of state for the system. A separate fluid characterisation Technical Note will be issued describing the recommended calculation methods for CO2 and its mixtures [S17].

3.2. Demonstration CO2 Production Rate/Cumulative Through Time

3.2.1. Operating Conditions

The initial assumptions for the operating conditions are presented below.

LP (gas phase) HP (dense phase)

Maximum Pressure (barg) 39 150

Minimum Pressure (barg) 2 79

Maximum Temperature (°C) (1) (3) (1)

Minimum Temperature (°C) 4 (2) (4) 4 (2)

Notes 1) Assuming an inlet temperature at Kingsnorth of 30°C (Ref. S1), the maximum temperature of the

system will depend on how much heat has to be added to the CO2 stream to maintain the system downstream of the Hewett choke in the gas or dense gas phase.

(2) Winter subsea/ground ambient temperature. (3) Heat is not added during normal operation – only at offshore facility during start-up. (4) Winter air temperature is minus 6°C, cooling offshore could occur during a shutdown.

Table 3-3 Flowline Operating Conditions


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Heating is to be provided at the Hewett platform to maintain a gas temperature above 0°C and single phase fluid in the complete injection string. For information, the CO2 may have to be heated to above 52 deg C, resulting in a temperature downstream of the choke valve of approximately 32 deg C, to ensure single phase fluid is maintained in the injection string.

3.2.2. Flowrates

Unless advised otherwise, the maximum flowrates for both scenarios will be as presented below. The flows for the base and full flow scenarios have been agreed previously with E.ON, however, an additional case (referred to as “max capacity”) was requested whereby the maximum capacity of the flowline is to be determined for dense phase operation. This is to allow the available ullage in the pipeline to be estimated.

Scenario

Base Full Flow Max Capacity

Power equivalent 400 MWg 300 MWe

1600 MWg 1200 MWe

TBC

Flowrate (tpd) 6,600 26,400 TBC

Peak annual volume (t/yr) 2,410,650 9,642,600 TBC

Average annual volume (t/yr) 2,169,585 8,678,340 N/A

Table 3-4 Flowrates

Note. The availability used for the average annual volume is 90%.

Further sensitivity cases examining the pipeline performance at low turndown will be performed, where 25% of design flow will be considered for the base and full flow cases.

3.2.3. Number of Wells

There will be 3 flowing wells (plus one installed spare) for the base case simulations. It is assumed that the flow is distributed evenly between the three wells i.e flow to single well = 1/3 of total pipeline flow of 6,600 te/d = 2,200 te/d.

There will be 12 wells for the full flow case. As for the base case the pipeline flow (26,400 te/d) is assumed to be distributed evenly between the 12 wells such that the flow to a single well is 2,200 te/d.

3.2.4. Fluid Phase

For all cases operating conditions must ensure that no 2 phase flow is present in the pipeline from Kingsnorth to Hewett i.e. it must be either gas or dense phase. The base case option would be a platform sized for the base case scenario demonstration flows of “gaseous phase” fluids only, however the design will require to be suitable for dense phase operation at full flow.

To avoid operating in the two-phase region, the base case option assumes that the pipeline will operate in LP (gaseous phase) mode up to a maximum inlet pressure of 39 barg. At this point operation will switch to HP (dense phase) mode with a minimum operating pressure of 79 barg. It is assumed that the transition from LP to HP operation is coincident with the switch from base case to full flow production.


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3.2.5. Production Profile

As per previous flow assurance studies (Ref S10S10), the following cases will be considered unless advised otherwise:

Reservoir Pressure

(bara)

Reservoir Pressure

(PSIA)

Average BHP (bara)

Average BHP (PSIA)

3 45 9 134

7 107 18 259

20 283 27 398

31 443 36 517

46 673 50 719

112 1622 113 1643

159 2299 160 2322

Table 3-5 Cases Modelled within Flow Assurance Study

3.2.6. CO2 Production Profile after Demonstration Period

Following the demonstration period, it is assumed that the CO2 production rates increase from base case to full flow..

E.ON anticipates being obliged to increase the rates should the government determine that CCS is mandatory.

3.2.7. Zero Flow Periods

It is possible that there will be “swing down” at night, i.e. the onshore power plant could be regularly shutdown for 12 hour periods at night. There could also be “swing down” at weekends, such that the onshore power plant will be routinely shutdown for 60 hour periods.

Routine long term (2 to 12 weeks) maintenance shutdowns will also occur, possibly every couple of years to begin with, and then every 3 to 4 years.

The pipeline system should be capable of being shut down for extended periods for maintenance and also be able to operate with occasional occurrences of fluctuations to and from zero flow within the period of one day.

It should also be noted that flow to the carbon capture system may be turned off, or down for short periods, if the power station is required to increase power output to meet National Grid requirements.

3.2.8. Constraints Imposed by Reservoir

It was agreed with E.ON that it may be assumed initially that the wells will be designed to cope with zero flow at anytime. This therefore negates the requirement to meet any well minimum flow requirements. (HOLD 76).


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3.2.9. Wellhead Choking

It is presumed that there is no choking required at the wellhead when the fluid is operating in the gaseous phase. However choking will be required for the full flow and maximum capacity scenarios.

3.3. Process Facilities Assumed for Flow Assurance Work

3.3.1. CO2 Plant Outlet Temperature

A plant outlet temperature of 30 deg C is to be used, with a sensitivity case of 50°C.

3.3.2. Offshore Compression

Offshore compression was discounted at an earlier phase of development and will therefore not be considered in this study.

3.3.3. Method of Heating CO2 Offshore

Reference should be made to the decision paper “Natural Convection Subsea Heater, Decision Paper”, Doc No. J71018-A-P-DP-002-B1 and the decision paper “Forced Convection Subsea Heater, Decision Paper”, Doc No. J71018-A-P-DP-003-B1.

The base case will assume that an electric heater will be used to heat the CO2 offshore prior to injection. Two alternative heating methods will be considered as sensitivity cases: a direct fired heater and an indirect fired heater. Platform heating with seawater is a sensitivity case which will remain outside the scope of this current study.

It will be assumed that a heater is to be installed on each well upstream of the choke, though a sensitivity case will be considered whereby a single heater upstream of the chokes, sized for all wells, will be considered. Heaters, using seawater as the heating medium and would be installed downstream of the chokes are a sensitivity case, which is to remain outside the scope.

3.3.4. Pigging Requirements

The base case assumption is that permanent pig traps will be required both onshore and offshore. Two sensitivity cases will be considered:

Permanent pig trap onshore only

No pigging requirements

3.4. Pipeline Configuration for Flow Assurance Work

3.4.1. Landline

From reference [S2], this initial onshore section of the pipeline route heads in a northerly direction from the Power Station to St Mary‟s Marshes and the subsequent Landfall (start of Offshore) location, encountering a variety of features en route, including 3

rd party pipelines

and services, ditches (16), access tracks (7), a rail line (1) an A-road (1) and some lower class roads (5).

3.4.2. Sealine

From reference [S2], a number of potential and actual obstacles are present along the route, these include wind farm concession areas, disposal sites, UK mineral rights extent, existing cables and pipelines and a military practice exercise area (PEXA).


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3.4.3. Topography / Bathometry for Proposed Route

The proposed pipeline routing comprises 7.6kms of onshore pipeline from Kingsnorth Power Station to the shoreline and a connecting offshore pipeline approximately 270kms long from the shoreline to the Hewett Field (Ref S12).

An indicative topography for the onshore section was extracted from the onshore corridor map (Ref S13), shown in Figure 3-3. The pipeline route for the offshore piping is assumed to follow the seabed profile for Option C (Easterly Route), which is shown in Figure 3-4. Seabed bathymetry will be confirmed by survey during 2010.

Figure 3-3 Assumed Onshore Pipeline Profile HOLD 9


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Figure 3-4 Assumed Offshore Pipeline Profile (Option C) HOLD 10

Data was extracted from the above profile and used to create an indicative topography for Olga modelling.

3.4.4. Pipeline Diameter

This study will cover the 36” OD pipeline size only; further sensitivity cases for different line sizes may be required at a later date, however these are currently outside the scope of this study.

3.4.5. Design Pressure Sensitivities – Wall Thickness Assumptions

The pipeline to be considered is assumed for flow assurance purposes, to have the following characteristics:

Design pressure

(barg) Size

OD (mm)

ID (mm)

WT (mm)

Material grade

120 36” 920.8 873.2 23.8 X65

150 36” 920.8 866.8 27 X65

200 36” 920.8 854 33.4 X65

Table 3-6 Pipeline Characteristics – onshore section (to 500m zone)

Note 1: These thicknesses are preliminary and will be confirmed during the course of the study. Some localised sections, e.g. crossings may have to have thicker wall thicknesses.

Design pressure

Size OD

(mm) ID

(mm) WT

(mm) Material grade


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(barg)

120 36” 914.4 873.2 20.6 X65

150 36” 914.4 866.8 23.8 X65

200 36” 914.4 854 30.2 X65

Table 3-7 Pipeline Characteristics – offshore section

Note 1: These thicknesses are preliminary and will be confirmed during the course of the study.

The base case assumes a pipeline design pressure of 150 barg. A range of sensitivity cases are to be considered, as defined below:-

Design pressure 200 barg (practical limit for Thames cluster)

Design pressure 120 barg

3.4.6. Roughness

A roughness of 0.0018 inches (new carbon steel pipe) is assumed for the pipeline.


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3.4.7. Insulation

From Reference S1, a typical pipe coating is assumed at this time of 5mm bitumen for all onshore pipe; 5mm bitumen plus 50 mm concrete weighting for all offshore pipe. The onshore pipeline is assumed to be buried; the offshore pipeline is assumed to be laid on the seabed and exposed to sea currents. Note that there will be sections of the offshore pipeline that require to be buried however this level of detail is not currently available and so the entire pipeline is assumed to be unburied. No account has been taken for any sections of heavier walled pipe.

The material properties used are presented below:

Material Cp (J/kg°C) K (W/m K) Density (kg/m3)

Carbon Steel 470 45 7850

Subsea sandy soil 1250 2.6 1750

Bitumen enamel 1300 0.7 1325

Concrete coating HD 880 2.7 3000

Table 3-8 Material properties

The pipeline wall coatings used in the system are shown in Table 5-4.

Section Material Wall thickness

(mm) U value (ID) (W/m2 K)

Onshore pipe

Steel 27 (1)

3.3 Bitumen 5

Soil (buried) 1000 *

Offshore pipe

Steel 23.8 (1)

15.5 Bitumen 5

Concrete weighting 50

Riser pipeline-Hewett Steel 31.8

137 Bitumen 5

Note: 1) Wall Thickness will vary with design pressure. Value for base case pressure of 150 barg shown here. To be confirmed * The Value used in OLGA was modified slightly to achieve a required U-value in the onshore section. Table 3-9 Assumed Pipeline Thermal Properties – For Estimation of U Value


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The overall heat transfer coefficients obtained using these material properties and wall thicknesses are presented in the figure below.

Figure 3-5 Overall Heat Transfer Coefficient

3.5. Wellbore Data for Flow Assurance Work

For the initial analysis, three wells from the Lower Bunter will be assessed. However to simplify the OLGA modelling an average well is assumed so that all wells are equivalent in terms of dimensions and injectivity (Reference [S5]).

3.5.1. Geometry

From Reference [S9], the three Lower Bunter wells will be modelled as vertical.

The figure below presents the model representation of the wellbore from the Hewett platform to the reservoir.


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Figure 3-6 Tubing Geometry

The tubing sizes, which are to be confirmed by Baker RDS (HOLD 77), are expected to be 7⅝ inch OD (6.969 in ID) and 9⅝ inch OD casing. (Ref.SS5).

A sensitivity of 4.5” tubing will be investigated for the full flow case.

A thickness of 1.5 inches of cement between the outer case and the base rock is assumed (Ref.S8).

The material properties used are presented below:

Material Cp (J/kg°C) K (W/m K) Density (kg/m3)

Sandstone 766.2 1.8 (1) 2650

Brine 4300 0.605 1000

Cement 837.4 0.866 1890.4

Note:

1) K-value used in OLGA was 8.204 W/m K to achieve the required U value.

Table 3-10 Material Properties


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The wellbore wall properties used in the system are presented below.

Section Material Wall thickness

(mm) U value (ID)

(W/m2 K)

Tubing Hewett-seabed

Steel 8.3

18.8 Brine 42.06 (1)

Steel 12.7 (1)

Tubing subsea

Steel 8.3

11.0

Brine 12.7 (1)

Steel 12.7 (1)

Cement 38.1

Sandstone 10000

1) Assumed Values – Requires confirmation

Table 3-11 Wellbore Wall Properties

3.5.2. Wellbore Heat Transfer Coefficient

A heat transfer coefficient of 11 W/m2 K will be assumed along the wellbore unless otherwise

stated. A linear geothermal gradient will be assumed from the reservoir to the seabed.

3.5.3. Annulus

The annulus will be assumed to be filled with inhibited brine unless advised otherwise.

3.6. Reservoir Data for Flow Assurance Work

3.6.1. Reservoir Characteristics

The reservoir depth is presented below.

Reservoir Depth

GWC Lower Bunter 4415ft / -1345.7m TVDSS

Table 3-12 Reservoir Depth

Reservoir Temperature

The Reservoir Temperature range is 108 °F to 126 °F. The base case, Lower Bunter reservoir temperature is 52 °C; no sensitivity analyses will be performed


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Productivity index

The productivity and injectivity index will be calculated from Reference S5 using the reservoir pressure and the bottom hole flowing pressure. Seven points along the field life are analysed for the 3 wells. An average is presented in the table below. Note that the PI values are based on the 400 MWg (3 well) profile – the reservoir PI for a single well or 12 wells can be obtained by multiplying by the appropriate factor as shown in Table 3-14.

Reservoir Pressure (psia)

Average BHP (psia)

Average Injectivity Index (scfd/psi)

Average 3-well Injectivity Index

(kg/s/Pa)

45 134.1 1.6 0.000143

107 258.8 0.9 0.000084

283 398.1 1.2 0.000110

443 516.5 1.9 0.000172

673 718.9 3.1 0.000275

1622 1643.0 6.9 0.000493

2299 2322.3 6.2 0.000600

Table 3-13 Injectivity Index

Reservoir Pressure (psia)

Average Injectivity Index (kg/s/Pa)

1 well 3 wells 12 wells

45 0.000048 0.000143 0.000573

107 0.000028 0.000084 0.000334

283 0.000037 0.000110 0.000440

443 0.000057 0.000172 0.000688

673 0.000092 0.000275 0.001099

1622 0.000164 0.000493 0.001970

2299 0.000200 0.000600 0.002401

Table 3-14 Injectivity Index vs. Number of Wells


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Figure 3-7 Injectivity Index

3.7. Environmental Conditions for Flow Assurance Work

3.7.1. Ambient Temperature

The ambient conditions assumed for this study are presented in the table below. Ambient seawater temperatures were extracted from Ref [S11] while ground and air temperatures are based on previous flow assurance studies (Ref S10).

Conditions Ground

temperature (°C)

Air temperature

(°C)

Sea surface temperature

(°C)

Seabed temperature

(°C)

Max Summer 18 35 21 17

Min Winter 4 -6 1 4

Table 3-15 Ambient Temperature


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4. Environmental Conditions

4.1. Water Depth

The water depth at the Hewett Platform in 37m.

4.2. Environmental Data

Refer to Section 11.19 for information.


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5. Additional Wells Data

This section needs to be populated by E.ON and Baker/RDS. Assumptions have been made in section 3 in order to allow the flow assurance work to proceed. However, detailed information for the headings given below must be made available to the project.

5.1. No. of Wells Available for Injection as a Function of Field Life

HOLD 24 Initial design assumptions are:-

For the gaseous phase of operation – 4 wells (3 operational wells and one spare) to be drilled by a jack-up drilling rig once the platform is installed.

Once CO2 is being injected in dense phase, the number of operational wells may decrease. A workover to recomplete the wells to smaller tubing may be required prior to dense phase injection. Note that as 4 wells are available all four may be used to distribute CO2 evenly in the reservoir.

Platform to be designed to allow a further 8 wells to be drilled (i.e. total of 12 slots)

Above assumptions are to be used for initial platform design. The numbers will be reviewed and confirmed by Baker-RDS during FEED Phase 1a (i.e. during 2010)

5.2. Detailed Well Trajectory

HOLD 25

Information is not currently available to this level of detail.

Preliminary design work indicates deviated wells (deviation up to 60 degrees) to a True Vertical Depth (TVD) of approx 1050 m.


5.3. Details of Well Availability Over Time

HOLD 26

5.4. Well Completion Details (For Each Well)

HOLD 27

Preliminary design indicates:-

7 inch diameter injection tubing for gaseous phase injection

Downhole safety valve to be of a tubing retrievable flapper design that will require hydraulic control from surface tied into the installation shut-down system.

Instrumentation to include downhole temperature, pressure and micro-seismic sensors plus distributed fibre-optic temperature sensors.

Conventional Christmas Trees to be used and will require a separate hydraulic control supply tied into the installation shut-down system

A choke valve, which is to be located downstream of an electrical well heater will regulate flow to each well. The choke will be remotely operated and will be adjusted by an electrical motor (HOLD 81).

A temperature probe is to be located downstream of the well choke valve. This temperature probe will be used to control the heat input into the well heater and maintain the temperature of the carbon dioxide entering the well.


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An additional low temperature probe, also located downstream of the choke valve, is to be used for low temperature shutdown purposes.

Above assumptions are to be used for initial platform design. This information will be reviewed and confirmed by Baker-RDS during FEED Phase 1a (i.e. during 2010).

5.5. Casings/Conductor Design

HOLD 28

Preliminary design indicates:-

Driven 30” conductor.

Drilled 17 ½” hole with 13 3/8” casing.

Drilled 12 ¼” hole which will be opened up to 14 ¾” with the option of allowing a 11 ¾” liner to be run.

9 5/8” casing across the reservoir, cemented to surface. A short section (150 – 200 m) of 10 3/42” casing may be required to accommodate a sub-surface shutdown valve (SSSV) plus cables etc.


The venting requirements and whether there is a requirement to monitor the pressure of each casing locally and/or remotely will be defined by Baker-RDS during the FEED Phase 1a (HOLD 82).

5.6. Well PI (or Forchheimer Coefficients) for Each Well

HOLD 29

To be determined by Baker-RDS during FEED Phase 1a (i.e. during 2010)

5.7. Initial Reservoir Pressure, and Expected Rise in Pressure Through Field Life

HOLD 30

Initial reservoir pressure is 2.69 bara (39 psia).

Pressure will rise during field life at a rate that is linked to the volume of CO2 injected.

Reference should be made to Table 3.12.

Above assumptions are to be used for initial platform design. The numbers will be reviewed and confirmed by Baker-RDS during FEED Phase 1a (i.e. during 2010).

5.8. Near Wellbore Thermal Profile

HOLD 31

Average reservoir temperature in the Hewett Field Lower Bunter reservoir is 52°C.

The process of injection causes local cooling at each wellbore due to the Joule-Thompson effect at the perforations. The long term sustained temperature is approx. 12°C. Modelling indicates a temperature-affected zone of radius of approximately 600m around each wellbore.

The above assumptions are to be used for initial platform design. The numbers will be reviewed and confirmed by Baker-RDS during FEED Phase 1a (i.e. during 2010).


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5.9. Well Geothermal Gradient

HOLD 32

The geothermal gradient should initially be assumed to be linear from surface to reservoir depth (52°C at 1345m or 4415 ft TVDSS (True Vertical Depth Subsea)).

The above assumptions are to be used for initial platform design. The numbers will be reviewed and confirmed by Baker-RDS during FEED Phase 1a (i.e. during 2010).

5.10. Well Minimum/Maximum Temperature Limits - Any Time Limited Excursions Allowed

HOLD 33

This is required for all casings and all well layers, i.e. tubing, casings, cement etc.

Definition of what thermal stresses may be tolerated in the well. What is the maximum rate of change allowable for increases in temperature and decreases in temperature?

In addition, as the well will be seeing dense phase CO2 later in field life, then the well contents could cool significantly when depressurised. Any minimum temperature limitations of the well system need to be defined.

Initial assumption is that minimum temperature allowed in wellbore is 0°C (zero centigrade).

No work has currently been done on maximum temperature ratings. Standard wellbore equipment will be used. In oil and gas production this equipment routinely sees temperatures of over 50°C

The above assumption is to be used for initial platform design. The numbers will be reviewed and confirmed by Baker-RDS during FEED Phase 1a (i.e. during 2010).

5.11. Well Flow/Flow Regime Limitations

HOLD 83

For power plant shutdowns of less than 20 hrs, then as long as the pipeline volume remains available, with the wells and the topsides systems all functioning, then flow into the wells will still remain possible through the well choke valves.

Details of the pressure decay in the pipeline, which will reduce the flow into the wells, is provided in Appendix A in document “Transient Analysis – Start-Up (Pipeline)”, Doc. No. KCP-GNS-FAS-DRP-0003.

Also include any flowrate limitations on start-up and define allowable flowrate increases or decreases. Other typical information in this section would be what flow regimes may be tolerated by the well and why these limits have been imposed.

Based on flow assurance work undertaken by Genesis Oil & Gas Consultants in 2009, it should be assumed that two phase flow is NOT to be permitted in the wellbore.

The above assumption is to be used for initial platform design. The numbers will be reviewed and confirmed by Baker-RDS during FEED Phase 1a (i.e. during 2010).


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6. Well Service Data

6.1. Well Utility System Requirements

HOLD 35

6.1.1. Kill Fluid

Kill fluid is the medium that is pumped into the well to prevent the well from flowing during a “well kill”. The “well kill” is an operation to place a column of heavy fluid into a wellbore preventing the flow of reservoir fluid, without the need for pressure control equipment at the surface. It works on the principle that the weight of the kill fluid will be enough to suppress the pressure of the formation fluid.

Under all foreseeable operating conditions during the demonstration phase, seawater is to be assumed as the kill fluid. A topsides pump will be required, which is to be capable of pumping filtered seawater into the wellbore, at a maximum pressure of 10 barg (as defined at the interface with the xmas tree) and at a maximum rate of approx. 20 m

3/h (3000 barrels/day).

The filtration requirements for the seawater are that all particles of a size greater than 1000 micron are to be removed.

A kill fluid header, which is currently assumed to be 3 inches NB will be provided. This header will be located along the wellbay, with a 3 inch flanged and blinded take-off, located in the vicinity of each well.

6.2. Bed / Manning Requirements

HOLD 36

A Normally Unmanned Installation (NUI), using a workover rig will be assumed by Genesis, unless informed otherwise.


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7. Additional Process Data

7.1. CO2 Plant Outlet Temperature

A maximum operating temperature of 30 deg C is to be used, with a sensitivity case of 50°C.

It is assumed that a high integrity protection system is not required on the pipeline section and that any failures of the upstream cooling systems will not require any additional facilities for the pipeline section. It is assumed that all safety systems to protect the pipeline against overtemperature are contained in onshore CO2 plant.

7.2. CO2 Plant Outlet Pressure Requirements

An assumed design pressure of 150 barg (HOLD 37) is to be used for the onshore section, the onshore and offshore pipeline and the offshore facility that is handling the CO2 up to the wellhead.

It is assumed that a HIPPS system is not required (HOLD 38) on the pipeline section and that any failures of the upstream operating systems, such as a failure of the compression overpressurisation protection systems, will not require any additional facilities for the pipeline section. It is assumed that all safety systems to protect the pipeline against overpressure are contained in onshore CO2 plant.

7.3. Solids Content

HOLD 84

The pipeline to the offshore facility will be carbon steel, which will have been initially flushed with seawater and then emptied, swabbed with MEG and swept through with multiple cleaning pigs, which will be propelled along the pipeline by dry compressed air. The level of cleanliness of the pipeline, prior to introducing CO2 into the pipeline, will be as best as can reasonably be achieved. However, some rust particles will still be carried onto the platform. It is envisaged that filters will be provided downstream of the pigging branch from the 36 inch (OD) pipeline.

Baker/RDS are to state what solids content can be tolerated by the wells. Baker/RDS are to state the particle size distribution and the maximum quantity of solids per unit volume of CO2.


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8. Metering Requirements

(HOLD 80)

Metering to fiscal standard will be provided onshore, within the boundary of the CO2 plant – HOLD 39.

Metering offshore will be for leak detection purposes only, located immediately downstream of the riser shutdown valve. – HOLD 40.

Additional metering will be provided for each well. This will be by venturi metering – HOLD 41. These meters will be located upstream of the well choke valve.

A meter will be installed to measure all of the CO2 that is vented. This shall be an ultrasonic type of meter (HOLD 42). The level of accuracy required is (HOLD 43).


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9. Platform / Facilities

During FEED and Detail Design offshore structures are designed to resist actions arising from a range of permanent, temporary and accidental criteria, as listed below:-

i. Permanent a. In-place strength b. In-place Fatigue

ii. Temporary a. Load-out b. Transportation strength and fatigue if required. c. Lift d. On-bottom Stability

iii. Accidental a. Pushover b. Ship Impact c. Earthquake d. Extreme Environmental - 10,000-yr return wave e. Dropped Objects f. Fire g. Jet cooling by a CO2 leak

For this conceptual design of the substructure, only the in-place strength will be considered, as this is the governing criteria for the majority of primary framing members of the substructure. Weight allowance will be included for the other design conditions.

9.1. Platform Location

The location of the offshore facility/wells has yet to be confirmed by Baker RDS (HOLD 80), but is assumed to be in the vicinity of the existing Hewett platform complex, in Block 48/29 of the UKCS Southern North Sea.

The design environmental criteria for the in-place condition are to be in accordance with Section 11.19, below. The 100-year return and 1-year return environmental conditions, from two orthogonal and one diagonal approach directions, will be considered. In keeping with current offshore design practice, deck elevations will be specified such that topsides structures and facilities are above the predicted 10,000-year return wave crest elevation.

9.2. Foundation Conditions

In the absence of site-specific information on the soil conditions, simplified foundation stiffness will be estimated based on previous experience and on the Hewett complex soil conditions.

9.3. Platform Drilling/Workover Requirements

The platform will be required to support drilling and well maintenance activities during its service life.

It is assumed that four wells (three injectors + one spare) will be required for the Base Case, and twelve wells will be required for the Extended Capacity Case (HOLD 44).


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It is assumed that all drilling and well maintenance activities will be carried out using a jack-up drilling unit operating in cantilever mode (HOLD 45), such that all drilling loads will be supported by the jack-up unit.

The spacing and arrangement of the platform wells will be provided by the client (HOLD 46) to suit the preferred class of jack-up units. Conductor sizes will also be provided by the client.

9.4. Design Life Requirements

It is assumed that the platform/facilities will have a design life of 40 years.


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10. Ecological Survey Data

10.1. Onshore Ecological Survey Data

HOLD 47

10.2. Offshore Ecological Survey Data

HOLD 48


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11. Subsea / Pipelines

11.1. Design Life

The pipeline system will have a design life of 40 years.

All equipment and items incorporated into the pipeline system will be of proven design for use in oil/gas transportation.

11.2. Materials

11.2.1. Line Pipe Material

Carbon steel linepipe is the economical choice for CO2 transport. Subject to any additional requirements such as those discussed in the Pipeline Material Selection, Corrosion Protection and Monitoring Philosophy with respect to low temperature capability/toughness and internal corrosion mitigation, ISO 3183 linepipe steel is expected to be generally suitable for construction of the onshore pipeline.

11.2.2. Corrosion Resistant Alloys

Although the main pipeline is expected to be fabricated from carbon steel, which is specifically designed to cope with short term low temperatures, there is likely to be a requirement for corrosion resistant alloys (CRA‟s) at particular locations in the system, for example valve materials, or certain pipework that is subject to particularly low temperatures. Selection of suitable CRA‟s shall take into consideration all relevant aspects of the service environment, including the pre-commissioning and commissioning phases.

11.2.3. External Corrosion Protection

The offshore pipeline shall be protected against external corrosion using a standard anti-corrosion coating and sacrificial bracelet anodes. Where the linepipe is to be subsequently concrete coated for hydrodynamic stability and/or protection, the anti-corrosion coating shall be compatible with the application of the concrete weight coating.

11.2.4. Concrete Weight Coating

The onshore section of the pipeline route may cross areas of ground which may be subject to periodic flooding and may require the installation of anti-buoyancy. This may be undertaken with the installation of concrete weight coating or other measures, which will be reviewed during the FEED design phase.

11.3. Pipeline Hydrotest Parameters

Mill hydrotest pressure for the linepipe shall be determined in accordance with ISO 3183.

System hydrotest strength and leak test pressures for the onshore and offshore pipeline shall be determined in accordance with the relevant pipeline design codes. It is anticipated that a golden weld i.e. 100% radiographically tested, will be performed at the landfall location (onshore / offshore tie-in weld) in lieu of an overall onshore/offshore leak test.

11.4. Onshore Pipeline Location Class

Location classes will be confirmed during FEED, after completion of the route surveys and assessment of the population densities. Preliminary location classes, in accordance with PD 8010-1, will be adopted to estimate pipeline wall thickness requirements and proximities


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based on conveyance of a Class E substance. As a starting point, the following general pipeline location class shall be as considered:

Class 2 (Areas with a population density greater than or equal to 2.5 persons per hectare) to be adopted for a distance of 800m (as a minimum) from High Water Tide Level towards offshore;

Class 1 (Areas with a population density less than 2.5 persons per hectare) for all other sections along the onshore pipeline route.

Cognisance shall also be taken of the recommendations of DNV-RP-J202, „Design and Operation of CO2 Pipelines‟.

11.5. Onshore Pipeline Routing (HOLD 49)

11.5.1. Description of Proposed Route

The pipeline starts within the confines of the proposed Kingsnorth Power Station. The proposed pipeline route heads in a northerly direction from the Power Station towards the landfall location and landfall valve in the vicinity of St. Mary‟s Marshes where it will cross the intertidal mud flats and continue eastwards down the Thames Estuary.

The landfall valve site shall include provision for connection and injection of dense phase CO2 flow sources being delivered into the pipeline system from other capture sources in the Thames basin. Such provision shall enable connections to be made without interruption to the flow from Kingsnorth to Hewett.

The proposed onshore route is outlined in Figure 11-1.


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Figure 11-1 Outline Onshore Pipeline Route

11.5.2. Routing Constraints (Onshore)

Routing constraints which will be considered during overall route selection for the onshore pipeline will include the following:

Proximity distances to inhabited areas to be maximised;

CO2 dispersion issues;

Ease of installation and construction of the pipeline - shortest route length to be maintained where possible;

Project stakeholder preferences, including Local Authority, Environment Agency, Natural England;

Landowner issues;

Environmental impact, including impact on ecology, archaeology and landscape to be minimised;

Impact on existing and on any proposed future infrastructure, including pipeline, cables and other utilities to be minimised;

Impact on any future developments e.g.in local plans, to be minimised;

Local community issues, particularly during construction, to be taken into consideration;

Interaction with any known areas of landfill or contaminated ground to be minimised.


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11.6. Offshore Pipeline Routing

11.6.1. General

The offshore section starts at the proposed landfall, and then runs east towards deeper water before deviating northwards towards Hewett.

An offshore route survey, will be performed at an early stage during FEED, and on completion, and on obtaining agreement with stakeholders, the route selection will be confirmed.

11.6.2. Routing Contraints (Offshore)

The following considerations and constraints shall be taken into consideration in defining the route of the offshore pipeline:

The shortest route length to be maintained where possible;

Pipelay will likely be initiated from the landfall to enable the laybarge to lay into deeper water. Laydown will likely be performed adjacent to the Hewett field WHP;

Bend radii of 3000m (HOLD 49) to be maintained at route deviations;

Straight route lengths of 500m (HOLD 50) to be maintained preceding and following any route deviations;

The pipeline to be routed in such a way that it maintains a minimum clearance of approximately 500m from wind farm structures, to allow for maintenance operations;

Routing to deeper water where possible, to minimise routing through the shallower water zones;

Clearances to be maintained to munitions dump sites;

Practice and exercise areas (PEXA) do not have to be avoided.

Clearances to be maintained to disposal dump sites;

Dredge sites to be avoided;

Pipeline, umbilical and cable crossings to be minimized;

Disturbance of fishing breeding grounds to be minimized ;

Areas of reef forming organisms to be avoided;

Shipping separation zones to be avoided;

Anchoring zones to be avoided ;

High intensity of shipping to be avoided ;

High intensity of fishing to be avoided;

Areas of mobile seabed to be avoided;

Seabed sand banks to be avoided;

Seabed sandwaves and megaripples to be avoided;

Ship wrecks to be avoided ;

Clearance of 500m to wells and installations to be maintained;

Clearance to drill rigs to be maintained subject to anchor patterns;

Consideration to be given to the routing of the pipeline past the major ports of Great Yarmouth and Lowestoft so as to minimise any disruption to marine activity during construction, and minimise risks to the pipeline throughout its operating life. Sectional isolation valves may be considered in order to mitigate risks arising from the possibility of damage at such locations.


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The outline offshore pipeline route is shown on Figure 11-2.

Figure 11-2 Outline Offshore Pipeline Outline Route

11.6.3. Additional Routing Constraints

There is a significant constraint just offshore from the Isle of Grain in the wrecked SS Richard Montgomery, a Second World War munitions ship left partly submerged on a shallow sandbar. The ship still contains significant quantities of explosives. The route shall be chosen so as to pass a safe distance from this constraint, but the precise distance will have to be verified during FEED.

The route also crosses busy shipping lanes. Further potential and actual obstacles are present including:

Wind farm concession areas – Round 1 and Round 2;

Dredging licence areas and dredging application areas;

Disposal sites;

UK mineral rights extent;

Existing cables and pipelines;


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Military practice exercise area (PEXA).

The number of pipeline and cables crossings should be minimised.

There is a large MOD practice area, which the most logical pipeline route crosses. This may be feasible, but more work would have to be done to investigate this.

The northern section of the pipeline route is known for its predominance of sandwaves and a highly mobile seabed. For a large diameter pipeline this implies seabed preparation by dredging and post-lay trenching of the pipeline.

11.7. Onshore Pipeline Installation and Construction

11.7.1. General

The proposed construction methodology to be fully developed during FEED and set out in a Construction Philosophy which shall comply with all relevant Health and Safety, and Environmental legislation. Construction techniques shall minimise the overall environmental impact of the onshore pipeline.

Consents will be required for certain construction activities e.g. planning permission from local planning authorities for any buildings, fences or bunds along the pipeline route.

An Environmental Impact Assessment (EIA) will be required, in accordance with European Directives.

The onshore pipeline will be buried along its entire length, with a minimum depth of cover of 1.1m, and with increased cover at crossings.

11.7.2. Landfall

The landfall area is a key aspect of the proposed pipeline route.

Typical landfall construction techniques are conventional open-cut with a cofferdam and pre-excavated trench, or HDD methods.

The final selection of the precise method of construction and sequence of activities to be followed during near shore/landfall construction will depend upon factors such as line diameter, water depth along the pipeline route, and environmental and other conditions at the landfall.

The scope of the work to be carried out during FEED for design of the landfall shall include:

Performing shore approach design for the pipeline up to landfall tie-in;

Determination of pipeline profile in the shore approach and intertidal zones;

Determination of governing minimum cover depth requirements;

Determination of pipeline weight coating requirements for nearshore and landfall zones;

CP (cathodic protection) requirements for nearshore and landfall areas;

Spoil and rockdump volumes determination;

Production of Shore Approach and Landfall Design Report;

Preparation of General Arrangement drawings of the Shore Approach and Landfall.


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11.8. Offshore Pipeline Installation and Construction

11.8.1. General

The proposed construction methodology shall comply with all relevant Health and Safety, and Environmental legislation. Pipeline routes and construction techniques shall also be developed during FEED to minimise the overall environmental impact of the offshore pipeline, for instance by avoiding environmentally sensitive areas wherever possible.

The pipeline design work to be performed during FEED shall include consideration of the following:

Stability design (concrete weight coating limits);

Pipeline installation assessment and analyses;

Trenching design and burial requirements (if any);

Shore approach and landfall design;

Pre-commissioning and commissioning update.

11.8.2. Trenching and Burial

Trenching and burial of the offshore pipeline will be minimised wherever possible, subject to practical levels of concrete weight coating requirements and pipeline protection from third-party interaction. The level and limit of pre-trenching/burial that will be required in the shore approach and /landfall regions shall be defined in both the on-bottom stability and routing reports.

Some areas of the seabed, e.g. sand waves may require pre-sweeping prior to pipelay to prevent over-stressing of the pipeline. Sweeping may be subject to environmental constraints.

11.8.3. Crossings and Third Party Ownership Considerations

All pipelines and cables or other items of infrastructure on the proposed offshore pipeline route shall be identified and 3

rd party owners confirmed. The locations of these items shall be

confirmed by the offshore route survey. The FEED work shall include preliminary designs for construction of the required crossings.

It is critical that all consents, including those for the offshore pipeline and the storage of CO2, are obtained in a timely manner, as failure to achieve this will have an impact on the project‟s programme to deliver the project on schedule.

11.9. Offshore Pipeline Protection Design

A detailed pipeline protection system design shall be performed during FEED.

The protection system design shall include consideration of the following:

Dropped objects;

Vessel anchoring (snagging and cable dragging);

Fishing activities (trawlboard and beam impact and pullover).

A dropped object study shall be performed during FEED to determine the risk of dropped objects from activities at the WHP.


Revision: 04






Southern North Sea shipping activities are very dense especially within the vicinity of Thames Estuary. An assessment of shipping within the region of interest for this project shall be contained in the routing report.

A low to medium fishing intensity, with both the Beam and Otter trawl efforts, exists along most of the proposed pipeline route. Fishing interaction studies shall be carried out during FEED to evaluate risks from fishing and determine appropriate protection measures for the pipeline.

11.10. Connections Design

Pipeline connections shall be weld-neck flanges in accordance with ASME B16.47, as ASME B16.5 is not applicable to flanges above 24-inch. Offshore pipeline spoolpiece flanges shall include swivel ring type to ease bolting. The number of flanged connections will be minimized wherever possible. Consideration may be given to hyperbaric welded tie-ins.

11.11. Risk Assessment

A hazard identification and risk evaluation will be undertaken to provide input to a major accident prevention document (MAPD) as part of the Pipeline Safety Regulations (PSR) 1996 requirements (Regulation 23). This is based on defining the CO2 pipeline as conveying a „dangerous‟ fluid in accordance with Regulation 18 and Schedule 2 of PSR 1996.

11.12. Pigging

The pipeline system will be equipped with a pig launcher at the Kingsnorth pipeline inlet and a receiver at the offshore platform. These vessels will be specified to accommodate intelligent pipeline inspection devices (IID) that will need to be designed specifically for use in the flowing CO2 pipeline. The devices will be designed to seek any evidence of localised or general internal/external corrosion or damage to the pipe wall.

The geometry of the pipeline system shall be compatible with running of IID‟s, with bend radii of a minimum of 5 x outside diameter included in the tie-in spoolpieces and pipework. The pipeline shall have a constant ID to allow smooth transit of pigs. At branched connections, guide bars shall be incorporated where the branched connection diameters exceeds 25% of the pipeline diameter to ensure effective and safe pigging.

11.13. Future Expansion of System

Consideration shall be given during FEED to the future expansion of the CCS system i.e. preparation for feeding in of the Thames cluster of power stations to the pipeline. This shall include consideration of tie-in locations and layouts, flow assurance considerations arising from mixing of the fluids, and pigging requirements for the system.

11.14. Pipeline Safety and Control Systems

Specific concepts and strategies for providing the pipeline Control and Safety Systems will be developed through FEED by consultation across design contributors/disciplines and by enquiry with potential specialist suppliers.

System design will take into account HAZOP and HAZID studies, different available control system types (SCADA, DCS etc) and technologies such as fieldbus, profibus etc, as well as focus on the environment and the locations where the parts of the control system could be installed. These will also be in compliance with internationally recognised standards such as “IEC 61511 – Functional Safety, Safety Instrumented Systems for the process industry” and


Revision: 04






“IEC 61508 - Functional safety of electrical/electronic/programmable electronic safety-related systems”.

Monitoring by the SCADA system will include the following:

Pressure switches;

Flow switches;

Temperature switches;

Position switches.

Safety management systems that will be considered include:

Cathodic protection monitoring;

Internal Inspection devices (intelligent pigs);

Corrosion monitoring;

Automatic ESD systems (pipeline shutdown to safe condition may include some valves that move to a fail-safe condition of open rather than closed).

Leak detection e.g. Pipeline Management System incorporating modelling of pipeline operation, monitoring and control elements;

Sacrificial anode cathodic protection monitoring.

11.15. Condition Monitoring

The main focus of monitoring will be to identify conditions that could give rise to internal and external corrosion and to confirm that the operating conditions are being maintained in a way that corrosion is being successfully inhibited.

The pipeline will also be monitored for leaks and a pipeline monitoring system should be considered so that the operating conditions can be compared continuously to expected behaviour (i.e. both simulations and historical). Particular care will be required when the system is taken from gas phase to dense phase operation.

The pipeline will also be monitored for leaks (acoustic monitoring). The onshore section of the pipeline will be protected from external corrosion in its buried location by appropriate coatings and/or wrappings with holiday detection being used to confirm the coating integrity during the pipe laying process. A cathodic protection (impressed current) system will be used to inhibit external corrosion over the life of the onshore pipeline.

11.16. Onshore Pipeline Sectional Valves

Section isolating valves shall be installed at the beginning and end of the onshore pipeline, with consideration to further isolating valves at a spacing along the pipeline appropriate to the substance being conveyed to limit the extent of a possible leak. The location and spacing of valves shall be justified to the statutory authorities as part of the safety evaluation of the pipeline and shall be considered as part of an overall assessment of risk mitigation measures for the onshore pipeline.

The spacing of sectional isolating valves should reflect the conclusions of any safety evaluation prepared for the pipeline, and should preferably be installed below ground. In the locating of section isolating valves, account should be taken of topography, ease of access for operation and maintenance, protection from vandalism and proximity to normally occupied buildings.


Revision: 04






11.17. Offshore Pipeline SSIVs

Any requirement for the provision of sectional barrier valves and SSIV‟s for the offshore pipeline shall be identified and discussed with the HSE during the course of the FEED study.


Revision: 04






11.18. Onshore Pipeline Design Data

11.18.1. Design Code

The onshore pipeline shall be designed in accordance with the requirements of PD 8010-1.

ASME B31.4 shall be used to supplement PD 8010-1 for areas not specifically addressed by the code. Cognisance shall also be taken of the recommendations of DNV-RP-J202.

11.18.2. Design and Operating Conditions

The pressure and temperature conditions which shall apply are summarised in Table 11.18.1-a.

Description Unit Value

Design Pressure barg 150

Maximum Allowable Operating Pressure barg HOLD 53

Maximum Design Temperature Deg C 70

Maximum Operating Temperature Deg C 40 (HOLD 55)

Minimum Design Temperature Deg C -85 (HOLD 56)

Table 11.18.1-a Pipeline Operating Parameters

The installation temperature for the pipelines is assumed to be 11 deg C, which is equivalent to the average minimum temperature (July) for south-east England.

11.18.3. Fluid Classification

For design purposes the dense phase CO2 anticipated to be produced from the Kingsnorth power station will be classified as Category E substance under PD 8010-1 i.e. toxic fluids that are gases at ambient temperature and atmospheric pressure conditions and are conveyed as gases and/or liquids.

This classification and treatment of CO2 is subject to confirmation by 3rd parties.

11.18.4. Mechanical Design

11.18.4.1. Design Factors

Preliminary design hoop stress factors for the onshore pipeline section are shown in Table 11.18.2-a:

Location Design Factor

fd Notes

Class 1 0.72 1

Class 2 (including AGI) 0.3 1

Table 11.18.2-a Onshore Pipeline Design Factors

Note 1: Design factors to be subject to safety evaluation

11.18.4.2. Pipe Diameter

The onshore section of the CO2 pipeline shall be designed to match the offshore pipeline requirements.


Revision: 04






The offshore pipeline shall be 36-inch NPS 914mm OD. The pipeline shall have a constant ID to allow smooth transit of pigs.

11.18.5. Minimum Wall Thickness

In accordance with standard industry practice, the diameter to wall thickness ratio for the onshore pipeline should not exceed 96 unless it can be demonstrated that higher values are not detrimental to the construction and in-situ integrity of the pipeline.

11.18.6. Materials

11.18.6.1. Linepipe Material

Mechanical calculations shall be based on linepipe of type SAWL in accordance with the requirements of ISO 3183. A summary of the material properties are presented in Table 11.18.3-a.

Parameter Units Value Notes

Material - SAWL, ISO 3183 L450M 2

SMYS MPa 450 1,2

SMTS MPa 535 1,2

Steel Density kg/cu.m 7850

Coefficient of Thermal Expansion

m/m/degC 11.7x10-6

Youngs Modulus MPa 207000

Thermal Conductivity W/mK 45

Heat Capacity J/kg.degC 500

Table 11.18.3-a Linepipe Material Properties

Notes: 1: SMYS and SMTS values to be de-rated appropriately for the design temperatures in

accordance with the requirements of DNV OS-F101. 2: Higher strength pipe (ISO 3183 L485M) shall also be considered.

11.18.7. Corrosion Allowance

A preliminary corrosion allowance of 1.5mm shall be assumed.

11.18.8. External Corrosion Protection

The buried sections of the onshore pipeline shall be protected against external corrosion using an appropriate anti-corrosion coating.

11.18.9. Onshore Pipeline Routing

11.18.9.1. Co-ordinate System

Onshore data shall be in accordance with OSGB36, the details of which are given below:

Spheroid Airy 1830

Semi-Major axis a 6377563.396m


Revision: 04






Semi-Minor axis b 6356256.910m

First Eccentricity Sq e2 0.0066705397616

Inverse Flattening 1/f 299.3249646

Datum OSGB36 National Grid

Central Meridian CM 2°W UTM Zone 30N, 0°W - 6°W

Latitude of Origin 49°

False Easting 400000m

False Northing -100000m

Scale Factor on CM 0.9996012717

11.18.9.2. Interfaces

The locations for the landfall valve, the exit from Kingsnorth power station, and Kingsnorth pipeline ESD valve are listed in Table 11.18.4-a. The co-ordinates stated are approximate and shall be updated during the design.

Location Easting Northing

Landfall Valve 581 678 177 889

Kingsnorth Power Station boundary fence 580 473 172 458

Kingsnorth pipeline ESD valve HOLD 59 HOLD 60

Table 11.18.4-a Interface Co-ordinates

11.18.9.3. Pipeline Crossings

A summary of the crossings, out with the Kingsnorth site boundary, which have been identified using satellite imagery are presented in Table 11.18.5-a. This list is preliminary and should be reviewed following the field survey.

Crossing Type Quantity

Motorway 0

Major Road 1

Minor Road 5

Track 7

Major/Minor River 0

Ditch 16

Railway 1

Third Party Service HOLD 61

Pipeline HOLD 62

Table 11.18.5-a List of Crossings

11.18.9.4. Burial Depth

The pipeline shall be buried along its entire length to a minimum cover of 1.1m. At crossings, the burial depth shall be increased in accordance with the requirements of PD 8010-1 or as required by crossing Owner.


Revision: 04






11.18.9.5. Pipeline Separation

The minimum horizontal separation distance between the pipeline and any existing buried pipelines shall be 5m.

11.18.9.6. Weight Coating

At water courses and areas subject to high water table, the pipeline shall be restrained against float out by the use of cohesive backfill, set-on weights, concrete weight coating or a combination thereof. The minimum thickness of concrete weight coating shall be 25mm.

The concrete weight coating properties to be adopted are shown in Table 11.18.6-a.

Type Dry Density

kg/cu.m

Medium Density 3050

High Densiy 3450

Table 11.18.6-a Concrete Weight Coating Properties

11.18.10. Environmental Data

11.18.10.1. Ground Water Properties

HOLD

11.18.10.2. Soil Conditions

HOLD

11.19. Offshore Pipeline Design Data

11.19.1. Process Data

11.19.1.1. Design and Operating Conditions

Offshore pipeline operating parameters are summarised in Table 11.19.1-a.

Description Unit Value

Design Pressure barg 150 (2)

Maximum Allowable Operating Pressure barg HOLD 66

Maximum Design Temperature ºC 70/50

Minimum Design Temperature ºC -85 (HOLD 68)

Table 11.19.1-a Offshore Pipeline Operating Parameters

Notes:

1. To be finalised during FEED.

2. Calculations also to be carried out for 120 and 200barg.

11.19.1.2. Arrival Conditions at Hewett

HOLD 70.


Revision: 04






11.19.2. Environmental Data (Preliminary – HOLD 71)

11.19.2.1. General

The data presented in this Section was obtained from documentation produced for an earlier phase of the project. This data is generic in nature and is not known to be specific to the Kingsnorth pipeline route or landfall location. The following project-specific studies and surveys (as applicable) should be commissioned and carried out during early FEED in order to provide the required specific data:

Metocean Study

Fishing and Shipping Study

Pipeline Bathymetric Survey

Pipeline Route Geophysical Survey

Pipeline Route Geotechnical Survey

Environmental Impact Assessment

Morphology Study (to determine extent of coastal and channel erosion and extent of scour).

11.19.2.2. Seawater Temperature

The maximum, average and minimum seawater temperature profiles (in ºC) are shown in Tables 11.19.2-a to c.

Depth (m)

Jan Feb Mar Apr May Jun Jul Aug Sept Oct Nov Dec year

0 10.5 10.8 10.8 13.6 15.5 18.5 21.0 20.5 19.3 16.7 13.9 12.5 21.0

5 8.0 8.0 8.0 8.1 10.0 15.1 17.4 15.7 15.9 14.1 13.5 10.8 17.4

10 8.1 8.0 7.2 7.5 10.0 14.4 16.2 15.8 17.0 14.3 13.5 9.4 17.0

15 8.1 8.0 7.1 6.3 9.9 15.0 16.1 15.8 16.0 13.4 13.5 9.4 16.1

20 8.0 8.0 7.2 8.4 9.2 14.4 16.0 16.0 17.0 14.3 13.5 9.4 17.0

25 8.0 8.0 7.2 7.1 8.9 13.5 15.5 15.6 17.0 14.2 13.5 - 17.0

30 8.0 8.1 7.3 8.3 8.9 12.8 14.9 15.0 15.6 14.3 13.5 9.5 15.6

40 8.0 8.1 7.3 8.1 10.5 12.2 14.2 14.8 17.0 14.9 13.5 - 17.0

Table 11.19.2-a Maximum Seawater Temperature

Depth (m)

Jan Feb Mar Apr May Jun Jul Aug Sept Oct Nov Dec Year

0 6.0 5.3 5.7 7.6 10.4 13.6 15.8 16.5 15.5 13.1 10.0 7.6 10.6

5 6.8 5.8 6.7 7.6 8.6 13.0 14.9 15.1 15.1 13.9 11.5 10.5 10.5

10 6.5 5.8 5.8 6.9 8.2 12.1 14.4 14.9 14.7 14.0 11.5 9.4 10.4

15 6.8 6.1 5.6 6.2 8.1 12.0 14.0 14.7 14.6 13.4 11.6 9.4 10.3

20 6.8 6.2 5.6 7.0 8.0 11.6 13.9 14.6 14.7 14.0 11.3 9.4 10.3

25 7.1 6.8 5.6 6.8 7.9 11.7 13.7 14.4 14.6 14.0 11.3 - 10.3

30 7.4 7.1 5.9 7.4 7.9 11.2 13.3 14.2 14.5 14.1 11.5 9.5 10.3

40 7.0 7.3 6.3 7.4 7.8 10.8 12.9 13.9 14.5 14.2 11.6 - 10.3

Table 11.19.2-b Average Seawater Temperature


Revision: 04






Depth (m)

Jan Feb Mar Apr May Jun Jul Aug Sept Oct Nov Dec Year

0 1.0 0.5 0.5 4.0 6.9 10.0 11.9 11.5 11.8 9.1 3.3 2.5 0.5

5 5.5 3.1 4.3 6.3 7.7 11.9 11.9 14.3 14.2 13.9 10.0 9.9 3.1

10 4.2 3.6 2.7 6.2 7.1 10.1 11.9 13.6 14.2 13.6 9.9 9.4 2.7

15 4.8 3.8 4.3 6.1 7.3 11.3 11.8 13.9 14.2 13.4 8.8 9.4 3.8

20 4.3 3.4 4.4 5.7 7.2 10.1 11.6 13.0 14.2 13.6 8.5 9.4 3.4

25 5.0 3.5 2.7 6.0 7.2 10.2 11.5 13.5 14.2 13.6 9.3 - 2.7

30 5.9 4.5 4.6 6.8 7.2 9.8 11.5 13.5 14.2 14.0 9.6 9.5 4.5

40 6.4 3.5 4.9 6.3 7.2 9.5 11.4 12.9 14.2 13.9 10.1 - 3.5

Table 11.19.2-c Minimum Seawater TemperatureWater Depths

Water depths vary between 0m at the landfall to over 45m HOLD 75. Detailed bathymetric profiles will be produced by the offshore survey.

11.19.2.3. Current Profile

Preliminary current data are shown in the following Tables.

Total current (directions TOWARDS) – 100 yr profiles

m/s N NE E SE S SW W NW Omni-dir

Surface (100%)

60%

50%

1.35

1.35

1.32

0.94

0.94

0.92

1.02

1.02

0.99

1.85

1.85

1.80

1.70

1.70

1.66

0.91

0.91

0.88

0.80

0.80

0.78

1.50

1.50

1.46

1.85

1.85

1.80

45%

40%

35%

1.28

1.22

1.16

0.89

0.86

0.81

0.96

0.92

0.87

1.75

1.68

1.58

1.61

1.54

1.46

0.86

0.82

0.78

0.75

0.72

0.68

1.42

1.36

1.28

1.75

1.68

1.58

30%

1m asb (22.7%)

0.5m asb

(11.4%)

1.05

0.97

0.88

0.73

0.68

0.61

0.79

0.73

0.66

1.43

1.33

1.20

1.32

1.23

1.11

0.70

0.65

0.59

0.62

0.57

0.52

1.16

1.08

0.97

1.43

1.33

1.20

Table 11.19.2-d Current Data-100 Year Return Period (Offshore Section)



Surface (100%)

60%

50%

1.26

1.26

1.23

0.88

0.88

0.86

0.95

0.95

0.92

1.72

1.72

1.68

1.59

1.59

1.55

0.84

0.84

0.82

0.74

0.74

0.72

1.40

1.40

1.36

1.72

1.72

1.68


Revision: 04






45%

40%

35%

1.19

1.14

1.08

0.83

0.80

0.75

0.90

0.86

0.81

1.63

1.56

1.47

1.50

1.44

1.36

0.80

0.77

0.72

0.70

0.67

0.63

1.32

1.27

1.19

1.63

1.56

1.47

30%

1m asb (22.7%)

0.5m asb

(11.4%)

0.97

0.91

0.82

0.68

0.63

0.57

0.73

0.68

0.62

1.34

1.24

1.12

1.23

1.14

1.03

0.65

0.61

0.55

0.57

0.53

0.48

1.08

1.01

0.91

1.34

1.24

1.12

Table 11.19.2-e Current Data-10 Year Return Period (Offshore Section)



Surface (100%)

60%

50%

1.17

1.17

1.14

0.81

0.81

0.79

0.88

0.88

0.86

1.6

1.6

1.56

1.47

1.47

1.43

0.78

0.78

0.78

0.69

0.69

0.67

1.29

1.29

1.26

1.6

1.6

1.56

45%

40%

35%

1.10

1.08

1.00

0.77

0.74

0.70

0.83

0.80

0.75

1.51

1.45

1.37

1.39

1.33

1.26

0.74

0.71

0.67

0.65

0.62

0.59

1.22

1.17

1.11

1.51

1.45

1.37

30%

1m asb (22.7%)

0.5m asb

(11.4%)

0.90

0.84

0.76

0.63

0.59

0.53

0.68

0.63

0.57

1.24

1.15

1.04

1.14

1.06

0.95

0.61

0.56

0.51

0.53

0.49

0.45

1.00

0.93

0.84

1.24

1.15

1.04

Table 11.19.2-f Current Data-1 Year Return Period (Offshore Section)



Surface (100%)

60%

50%

0.57

0.57

0.55

0.43

0.43

0.42

0.43

0.43

0.42

1.26

1.26

1.23

0.66

0.66

0.64

0.43

0.43

0.42

0.43

0.43

0.42

0.95

0.95

0.92

1.26

1.26

1.23


Revision: 04






45%

40%

35%

0.54

0.54

0.53

0.41

0.40

0.40

0.41

0.40

0.40

1.21

1.19

1.17

0.63

0.62

0.61

0.41

0.40

0.40

0.41

0.40

0.40

0.91

0.89

0.88

1.21

1.19

1.17

30%

1m asb (22.7%)

0.5m asb

(11.4%)

0.51

0.49

0.45

0.39

0.37

0.34

0.39

0.37

0.34

1.14

1.10

0.99

0.59

0.57

0.52

0.39

0.37

0.34

0.39

0.37

0.34

0.88

0.82

0.75

1.14

1.10

0.99

Table 11.19.2-g Current Data-100 Year Return Period (Shore Approach)



Surface (100%)

60%

50%

0.53

0.53

0.52

0.40

0.40

0.39

0.40

0.40

0.39

1.17

1.17

1.14

0.61

0.61

0.60

0.40

0.40

0.39

0.40

0.40

0.39

0.88

0.88

0.86

1.17

1.17

1.14

45%

40%

35%

0.51

0.50

0.49

0.38

0.38

0.37

0.38

0.38

0.37

1.13

1.11

1.09

0.59

0.58

0.57

0.38

0.38

0.37

0.38

0.38

0.37

0.85

0.83

0.82

1.13

1.11

1.09

30%

1m asb (22.7%)

0.5m asb

(11.4%)

0.48

0.46

0.42

0.36

0.35

0.31

0.36

0.35

0.31

1.06

1.02

0.93

0.55

0.53

0.48

0.36

0.35

0.31

0.36

0.35

0.31

0.80

0.77

0.69

1.06

1.02

0.93

Table 11.19.2-h Current Data-10 Year Return Period (Shore Approach)




Revision: 04






Surface (100%)

60%

50%

0.49

0.49

0.48

0.37

0.37

0.36

0.37

0.37

0.36

1.09

1.09

1.06

0.57

0.57

0.55

0.37

0.37

0.36

0.37

0.37

0.36

0.82

0.82

0.80

1.09

1.09

1.06

45%

40%

35%

0.47

0.46

0.45

0.36

0.35

0.34

0.36

0.35

0.34

1.04

1.03

1.01

0.54

0.53

0.52

0.36

0.35

0.34

0.36

0.35

0.34

0.78

0.77

0.76

1.04

1.03

1.01

30%

1m asb (22.7%)

0.5m asb

(11.4%)

0.44

0.43

0.39

0.34

0.32

0.29

0.34

0.32

0.29

0.99

0.95

0.86

0.51

0.49

0.45

0.34

0.32

0.29

0.34

0.32

0.29

0.74

0.71

0.64

0.99

0.95

0.86

Table 11.19.2-i Current Data-1 Year Return Period (Shore Approach)


Revision: 04






11.19.2.4. Tide Levels

Preliminary tide and extreme water levels referred to datum of surroundings are shown in the following Tables.

LAT (m) MSL (m)

100 yr total

50 yr total

13.6

13.2

11.9

11.5

100 yr +ve swl

50 yr +ve swl

10 yr +ve swl

1 yr +ve swl

5.0

4.9

4.8

4.5

3.3

3.2

3.0

2.8

HAT

MHWS

MHWN

MSL

MLWN

MLWS

LAT

3.4

3.1

2.4

1.8

1.1

0.3

0.0

1.6

1.3

0.7

0.0

-0.7

-1.4

-1.8

1 yr +ve swl

10 yr +ve swl

50 yr +ve swl

100 yr +ve swl

-1.1

-1.3

-1.5

-1.6

-2.8

-3.1

-3.3

-3.3

Tide and Extreme Still Water Levels (Offshore Section)

Years Crest

100 8.6 m

50 8.3 m

Wave Crest (Offshore Section)

Years Surge

100 2.4 m

50 2.3 m

10 2.0 m

1 1.6 m

Surge Levels (Offshore Section)


Revision: 04






LAT (m) MSL (m)

100 yr total

50 yr total

10.0

9.9

7.4

7.3

100 yr +ve swl

50 yr +ve swl

10 yr +ve swl

1 yr +ve swl

6.5

6.4

6.2

6.0

3.9

3.8

3.6

3.4

HAT

MHWS

MHWN

MSL

MLWN

MLWS

LAT

5.0

4.6

3.6

2.6

1.6

0.5

0.0

2.4

2.0

1.0

0.0

-1.0

-2.1

-2.6

1 yr +ve swl

10 yr +ve swl

50 yr +ve swl

100 yr +ve swl

-0.8

-1.1

-1.3

-1.4

-3.4

-3.7

-3.9

-4.0

Tide and Extreme Still Water Levels (Shore Approach)

Years Crest

100 3.5 m

50 3.5 m

Wave Crest (Shore Approach)

Years Surge

100 2.5 m

50 2.4 m

10 2.1 m

1 1.7 m

Surge Levels (Shore Approach)


Revision: 04






11.19.2.5. Wave Data

Preliminary wave data are shown in the following Tables.

100-Year RP Stillwater depth: 34m

Parameter

Direction (from) Omni-dir 000° 045° 090° 135° 180° 225° 270° 315°

Hs (m)

Tz (s)

Tp (s)

8.3

9.8

12.4

8.0

9.6

12.2

6.3

8.5

10.8

5.0

7.6

9.6

6.8

8.9

11.2

6.4

8.6

10.9

7.5

9.3

11.8

8.0

9.6

12.2

8.3

9.8

12.4

Hmax (m)

Tmax (s)-lower

Tmax (s)-Upper

15.5

10.3

13.7

15.0

10.1

13.4

11.9

8.9

11.9

9.5

8.0

10.6

12.8

9.3

12.4

12.1

9.0

12.0

14.1

9.8

13.0

15.0

10.1

13.4

15.5

10.3

13.7

Crest height (m)

Above SWL

10.0 9.5 7.2 5.6 7.8 7.3 8.8 9.5 10.0

Wave Data-100 Year Return Period (Offshore Section)


Parameter


Hs (m)

Tz (s)

Tp (s)

7.3

9.2

11.7

7.0

9.0

11.4

5.5

8.0

10.2

4.4

7.1

9.0

6.0

8.3

10.5

5.6

8.1

10.2

6.6

8.7

11.1

7.0

9.0

11.4

7.3

9.2

11.7

Hmax (m)

Tmax (s)-lower

Tmax (s)-Upper

13.7

9.6

12.8

13.3

9.5

12.6

10.5

8.4

11.2

8.4

7.5

10.0

11.3

8.7

11.6

10.7

8.5

11.3

12.5

9.2

12.2

13.3

9.5

12.6

13.7

9.6

12.8

Crest height (m)

Above SWL

8.5 8.2 6.2 4.9 6.8 6.3 7.6 8.2 8.5



Revision: 04







Parameter


Hs (m)

Tz (s)

Tp (s)

6.0

8.3

10.5

5.8

8.1

10.3

4.5

7.2

9.2

3.6

6.4

8.2

4.9

7.5

9.5

4.6

7.3

9.3

5.4

7.9

10.0

5.8

8.1

10.3

6.0

8.3

10.5

Hmax (m)

Tmax (s)-lower

Tmax (s)-Upper

11.3

8.7

11.6

10.9

8.6

11.4

8.7

7.6

10.1

6.9

6.8

9.0

9.3

7.9

10.5

8.8

7.7

10.2

10.3

8.3

11.0

10.9

8.6

11.4

11.3

8.7

11.6

Crest height (m)

Above SWL

6.8 6.5 5.1 4.1 5.5 5.2 6.1 6.5 6.8



Parameter


Hs (m)

Tz (s)

Tp (s)

2.1

4.9

6.2

2.1

4.9

6.2

2.1

4.9

6.2

2.1

4.9

6.2

1.8

4.6

5.8

1.2

3.7

4.7

1.8

4.6

5.8

2.1

4.9

6.2

2.1

4.9

6.2

Hmax (m)

Tmax (s)-lower

Tmax (s)-Upper

3.4

5.2

6.9

3.4

5.2

6.9

3.4

5.2

6.9

3.4

5.2

6.9

3.4

4.8

6.4

2.4

3.9

5.2

3.4

4.8

6.4

3.4

5.2

6.9

3.4

5.2

6.9

Crest height (m)

Above SWL

2.9 2.9 2.9 2.9 2.7 1.6 2.7 2.9 2.9

Wave Data-100 Year Return Period (Shore Approach)


Revision: 04







Parameter


Hs (m) Tz (s) Tp (s)

2.0 4.8 6.1

2.0 4.8 6.1

2.0 4.8 6.1

2.0 4.8 6.1

1.7 4.4 5.6

1.1 3.6 4.6

1.7 4.4 5.6

2.0 4.8 6.1

2.0 4.8 6.1

Hmax (m) Tmax (s)-

lower Tmax (s)-

Upper

3.3 5.0

6.7

3.3 5.0

6.7

3.3 5.0

6.7

3.3 5.0

6.7

3.3 4.7

6.2

2.3 3.8

5.1

3.3 4.7

6.2

3.3 5.0

6.7

3.3 5.0

6.7

Crest height (m)

Above SWL 2.8 2.8 2.8 2.8 2.6 1.5 2.6 2.8 2.8

North Sea Wave Data-10 Year Return Period (Shore Approach)


Parameter


Hs (m) Tz (s) Tp (s)

1.9 4.7 5.9

1.9 4.7 5.9

1.9 4.7 5.9

1.9 4.7 5.9

1.6 4.3 5.5

1.1 3.5 4.5

1.6 4.3 5.5

1.9 4.7 5.9

1.9 4.7 5.9

Hmax (m) Tmax (s)-

lower Tmax (s)-

Upper

3.1 4.9

6.5

3.1 4.9

6.5

3.1 4.9

6.5

3.1 4.9

6.5

3.1 4.5

6.0

2.2 3.7

4.9

3.1 4.5

6.0

3.1 4.9

6.5

3.1 4.9

6.5

Crest height (m)

Above SWL 2.6 2.6 2.6 2.6 2.4 1.4 2.4 2.6 2.6

North Sea Wave Data-1 Year Return Period (Shore Approach)


Revision: 04






11.19.2.6. Marine Growth

HOLD 72.

11.19.2.7. Soil Conditions

HOLD 73.

Preliminary lateral and axial friction coefficients for design are obtained from BS PD 8010-2 and given in the following Tables. Detailed information on soil conditions will be provided by the offshore survey.

Seabed Type Lateral Friction Axial Friction

Min Max Min Max

Non-Cohesive (e.g. Sand) 0.50 0.90 0.55 1.2

Cohesive (e.g. Clay, Silt) 0.30 0.75 0.3 1.00

Soil Coefficient of Friction

Soil Type Conductivity (W/mK)

Dry Soil (onshore) 0.87

Wet Soil (offshore) 2.6

Soil Conductivity

11.19.2.8. Landfall Data

HOLD 74.

11.19.2.9. Pipeline Details

The pipeline size adopted from the conceptual phase is 36-inch NPS (914mm OD) and the wall thickness is to be calculated giving due consideration to operating parameters and design codes. The pipeline shall have a constant ID to allow smooth transit of pigs.

Service Outer Diameter

Production 36-inch (914 mm)

Pipeline Size

11.19.2.10. Minimum Wall Thickness

For offshore pipe with Safety Class High and Location Class 2, Table 5-3 of DNV OS-F101 recommends a minimum wall thickness of 12mm for all pipe 8” and above based on failure statistics of impact loads.


Revision: 04






11.19.2.11. Materials for Construction

Parameter Unit Value

Material - SAWL, ISO 3183 L450MO

(DNV SAWL 450 S) (2)

SMYS (1)

MPa 450

SMTS (1)

MPa 535

Steel Density kg/m3 7850

Coefficient of Thermal Expansion

m/m/oC 11.7x10-6

Young‟s Modulus MPa 207000

Thermal Conductivity W/mK 45

Heat Capacity J/kgoC 500

Mill Tolerance mm As per ISO 3183, Table J.4

Maximum OOR tolerance mm 10.7

Notes:

1. SMYS and SMTS to be derated appropriately for the design temperatures.

2. Higher strength material (485S) may also be considered.

11.19.2.12. Corrosion Allowance

A preliminary corrosion allowance of 1.5mm shall be assumed.

11.19.2.13. External Corrosion Protection

It is assumed that the offshore pipeline is to be protected against external corrosion using an appropriate anti-corrosion coating. Typical properties for 3-layer PE are presented in the table below. This assumption will be validated during FEED. The anti-corrosion coating will include a roughened outer layer to assist in the application of the concrete weight coating.

Protection Coating

Nominal Thickness

mm

Assumed Density kg/m3

Thermal Conductivity

W/mK

Heat Capacity J/kgK

3-Layer Polyethylene

3.2 950 0.35 1800

Pipeline Anti-Corrosion Coating Properties


Revision: 04






11.19.2.14. Pipeline Weight Coating

The pipeline is to be stabilized on the seabed using a concrete weight coating. The concrete weight coating properties are summarized in the following Table. The specific concrete strength to be adopted will be specified in the on-bottom stability report.

Concrete Type Dry Density

kg/m3

Normal Strength Concrete 2400

High Strength Concrete 3040

Concrete Weight Coating Properties

11.19.2.15. Pipeline Protection Requirements

Preliminary assessments will be involved at this conceptual stage while a detailed pipeline protection system design shall be performed during FEED. The design shall include consideration of the following:

Dropped Objects (from WHP);

Vessel Anchoring (snagging and cable dragging);

Fishing activities (trawlboard and beam impact and pullover).

11.19.2.16. Interfaces

The offshore pipeline extends from the landfall to the Hewett platform. The section of pipe from the landfall to the landfall valve shall fulfil the requirements of both the onshore pipeline code and the recommendations of DNV-OS-F101 Appendix F.

11.19.3. Third-Party Considerations

11.19.3.1. Third-Party Tie-ins

To be established during the conceptual design phase and detailed during FEED.

11.19.3.2. Fishing Intensity

A low to medium fishing intensity, with both Beam and Otter trawl efforts exists along most of the proposed pipeline route. These will be illustrated and discussed in the routing report.

11.19.3.3. Shipping Intensity

The Southern North Sea shipping activities are very dense especially within the vicinity of Thames Estuary. An assessment of shipping within the region of interest for this project will be contained in the routing report.

11.19.3.4. Crossings and 3rd Party Ownership Considerations

A list of crossings along the onshore and offshore sections of the pipeline route will be contained in the onshore and offshore routing reports as well as the identified 3rd party ownership data.


Revision: 04






12. References

S1. Pipeline Routing Study for Transport of CO2 by Pipeline From Kingsnorth Power Station to Hewett Gas Field - CO2 Transportation Document; JD; Penspen, 80011-RPT-EN-001, Rev 0, April 2008

S2. Kingsnorth CO2 Pipeline Study Offshore Pipeline Routing Option Report - Kingsnorth to Hewett Field; LA; Penspen, 80011-RPT-PL- 001, Rev 0, April 2008

S3. Kingsnorth Carbon dioxide disposal; JH; Energy & Power Consultants, 0448-GR-001 Rev. 5, March 2008

S4. Email Communication “FW: CO2 volumes - average and peak for 50MW, 300MW and 1600MW” from E.ON to Genesis, 22/10/08

S5. Email Communication “Scope of Work”, from E.ON Partners to Genesis, 22/10/08, \Hewett_CO2_RPS_LB_JME_Ver2_10102008.xls

S6. CO2 Storage Pipeline Concept Selection Engineering Study SOW Rev B; .; E.ON / Ruhrgas, Rev. B, May 2008

S7. International Thermodynamic Tables of the Fluid State, Carbon Dioxide; Angus, S., Armstrong, B., de Reuck, K.M.; Vol.3, Pergamon Press, 1976

S8. Email “RE: CO2 Project Data”, from E.ON Partners to Genesis, 18/11/08.

S9. Hewett Sequestration Study – Scope of Work, E.ON, Rev. 0, March 2006

S10. Hewett CO2 Flow Assurance Technical Note, E.ON doc number CCS-GEN-DES-STU- 0004_02, revision B2, March 2009.

S11. Offshore Pipeline Project Data, KCP-GNS-DES-DRP-0003, Rev 01, April 2010

S12. Offshore Route Selection Report, Penspen, 80011/RPT-PL-005, Rev A, June 2009

S13. Kingsnorth CO2 Route Option – Feb 2010, J71516-A-K-SK-01, Rev A1, February 2010

S14. Email Communication “Kingsnorth CCS Project – Outstanding Data - Genesis 2010” from E.ON UK to Genesis, 08/04/10

S15. Email Communication “Basis of Design For Studies” from E.ON UK to Genesis, 29/04/10


Revision: 04






S16. Email Communication 21/04/10 from E.ON UK to Genesis, J71584A_CRRPDC_IN_035 and attachment 2009-02-05 Hewett Reservoir pressure data and plots.xlsx

S17. EOS Prediction of CO2 Properties, Doc No. KCP-GNS-FAS-DRP-0001

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