6.26 Transient Analysis Depressurising and Venting (Pipeline)

KCP-GNS-FAS-DRP-0004

Revision: 02

Project Title: Kingsnorth Carbon Capture & Storage Project Page 1 of 54

Document Title: Transient Analysis – Depressuring and Venting (Pipeline)

Kingsnorth CCS Demonstration Project The information contained in this document (the Information) is provided in good faith. E.ON UK plc, its subcontractors, subsidiaries, affiliates, employees, advisers, and the Department of Energy and Climate Change (DECC) make no representation or warranty as to the accuracy, reliability or completeness of the Information and neither E.ON UK plc nor any of its subcontractors, subsidiaries, affiliates, employees, advisers or DECC shall have any liability whatsoever for any direct or indirect loss howsoever arising from the use of the Information by any party.

Transient Analysis – Depressuring and Venting (Pipeline) Table of Contents 1 Executive Summary ................................................................................................................... 6

1.1 Scope of Work .................................................................................................................. 6 1.2 Depressurisation Times and Peak Flow Rates ................................................................. 6

1.2.1 Onshore Pipeline Only .................................................................................................. 6 1.2.2 Onshore and Offshore Pipelines .................................................................................. 7

1.3 Depressurisation of Offshore Kingsnorth Platform Topsides Piping ................................. 7 1.4 Pressure Surges ............................................................................................................... 7 1.5 Minimum Temperatures .................................................................................................... 8

1.5.1 Fluid and Wall Temperatures within Pipeline ............................................................... 8 1.5.2 Fluid Temperatures within Vent System ....................................................................... 9

2 Scope of Work ......................................................................................................................... 10 2.1 Pipeline Operating Scenarios ......................................................................................... 10 2.2 Scope of Study ............................................................................................................... 10

3 Basis of Design and Assumptions ........................................................................................... 11 3.1 Depressurisation Philosophy .......................................................................................... 11 3.2 Depressurisation Orifices ................................................................................................ 11 3.3 Vent Backpressure ......................................................................................................... 11 3.4 Final Pressure ................................................................................................................. 12 3.5 Olga Model ..................................................................................................................... 12

4 Depressurisation of Onshore Piping ........................................................................................ 14 4.1 Introduction ..................................................................................................................... 14 4.2 Depressurisation of Onshore Section - Vapour Phase Operation .................................. 14 4.3 Depressurisation of Onshore Section - Dense Phase Operation ................................... 17

5 Depressurisation of Offshore Kingsnorth Platform Topsides Piping ........................................ 25 5.1 Introduction ..................................................................................................................... 25 5.2 Results ............................................................................................................................ 25

6 Depressurisation of Offshore Pipeline ..................................................................................... 26 6.1 Introduction ..................................................................................................................... 26 6.2 Depressurisation of Offshore Pipeline - Vapour Phase Operation ................................. 26 6.3 Depressurisation of Offshore Pipeline - Dense Phase Operation................................... 30

7 Depressurisation of Offshore Pipeline by Pigging ................................................................... 39 8 Pressure Surges ...................................................................................................................... 39

8.1 Introduction ..................................................................................................................... 39 8.2 ESD Closure ................................................................................................................... 39 8.3 “Steam type” Condensation ............................................................................................ 39

9 Supporting References ............................................................................................................ 40 10 Appendix A Onshore Pipeline Depressurisation Results .................................................... 41

10.1 Vapour Phase Operation ................................................................................................ 41 10.2 Dense Phase Operation ................................................................................................. 44

11 Appendix B Offshore Pipeline Depressurisation Results .................................................... 47 11.1 Vapour Phase Operation ................................................................................................ 47 11.2 Dense Phase Operation ................................................................................................. 51


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Table of Tables

Table 1-1 Pipeline Operating Scenarios ...................................................................... 6 Table 1-2 Summary of Minimum Fluid Temperatures during Blowdown ..................... 8 Table 1-3 Summary of Minimum Wall Temperatures during Blowdown ...................... 8 Table 2-1 Pipeline Operating Scenarios .................................................................... 10 Table 2-2 Transient Analysis Cases .......................................................................... 10 Table 4-1 Onshore Pipeline Depressurisation Times – Vapour Phase Operation .... 15 Table 4-2 Minimum Temperatures during Onshore Pipeline Depressurisation– Vapour Phase Operation ............................................................................................ 16 Table 4-3 Onshore Pipeline Depressurisation Times – Dense Phase Operation ...... 17 Table 4-4 Minimum Temperatures during Onshore Pipeline Depressurisation– Dense Phase Operation ........................................................................................................ 19 Table 6-1 Offshore Pipeline Depressurisation Times – Vapour Phase Operation .... 26 Table 6-2 Minimum Temperatures during Vapour Phase Depressurisation of Offshore Pipeline ....................................................................................................................... 28 Table 6-3 Offshore Pipeline Depressurisation Times – Dense Phase Operation ...... 30 Table 6-4 Minimum Operating Temperatures during vapour phase depressurisation of offshore pipeline ..................................................................................................... 33

Table of Figures Figure 3-1 Schematic of OLGA Model for Depressurisation ...................................... 13 Figure 4-1 Pressure Upstream of Depressurisation Orifice – Vapour Phase Operation, Onshore Section ....................................................................................... 15 Figure 4-2 Temperature Downstream of Depressurisation Orifice – Vapour Phase Operation, Onshore Section ....................................................................................... 16 Figure 4-3 Figure 4-4 Mass Flow Rate during Onshore Pipeline Depressurisation, Dense Phase Operation ............................................................................................. 18 Figure 4-5 Liquid Content during Onshore Pipeline Depressurisation, Dense Phase Operation .................................................................................................................... 18 Figure 4-6 Pressure Upstream of leak during Onshore Pipeline Depressurisation, Dense Phase Operation ............................................................................................. 19 Figure 4-7 Downstream Temperature during Onshore Pipeline Depressurisation, Dense Phase Operation ............................................................................................. 20 Figure 4-8 Temperature Trends in Onshore Pipeline during Onshore Blowdown, Dense Phase Operation ............................................................................................. 21 Figure 4-9 Pressure Trends in Onshore Pipeline during Onshore Blowdown, Dense Phase Operation ........................................................................................................ 21 Figure 4-10 Minimum Fluid Temperature in Pipeline during Depressurisation of Onshore Section – Dense Phase Operation .............................................................. 22 Figure 4-11 P-T Pathway at landfall valve, During Depressurisation of Onshore Pipeline (4“ Orifice), Dense Phase Operation. ........................................................... 23 Figure 4-12 P-T pathway upstream of depressurisation orifice, During Depressurisation of Onshore Pipeline (4“ Orifice), Dense Phase Operation ............. 24 Figure 6-1 Depressurisation times and peak mass flow – offshore pipeline, vapour phase .......................................................................................................................... 27 Figure 6-2 Mass Flowrate during Depressurisation of the Offshore Pipeline, Vapour Phase Operation ........................................................................................................ 27 Figure 6-3 Upstream Pressure during Depressurisation of the Offshore Pipeline, .... 28 Figure 6-4 Comparison of T, P in Onshore and Offshore Piping during Blowdown, Vapour Phase Operation ............................................................................................ 29


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Figure 6-5 Depressurisation times and peak mass flow – offshore pipeline, dense phase .......................................................................................................................... 30 Figure 6-6 Mass Flow during Offshore Pipeline Depressurisation, Dense Phase Operation .................................................................................................................... 31 Figure 6-7 Pressure Upstream of Blowdown Valve During Depressurisation of the Offshore Pipeline, Dense Phase Operation ............................................................... 31 Figure 6-8 Comparison of T, P in Onshore and Offshore Piping during Blowdown, Dense Phase Operation ............................................................................................. 33 Figure 6-9 Comparison of Holdup in Onshore and Offshore Piping during Blowdown, Dense Phase Operation ............................................................................................. 34 Figure 6-10 Minimum Fluid Temperature in the Pipe during Depressurisation of the Offshore Pipeline, Dense Phase Operation ............................................................... 35 Figure 6-11 Operating Conditions at 273km during Blowdown of Dense Phase Offshore Pipeline ........................................................................................................ 36 Figure 6-12 Operating Conditions at Riser Base, Dense Phase Offshore Pipeline Blowdown through 6” Orifice ...................................................................................... 36 Figure 6-13 Downstream Temperature during Offshore Depressurisation, Dense Phase Operation ........................................................................................................ 37 Figure 10-1 Downstream Temperature during Onshore Pipeline Depressurisation, Vapour Phase Operation ............................................................................................ 41 Figure 10-2 Upstream Pressure during Onshore Pipeline Depressurisation, Vapour Phase Operation ........................................................................................................ 42 Figure 10-3 Mass Flowrate during Onshore Pipeline Depressurisation, Vapour Phase Operation .................................................................................................................... 42 Figure 10-4 Pipeline Liquid Content during Onshore Pipeline Depressurisation, Vapour Phase Operation ............................................................................................ 43 Figure 10-5 Downstream Temperature during Onshore Pipeline Depressurisation, Dense Phase Operation ............................................................................................. 44 Figure 10-6 Upstream Pressure during Onshore Pipeline Depressurisation, Dense Phase Operation ........................................................................................................ 44 Figure 10-7 Mass Flow Rate during Onshore Pipeline Depressurisation, Dense Phase Operation ........................................................................................................ 45 Figure 10-8 Minimum Pipe Wall Temperature during Onshore Pipeline Depressurisation, Dense Phase Operation ................................................................ 45 Figure 10-9 Minimum Fluid Temperature during Onshore Pipeline Depressurisation, Dense Phase Operation ............................................................................................. 46 Figure 10-10 Liquid Content during Onshore Pipeline Depressurisation, Dense Phase Operation .................................................................................................................... 46 Figure 11-1 Downstream Temperature during Offshore Pipeline Depressurisation, . 47 Figure 11-2 Upstream Pressure during Offshore Pipeline Depressurisation, ............ 48 Figure 11-3 Mass Flowrate during Offshore Pipeline Depressurisation, ................... 48 Figure 11-4 Minimum Wall Temperature during Offshore Pipeline Depressurisation, .................................................................................................................................... 49 Figure 11-5 Liquid Content during Offshore Pipeline Depressurisation, .................... 50 Figure 11-6 Downstream Temperature during Offshore Pipeline Depressurisation, . 51 Figure 11-7 Upstream Pressure during Offshore Pipeline Depressurisation, ............ 51 Figure 11-8 Mass Flowrate during Offshore Pipeline Depressurisation, ................... 52 Figure 11-9 Minimum Wall Temperature during Offshore Pipeline Depressurisation, .................................................................................................................................... 52 Figure 11-10 Minimum Fluid Temperature during Offshore Pipeline Depressurisation, .................................................................................................................................... 53 Figure 11-11 Liquid Content during Offshore Pipeline Depressurisation, .................. 53


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Table of Holds HOLD Description

1 Hewett topsides blowdown orifice sizes considered

2 Offshore Blowdown Pending Data from Plant Layout Review

3 Data from Pigging Simulations

List of Abbreviations

API RP American Petroleum Industry Recommended Practice CCS Carbon Capture and Storage CFD Computational Fluid Dynamics ESD Emergency Shutdown FEED Front End Engineering Design HP High Pressure LP Low Pressure OD Outside Diameter OLGA Transient flow assurance software P-T Pressure-Temperature SDV Shut Down Valve SSIV Subsea Isolation Valve


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1 Executive Summary

1.1 Scope of Work

The pipeline depressurisation analysis takes into account two operating scenarios agreed previously: Table 1-1 Pipeline Operating Scenarios

Property Base Case Full Flow

Vapour Density LP Vapour HP Dense

Power Plant Capacity (without Capture) 400 MW 1600 MW

CO2 Flowrate 6600 t/d 26,400 t/d

This study examines the following depressurisation scenarios for the cases described in Table 1-1 above:

Depressurisation of onshore pipeline

Depressurisation of offshore Kingsnorth platform topsides pipework (HOLD 2)

Depressurisation of offshore pipeline

It is assumed that pipeline depressurisation would be done preferentially by displacing the CO2 into the wells with an air-driven pig, with subsequent depressurisation of the air (as described in Ref S6). However, facilities for manual depressurisation of the entire pipeline via the Kingsnorth CCS plant vent system are considered in this document. It is assumed that the CO2 vented during depressurisation is routed to the onshore CCS plant vent system, from which it will be safely released to atmosphere

1.

1.2 Depressurisation Times and Peak Flow Rates

1.2.1 Onshore Pipeline Only

The 29.5 barg (443 psia) reservoir pressure case was considered for vapour phase operation as this has the highest pipeline settle-out pressure of all the vapour phase cases (33.2 barg) and is thus the most conservative. The quantity of CO2 held in the vapour filled onshore section before depressurisation is approximately 400 tonnes. The depressurisation times required for a range of orifice sizes from 1 to 6 inches ranged from 77 to 2 hours with peak mass flows from 6 to 200 kg/s respectively. The 157.5 barg (2,299 psia) reservoir pressure case was considered for dense phase operation as it is representative of typical dense phase pipeline operation. The quantity of CO2 held in the liquid filled onshore section before depressurisation is approximately 4,200 tonnes. The depressurisation times required for a range of orifice sizes from 1 to 5 inches ranged from greater than 800 hours to 15 hours with peak mass flows from 50 to 1,085 kg/s respectively. The simulation for a 6 inch orifice did not run to the end of the depressurisation (i.e. OLGA model would not converge).

1 The location of the vent stack is not known; for the case of venting of the onshore pipeline (vapour phase)

the stack could be located next to the CCS plant to give the highest initial temperature.


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1.2.2 Onshore and Offshore Pipelines

Depressurisation of the offshore pipeline is currently assumed to be performed preferentially by pigging, thus displacing the CO2 into the reservoir

2. This is

considered separately in Ref S6. If this is not possible, it is assumed that any blowdown would be via the onshore Kingsnorth CCS plant vent system. Depressurisation of the pipeline via the offshore Kingsnorth platform may also be considered; if so this document will be updated following dispersion analysis to confirm this methodology is acceptable with respect to relevant safety standards. Blowdown orifice sizes of 4”, 5” and 6” were considered, as the likely size of the Kingsnorth CCS vent plant was not known at this stage of the project (smaller sizes were presumed to result in excessive blowdown times). As for the onshore case the 29.5 barg (443 psia) reservoir pressure case was considered for vapour phase operation. The quantity of CO2 held in the vapour filled onshore and offshore pipeline before depressurisation is approximately 14,800 tonnes. The depressurisation times required for orifice sizes from 4 to 8 inches ranged from 190 to 74 hours with peak mass flows from 91 to 307 kg/s respectively. Similarly the 157.5 barg (2,299 psia) reservoir pressure case was considered for dense phase operation. The quantity of CO2 held in the liquid filled onshore and offshore pipeline before depressurisation is approximately 152,000 tonnes. The depressurisation times required for a range of orifice sizes from 4 to 8 inches ranged from 558 hours to 199 hours with peak mass flows from 61 to 2,007 kg/s respectively. The peak rates described above, particularly for dense phase depressurisation, are likely to require large vent systems. It may be desirable to limit the instantaneous depressurisation rate upon ESD initiation (e.g slow opening valve or parallel offline locked closed valve system) in order to reduce the required size of the Kingsnorth CCS plant vent system.

1.3 Depressurisation of Offshore Kingsnorth Platform Topsides Piping

This analysis is on hold until platform layout drawings have been produced; these are required to allow an estimate of the topsides inventory to be made.

1.4 Pressure Surges

No significant issues were found for the Kingsnorth system associated with pressure surges due to fluid hammer or vapour condensation.

2 This would be followed by depressurisation of the air in the pipeline via the Kignsnorth CCS plant vent

system


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1.5 Minimum Temperatures

1.5.1 Fluid and Wall Temperatures within Pipeline

The minimum temperatures during blowdown are summarised below. The design temperature will be driven by the requirements for dense phase blowdown rather than vapour phase blowdown. The blowdown of the onshore pipeline is the more onerous of the dense phase blowdown scenarios and will require a significantly lower design temperature than blowdown of the onshore and offshore pipelines together. The minimum fluid and wall temperatures during blowdown are summarised in Table 1-2 and Table 1-3 respectively. Table 1-2 Summary of Minimum Fluid Temperatures during Blowdown

Orifice Size (in)

Min Fluid Temperature within Pipeline °C

Onshore pipeline only Onshore and offshore pipelines

Vapour phase Dense phase Vapour phase Dense phase

1 -3 N/A N/A N/A

2 -4 -55 N/A N/A

3 -6 -78 N/A N/A

4 -7 -78 -2 -7

5 -9 -78 -2 -7

6 -10 -78 -2 -18

Table 1-3 Summary of Minimum Wall Temperatures during Blowdown

Orifice Size (in)

Min Fluid Temperature within Pipeline °C

Onshore pipeline only Onshore and offshore pipelines

Vapour phase Dense phase Vapour phase Dense phase

1 -3 N/A* N/A N/A

2 -3 -41 N/A N/A

3 -3 -63 N/A N/A

4 -4 -68 -3 -7

5 -4 -64 -3 -7

6 -5 -74 -3 -13

N/A corresponds to cases where the orifice size is unsuitable (i.e. too small). The following points should be noted:

The minimum fluid temperature of -18°C for the dense phase onshore and offshore blowdown through a 6” orifice corresponds to a worst case value due to the formation of a pool of liquid CO2. The temperature in the pipeline during blowdown is more typically -12°C.

The minimum fluid temperatures of -78°C in Table 1-2 and Table 1-3 occur when the onshore pipeline is blown down with the offshore pipeline isolated and left pressurised. This is the most onerous design condition for the onshore pipeline but does not apply for the offshore pipeline. Pressure and temperature trends for various positions in the pipeline are provided in section 4.3 for the onshore pipeline and section 6.3 for the offshore pipeline.

Where the fluid and wall temperatures are <-50°C, this occurs with a simultaneous decrease in pressure i.e. the design pressure does not need to allow for -78°C at maximum allowable operating pressure.


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Pressure and temperature trends for the riser are shown in section 6.3 (Figure 6-12). 1.5.2 Fluid Temperatures within Vent System

During vapour phase operation, solids may potentially be formed immediately downstream of the depressurisation orifice as the minimum downstream temperature

3 is c. -56 °C. However it is likely that any solids formed will sublime

quickly as the temperature required to maintain solid CO2 at 1 atm is c. -79 °C. Note that that the velocity in the pipework downstream of the blowdown orifice will likely sweep any solids towards the onshore CCS plant vent system. For dense phase blowdown, there is the potential to form solid CO2 downstream of the depressurisation orifice. During blowdown of the offshore pipeline, the fluid temperature downstream of the orifice is maintained at -79°C for a significant length of time and thus if there is limited heat ingress from atmosphere into the vent system there is the potential for solid CO2 to accumulate downstream of the depressurisation orifice. It is recommended that this be examined in more detail during the design of the vent system.

3 This assumes that the pressure within the vent system could be as high as the triple

point.


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2 Scope of Work

2.1 Pipeline Operating Scenarios

This transient analysis will take into account two operating scenarios described in the project basis of design, as shown in Table 2-1. Table 2-1 Pipeline Operating Scenarios

Property Base Case Full Flow

Vapour Density LP Vapour HP Dense

Power Plant Capacity (without Capture) 400 MW 1,600 MW

CO2 Flowrate 6,600 t/d 26,400 t/d

These scenarios have been described in the flow assurance basis of design and previous steady state simulations; details of base data are provided in Refs S1 and S2 respectively). The two cases considered further in this transient analysis are summarised in Table 2-2. Table 2-2 Transient Analysis Cases

Reservoir pressure psia

Reservoir pressure barg

Scenario Pipeline operating

phase

443 29.5 Base case Vapour

2,299 157.5 Full flow Dense

2.2 Scope of Study

This study examines the following depressurisation scenarios for the cases described in Table 2-2 above:

Depressurisation of onshore pipeline (i.e. up to the landfall isolation valve)

Depressurisation of offshore Kingsnorth platform topsides pipework

Depressurisation of offshore pipeline (i.e. inlet up to isolation valve at offshore Kingsnorth platform) Removal of CO2 from the entire pipeline by pigging (and subsequently depressurising the air-filled pipeline through the Kingsnorth CCS plant vent system) is presumed to be the preferred method of depressurising the entire pipeline; this is considered separately in Ref S6. The shutdown and cooldown OLGA models produced in the previous start-up analysis (Ref S3) will be used as the basis for this study.


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3 Basis of Design and Assumptions

Unless indicated otherwise, the basis of design and assumptions for this study are the same as those presented in Reference S1.

3.1 Depressurisation Philosophy

It is assumed that only the onshore pipeline and offshore platform topsides would be required to be depressurised for ESD or maintenance purposes; the subsea pipeline is assumed to be appropriately isolated and left in a pressurised state. There may be a requirement to depressurise the pipeline in the event of an accident or extreme maintenance operation. This is assumed to be done preferentially by displacing the CO2 into the wells with an air-driven pig, although facilities for manual depressurisation of the entire pipeline via the Kingsnorth CCS plant vent system could also be considered (e.g. if the pipeline was damaged in such a way that pigging would be impossible). It should be noted that a different venting system may be installed for the demonstration phase facility to that used for the full flow system. The vent system for the base case scenario would only be sized for the gaseous mode venting requirements.

3.2 Depressurisation Orifices

The depressurisation of the pipeline and offshore platform topsides piping was modelled using the OLGA “leak” model to represent blowdown through a fixed orifice. As the depressurisation orifice size will not be calculated until the detail design phase of this project, various orifice sizes were considered for comparison:

1, 2, 3, 4, 5 and 6 inches for the onshore pipeline

[HOLD 1] for the offshore Kingsnorth platform topsides equipment / pipework

4, 5, 6 and 8 inches for the offshore pipeline

It should be noted that imperial measurements are used for orifice sizes by convention; this is an exception to the SI system which is utilised elsewhere in this project. The blowdown orifices were modelled in OLGA by using a manual controller to achieve the equivalent orifice area. The discharge coefficient of the orifice (or depressurisation valve) was assumed to be 0.84 throughout the simulation. It is acknowledged that the actual discharges will vary significantly between liquid and vapour service, however for the purposes of this pre-FEED level of study, it was not considered appropriate to model the equipment in this level of detail.

3.3 Vent Backpressure

There may be some backpressure in the vent system, particularly at the peak depressurisation rate. However due to the difference in pressure upstream and


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downstream of the depressurisation orifice, the flow at this point will be critical, i.e. flow rate is independent of downstream pressure. Therefore specifying a higher back pressure would have negligible impact on the peak flow through the orifice; a back pressure of 0 barg was thus assumed. The assumption of a back-pressure of atmospheric pressure is conservative with respect to minimum temperature (i.e. risk of solid formation) downstream of the orifice.

3.4 Final Pressure

There are no industry standards which define the depressurisation criteria for CO2 pipelines. A final pressure of 0 barg was therefore assumed as this would be required in order for any invasive maintenance work to be performed on the pipeline.

3.5 Olga Model

A schematic of the Olga model utilised for the depressurisation studies is illustrated in Figure 3-1.

KCP-GNS-FAS-DRP-

0004 Rev.: 01

Project Title:

Kingsnorth Carbon Capture & Storage Project

Page 13 of 54

Document Title:

Transient Analysis – Depressuring and Venting (Pipeline)

KCP-GNS-FAS-DRP-0004_02-ktKKDoc1--Transient Analysis - Depressurising and Venting (Pipeline)

Printed on: 20-May-10

Figure 3-1 Schematic of OLGA Model for Depressurisation

KCP-GNS-FAS-DRP-

0004 Rev.: 01

Project Title:

Kingsnorth Carbon Capture & Storage Project

Page 14 of 54

Document Title:

Transient Analysis – Depressuring and Venting (Pipeline)

KCP-GNS-FAS-DRP-0004_02-ktKKDoc1--Transient Analysis - Depressurising and Venting (Pipeline)

Printed on: 20-May-10

4 Depressurisation of Onshore Piping

4.1 Introduction

It is assumed that only the onshore pipeline and the offshore platform topsides would normally be required to be depressurised for safety or maintenance purposes. The subsea pipeline and wells are presumed to be appropriately isolated and locked in during an event which would require depressurisation. The CO2 vented during depressurisation is presumed to be routed to the onshore CCS plant vent system, from which it will be safely released to atmosphere. For depressurisation of the onshore piping, the worst case initial conditions for depressurisation are from a pipeline that has been shut in and allowed to cool, as this gives the lowest initial temperature. The results from the shutdown and cooldown simulations from the start-up analysis (Ref S3) were used as the basis for the depressurisation simulations. The landfall valve between the onshore and offshore sections was closed prior to depressurisation of the onshore pipeline. The 29.5 barg (443 psia) reservoir pressure case was considered for vapour phase operation as this has the highest pipeline settle-out pressure of all the vapour phase cases (33.2 barg) and is thus the most conservative. The quantity of CO2 held in the vapour filled onshore section before depressurisation is approximately 400 tonnes. The 157.5 barg (2,299 psia) reservoir pressure case was considered for dense phase operation as it is a representative case for dense phase pipeline operation and allows consistency with the depressurisation of offshore piping (section 5). The pipeline pressure and temperature profiles are similar throughout dense phase operation due to the chokes at the offshore Kingsnorth platform and so all the dense phase cases result in a similar settle-out pressure (62.8 barg). The quantity of CO2 held in the liquid filled onshore section before depressurisation is approximately 4,200 tonnes. The depressurisation was modelled within OLGA as a “leak” (OLGA tool to model leaks and blowdowns) through a fixed orifice. As the depressurisation orifice size will not be calculated until the detail design phase of this project, six standard orifice sizes were considered for comparison – 1” through 6”.

4.2 Depressurisation of Onshore Section - Vapour Phase Operation

The pressures upstream of the depressurisation valves and calculated temperatures downstream of the valves are shown in Figure 4-1 and Figure 4-2 respectively. These results are summarised in Table 4-1 while further results are included in Appendix A. The depressurisation time was recorded as the time at which the pressure upstream of the depressurisation orifice was 0 barg.


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Table 4-1 Onshore Pipeline Depressurisation Times – Vapour Phase Operation

Initial Settle-out pressure (barg)

Orifice size (in)

Depressurisation time (hrs)

Peak Mass Flow (kg/s)

Peak Std. Vol Flow

MSm³/d)

33.2

1 77 6 0.3

2 19 22 1

3 9 50 2

4 5 89 4

5 3 139 6

6 2 200 9

Figure 4-1 Pressure Upstream of Depressurisation Orifice – Vapour Phase Operation, Onshore Section The minimum wall temperature in the pipework is also of concern when blowing down a pipeline; in this case the minimum wall temperature in the onshore section do not fall below -6°C, which is the minimum ambient air temperature assumed for the purposes of the Kingsnorth flow assurance studies (Ref S1). The minimum temperatures are shown in Figure 4-2 and Table 4-2 (onshore section only).


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Figure 4-2 Temperature Downstream of Depressurisation Orifice – Vapour Phase Operation, Onshore Section For vapour phase operation, the minimum temperature in the system is that downstream of the blowdown orifice, which reaches -56°C. This is only very marginally above the triple point temperature. There is the potential for solid CO2 to form within the orifice as the pressure is reduced; however any solids formed are likely to sublime quickly downstream of the orifice as the temperature required to maintain solid CO2 at 1 atm is c. -79 °C. It should be noted however that the validity of the assumption that any solid CO2 will sublime before the pipe becomes blocked will depend on the orifice size, as smaller orifices are inherently more likely to become blocked with solid CO2. The potential for solid CO2 to form on the pipe walls and then break loose and move along the vent pipework should also be considered. Solids will not form in the onshore pipeline as the temperatures of the fluid and walls do not fall sufficiently low during depressurisation, as shown in Table 4-2. Table 4-2 Minimum Temperatures during Onshore Pipeline Depressurisation– Vapour Phase Operation

Settle-out pressure (barg)

Orifice size (in)

Min fluid temperature D/S

orifice (°C)

Min fluid temperature in Pipeline

(°C)

Min wall temperature in pipeline (°C)

33.2

1 -56 -3 -3

2 -56 -4 -3

3 -56 -6 -3

4 -56 -7 -4

5 -56 -9 -4

6 -56 -10 -5


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4.3 Depressurisation of Onshore Section - Dense Phase Operation

The time taken to depressurise the onshore section of the pipeline (i.e. achieve a pressure of 0 barg upstream of the depressurisation orifice) from the settle-out pressure of 62.8 barg are shown for orifice sizes of 1” through 6” in Table 4-3. The peak rates are shown both in terms of mass and standard volume.

Table 4-3 Onshore Pipeline Depressurisation Times – Dense Phase Operation


Orifice size (in)

Depressurisation time (hrs)


Peak Std. Vol Flow

(MSm³/d)

62.8

1 >800 50 2

2 188 196 9

3 48 398 19

4 22 702 33

5 15 1,085 50

6 N/A (1) 1,493 92

(1) The OLGA model for the 6" orifice case would not solve beyond the minimum turning point in fluid / wall temperature (at simulation time of c. t = 23.3 hr). Other attempts to model depressurisation of CO2 systems with large orifices produced results that appear to be physically unreasonable, so it is presumed to be a limitation of the modelling rather than a genuine effect.

When depressurisation is initiated the peak flowrate is considerably greater than the flow rate for the remainder of the depressurisation, as illustrated in Figure 4-3. There may therefore be scope to limit the rate at which the depressurisation valve can be opened (to limit the initial depressurisation rate) in order to reduce the size of the required vent system. This will be discussed in more detail for depressurisation of the offshore pipeline (Section 6.3).


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Figure 4-3 Figure 4-4 Mass Flow Rate during Onshore Pipeline Depressurisation, Dense Phase Operation Unlike vapour phase operation, where the pressure declined from approximately the same time for all orifice sizes, there are significant differences between orifice sizes in the time from which the pressure begins to decline for dense phase operation. For dense phase operation the CO2 is in the liquid phase at the beginning of the simulation. The system responds such that it operates on the saturation line and liquid is boiled off to replace the vented gas. For the smaller orifice sizes (1 and 2 inch) the gas is vented at a very slow rate such that the pressure in the pipeline remains at the saturation pressure (for the relevant fluid temperature) for a significant length of time. For the 1“ orifice the liquid had still not been completely evaporated at the end of an extended 800 hour (33 day) simulation; it was thus concluded that this orifice size would not be practical for depressurising the onshore pipeline. For larger orifice sizes, the contents of the pipeline are vapourised quickly and thus the pressure upstream of the leak began to decline relatively quickly. The total liquid content in the pipeline and pressure upstream of the depressurisation orifice are compared for the various orifice sizes in Figure 4-5 and Figure 4-6 respectively.

Figure 4-5 Liquid Content during Onshore Pipeline Depressurisation, Dense Phase Operation


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Figure 4-6 Pressure Upstream of leak during Onshore Pipeline Depressurisation, Dense Phase Operation

The minimum fluid temperatures downstream of the depressurisation orifice and in the pipeline and the minimum wall temperature in the pipeline are presented in Table 4-4. Table 4-4 Minimum Temperatures during Onshore Pipeline Depressurisation– Dense Phase Operation


Orifice size (in)

Min fluid temperature D/S orifice

(°C)

Min fluid temperature in pipeline

(°C)

Min wall temperature in pipeline

(°C)

62.8

1 -79 N/A (1) N/A (1)

2 -79 -55 -41

3 -79 -78 -63

4 -79 -78 -68

5 -79 -78 -64

6 -79 -78 -74

(1) For the 1“ orifice the pipeline contents had not fully vapourised by the end of the simulation and thus the worst case fluid and wall temperatures had yet to be reached

The minimum temperature downstream of the orifice is the same for all cases, as the pressure difference is identical. However, this minimum temperature is only sustained as long as there is a high upstream pressure; when the pipeline becomes


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vapour-filled the upstream pressure declines quickly, such that the downstream temperature begins to increase. This is shown in Figure 4-6 and Figure 4-7.

Figure 4-7 Downstream Temperature during Onshore Pipeline Depressurisation, Dense Phase Operation The minimum wall temperature in the system is shown to generally move to colder values with increasing orifice size (Table 4-4 above); as the depressurisation rate increases there is less heat exchange between the fluid and the surroundings thus the system approaches adiabatic behaviour. The minimum temperature in the pipeline is that adjacent to the landfall SDV. The pressure and temperature trends for a variety of positions within the pipeline are shown in Figure 4-8 and Figure 4-9below, with P16S1 (Pipe 16, section 1 – adjacent to landfall SDV) being the worst case temperature.


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Figure 4-8 Temperature Trends in Onshore Pipeline during Onshore Blowdown, Dense Phase Operation

Figure 4-9 Pressure Trends in Onshore Pipeline during Onshore Blowdown, Dense Phase Operation


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The minimum fluid temperature in the pipeline is around -79°C for all orifice sizes. As the vapourisation of CO2 is an endothermic process, heat must be absorbed to vapourise the liquid CO2 in the pipeline. As the system behaviour tends towards adiabatic, this heat must come from the fluid itself and hence the temperature of the CO2 in the pipeline falls significantly during depressurisation. The fluid temperature begins to increase once the last liquid has been vapourised, as shown in Figure 4-10. The time required to vapourise the liquid in the pipeline decreases with increasing orifice size, thus the 3“ and 2“ orifices do not display a minimum temperature until after that of the larger orifices. The contents of the pipeline are not fully vapourised during the simulation for 1“ orifice hence the trend does not show a decrease in temperature in the pipeline for this orifice size.

Figure 4-10 Minimum Fluid Temperature in Pipeline during Depressurisation of Onshore Section – Dense Phase Operation For depressurisation during dense phase operation, the CO2 is in the liquid phase at the beginning of the simulation. The system moves such that it operates on the saturation line and liquid is boiled off to replace the vented gas. Once the liquid in the onshore section has all vapourised (i.e. along the saturation line) then the sublimation line is followed. Therefore solid CO2 will be formed in the pipeline during the depressurisation. The P-T pathway for the position immediately adjacent to the landfall valve is shown in Figure 4-11 to illustrate this; this position in the pipeline takes longest for the temperature to recover.


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Figure 4-11 P-T Pathway at landfall valve, During Depressurisation of Onshore Pipeline (4“ Orifice), Dense Phase Operation. Conversely for the position immediately upstream of the depressurisation orifice, the temperature increases a lot faster and so the P-T pathway does not follow the sublimation line to the same extent (see Figure 4-12) and the fluid is fully vapourised at a higher pressure (6 bara vs. 1 bara). Nonetheless there are conditions in the pipeline which will maintain solid carbon dioxide. If provision is made to blow the pipeline down quickly with minimum heating from the ambient, it is recommended that further work be done to analyse the potential for solid CO2 to either form blockages or projectiles (i.e. if the wall temperature warms up so that it is higher than the fluid temperature then a plug of solid CO2 could be forced along the pipeline at high velocity).


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Figure 4-12 P-T pathway upstream of depressurisation orifice, During Depressurisation of Onshore Pipeline (4“ Orifice), Dense Phase Operation


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5 Depressurisation of Offshore Kingsnorth Platform Topsides Piping

5.1 Introduction

The time taken to blow down the topsides piping on the offshore Kingsnorth platform is strongly dependent on the inventory contained within the pipework. This cannot be estimated with any reasonable degree of accuracy until layout drawings have been constructed. This section of work will therefore be completed following issue of the topsides equipment layout review (Ref S4).

5.2 Results

HOLD 2


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6 Depressurisation of Offshore Pipeline

6.1 Introduction

In the event that depressurisation of the offshore pipeline is required, it is presumed that the preferred method would be to displace the CO2 in the pipeline into the wells using an air-driven pig. The air remaining in the pipeline would subsequently be blown down via the Kingsnorth CCS plant vent system. This is subject to risk assessment. Provision for manual depressurisation could also be provided (Ref S5); again it is assumed that depressurisation is from the Kingsnorth CCS plant and no venting occurs from the offshore platform

4. The quantity of CO2 held in the vapour

and dense filled onshore and offshore pipelines before depressurisation is approximately 14,800 and 152,000 tonnes respectively.

The methodology for depressurisation of the offshore pipeline is very similar to that described in section 4 above for the onshore pipeline; the only significant difference is the location of the isolation valve, which was assumed to be at the offshore Kingsnorth platform. As for the onshore pipeline blowdown, no information is available regarding depressurisation orifices or valves for the onshore vent pipework at this stage of the project, so orifices of 4”, 5”, 6” and 8” were considered. Based on the results of the onshore pipeline depressurisation, smaller orifice sizes were assumed to result in excessively large depressurisation times. The results are summarised below with further detail provided in Appendix B.

6.2 Depressurisation of Offshore Pipeline - Vapour Phase Operation

The depressurisation times and peak mass flow rates are tabulated in Table 6-2 and illustrated in Figure 6-1. Table 6-1 Offshore Pipeline Depressurisation Times – Vapour Phase Operation

Orifice size (in) Depressurisation

time (hrs)


Peak Std. Vol Flow

(MSm³/d)

4 190 92 4

5 137 142 7

6 99 204 9

8 74 357 17

4 Following dispersion analysis it may be considered acceptable to vent the pipeline contents from the

offshore platform rather than Kingsnorth CCS plant; if so this analysis will be updated accordingly.


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0

50

100

150

200

250

300

350

400

40

60

80

100

120

140

160

180

200

2 4 6 8 10

Pe

ak m

ass

flo

w (

kg/s

)

de

pre

ssu

risa

tio

n t

ime

(h

r)

Depressurisation time and peak mass flowOffshore pipeline - vapour phase

depressurisation time peak mass flow

Figure 6-1 Depressurisation times and peak mass flow – offshore pipeline, vapour phase The peak rates are identical to those for the onshore section, for the same orifice size. Similarly, the peak rates upon depressurisation initiation are significantly larger than the rates for the remainder of the depressurisation, as shown in Figure 6-2.

Figure 6-2 Mass Flowrate during Depressurisation of the Offshore Pipeline, Vapour Phase Operation


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Figure 6-3 Upstream Pressure during Depressurisation of the Offshore Pipeline, Vapour Phase Operation It can be seen in Figure 6-3 that there is a smooth, exponential reduction of pressure in the pipeline with time. The minimum temperatures in the system during the depressurisation of the pipeline are presented in Table 6-2. Table 6-2 Minimum Temperatures during Vapour Phase Depressurisation of Offshore Pipeline

Orifice size (in)


(°C)


(°C)


(°C)

4 -60 -2 -3

5 -59 -2 -3

6 -58 -2 -3

8 -58 -2 -3

The minimum temperature downstream of the choke should be the same for all orifice sizes as the pressure difference is identical. There is a slight difference between the results for orifice sizes of 4”, 5”, 6” and 8”; however the difference is small and within the normally accepted error range of OLGA. The pressure and temperature at two positions in the pipeline are shown below to illustrate the difference in operating conditions between the onshore and offshore sections of the pipeline. The “3km” position is at a distance of 3km from the pipeline inlet in a low point and represents the onshore section. The “240km” position is at a


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distance of 240km from the pipeline, also in a low point, and represents the offshore section. Trends for the 4” blowdown orifice are presented in Figure 6-4:

Figure 6-4 Comparison of T, P in Onshore and Offshore Piping during Blowdown, Vapour Phase Operation Although the pressures are similar for the onshore and offshore sections (with a slight pressure gradient from the platform to the shore as expected), the temperatures are different. The temperature in the onshore section is colder than that in the offshore section. This is due to the lower ambient temperature in the onshore section and also the lower heat transfer coefficient from the surroundings: there is less heat ingress from the surroundings to counter the effects of Joule-Thomson cooling. The minimum fluid and wall temperatures are constant for all orifice sizes. It is concluded therefore that the flow rates for all orifice sizes are sufficiently low that heat can be transferred from the surroundings. As for depressurisation of the onshore pipeline, the minimum temperature in the system is that downstream of the orifice, which reaches c. -56°C. This is approximately the triple point temperature. There is the potential for solid CO2 to form over the orifice as the pressure is reduced however any solids formed will likely sublime quickly downstream of the orifice as the temperature required to maintain solid CO2 at 1 atm is c. -79 °C. However consideration should be given to the potential to form lumps of solid CO2, which could block vent pipework.


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6.3 Depressurisation of Offshore Pipeline - Dense Phase Operation

The depressurisation times and peak mass flow rates are tabulated in Table 6-3 and illustrated in Figure 6-5. Table 6-3 Offshore Pipeline Depressurisation Times – Dense Phase Operation

Orifice size (in) Depressurisation

time (hrs)


Peak Std. Vol Flow

(MSm³/d)

4 558 601 28

5 381 863 40

6 281 1257 58

8 199 2007 93

0

500

1,000

1,500

2,000

2,500

150

250

350

450

550

2 4 6 8 10

Pe

ak m

ass

flo

w (

kg/s

)

de

pre

ssu

risa

tio

n t

ime

(h

r)

Depressurisation time and peak mass flowOffshore pipeline - dense phase

depressurisation time peak mass flow

Figure 6-5 Depressurisation times and peak mass flow – offshore pipeline, dense phase

The peak flow rates to the vent system when depressurisation is initiated are likely to be significantly greater than the maximum design flow rates and normal operational rates. Some form of slow-opening depressurisation valve to limit the initial rate may therefore be advantageous as the peak is instantaneous and not sustained for a great length of time, as illustrated in Figure 6-6. Alternatively a parallel offline locked closed system could be considered.


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Figure 6-6 Mass Flow during Offshore Pipeline Depressurisation, Dense Phase Operation

Figure 6-7 Pressure Upstream of Blowdown Valve During Depressurisation of the Offshore Pipeline, Dense Phase Operation


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The pressure upstream of the blowdown orifice is shown in Figure 6-7. Unlike hydrocarbon systems, there is no requirement to reach a given pressure in a specified time (e.g. API RP 521 criteria of 7 barg in 15 minutes) and therefore the peak depressurisation rate could be reduced significantly in order to minimise the size of the vent system, with no significant adverse effects, barring a slight increase in depressurisation time before maintenance can be performed. The minimum fluid temperature downstream of the depressurisation orifice and in the pipeline and the minimum wall temperature are shown below in Table 6-4. Table 6-4 Minimum Operating Temperatures during vapour phase depressurisation of offshore pipeline

Orifice size (in)


(°C)


(°C)


(°C)

4 -79 -7 -7

5 -79 -7 -7

6 -79 -18 -13

8 -79 -17 -12

As for vapour phase operation, the temperatures in the onshore and offshore sections are slightly different; illustrated in Figure 6-8 for the 4” blowdown orifice.

Figure 6-8 Comparison of T, P in Onshore and Offshore Piping during Blowdown, Dense Phase Operation The temperature is lower in the onshore section than the offshore section, as per vapour phase operation. However, unlike vapour phase operation, there is a

3km = typical onshore trough 240 km = typical offshore trough


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significant difference in pressure between the onshore pipeline at the Kingsnorth CCS plant and the offshore platform while the CO2 is vapourising (as illustrated in Figure 6-8). The pressure gradient in the pipeline is more significant than for vapour phase operation due to the increase in vapour content in the pipeline upstream of the blowdown orifice. Once the liquid in the pipeline has vapourised (shown in Figure 6-9 below to occur at a simulation time of 360 hr), the pressure gradient in the pipeline returns to a small difference.

Figure 6-9 Comparison of Holdup in Onshore and Offshore Piping during Blowdown, Dense Phase Operation The minimum temperatures downstream of the orifices are identical for all orifice sizes as the pressure difference is identical. The minimum wall and fluid temperatures within the pipeline are greater (i.e. warmer) than for the depressurisation of the onshore pipeline, thus it will be the onshore blowdown scenario that defines the minimum design temperature of the pipeline. For dense phase operation the CO2 is in the liquid phase at the beginning of the simulation. The system moves such that it operates on the saturation line and liquid is boiled off to replace the vented gas. The heat required is absorbed from the fluid, but the fluid temperature does not drop as significantly as for the onshore pipeline depressurisation. It is possible to absorb much more heat from the surroundings into the subsea pipeline (partially buried in sand, ambient fluid seawater) than to the onshore pipeline (buried in mud, ambient fluid air) and thus the system behaves less like an adiabatic system for the offshore depressurisation than for onshore depressurisation

5. The mass flow through the orifice is approximately the same and

thus the vaporisation rate and required heat flow is similar to that of onshore depressurisation. However, the required heat ingress is spread over a significantly larger area allowing a greater proportion to come from the surrounding seawater

5 That is closer to isothermal behaviour.


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rather than the CO2 itself. As a result, the minimum temperatures for the offshore depressurisation are higher than for the onshore depressurisation. The minimum temperature in the pipeline increases following the initial cooling but then suddenly drops down again for the 6” and 8” orifice sizes, as illustrated in Figure 6-10. This is due to the heat absorbed to evaporate the last pools of liquid in the pipeline. The minimum temperature of -18°C for the 6” orifice occurs at the end of the pipeline (i.e. near the platform) at a distance of approximately 272-274 km. The temperature, pressure and hold up at this position are shown in Figure 6-11; note the decrease in temperature to –18°C as the liquid hold-up falls to zero.

Figure 6-10 Minimum Fluid Temperature in the Pipe during Depressurisation of the Offshore Pipeline, Dense Phase Operation


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Figure 6-11 Operating Conditions at 273km during Blowdown of Dense Phase Offshore Pipeline Also of interest is the operating conditions at the base of the riser; these are shown in Figure 6-12 below for a 6” blowdown orifice. No low temperatures are exhibited.

Figure 6-12 Operating Conditions at Riser Base, Dense Phase Offshore Pipeline Blowdown through 6” Orifice


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Although the temperatures in the pipeline are not low enough to form solid carbon dioxide, solid CO2 will form over the depressurisation orifice. The conditions downstream of the depressurisation valve are -79°C and 1 atm for a significant period of time (in excess of 100 hours for a 6” orifice) while the liquid CO2 in the pipeline is being vapourised

6. This is illustrated in Figure 6-13 below. At this temperature and

pressure solid CO2 can be maintained until the fluid is heated by the atmosphere. However, if there is limited heat ingress from atmosphere into the vent system there is the potential for solid CO2 to accumulate downstream of the depressurisation valve.

Figure 6-13 Downstream Temperature during Offshore Depressurisation, Dense Phase Operation With a temperature of -79°C downstream of blowdown orifice, many company insulation guidelines will stipulate that provision should be made for personnel protection from low temperatures on the Kingsnorth CCS plant vent system. If this is the case for the vent system then it is recommended that the ability of the chosen system to allow heat ingress be investigated (i.e. mesh guard may be more appropriate than traditional insulation). It should be noted that, although methanol is often used to prevent hydrate blockages downstream of valves, this is not generally applicable to the prevention of blockages

6 Depending on the vent system design, the back-pressure may be slightly higher than 1 atm, however this

is not known at this early stage of the design project.


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when depressurising CO2 lines. With hydrates the quantity of methanol required is based on the water content of the gas, which is normally small relative to the total flowrate. However, with CO2 a significant fraction of the stream is likely to solidify, such that based on typical depressurisation rates discussed in this study (hundreds of kg per second) the quantity of methanol required would be very large. It is also important to note that if insufficient methanol were used it could do more harm than good since mixtures of methanol plus dry ice (as used in dry ice alcohol baths) will form a very thick paste that is likely to be more problematic than dry solid carbon dioxide on its own.


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7 Depressurisation of Offshore Pipeline by Pigging

Pigging simulations have been carried out as part of a separate study. This will include the use of an air-driven pig to displace the carbon dioxide from the flowline into the wells, followed by depressurisation of the air left within the pipeline. Further details are provided in the Transient Analysis – Pigging (Pipeline) report (Ref SS6).

8 Pressure Surges

8.1 Introduction

In any situation which requires activation of the emergency shutdown system actions would be taken to initiate isolation of the onshore compression plant, pipeline, and platform / wells. In this case there is the potential for fluid hammer / pressure surge effects on closure of fast acting valves. There is also the potential for pressure surges due to rapid condensation of vapour. This type of pressure surge could occur at key points along the pipeline where hot CO2 vapour comes in contact with cold liquid CO2.

8.2 ESD Closure

The rapid closure of the SSIV (or any other valve) at the offshore platform while the system is operated in the dense phase region and at maximum flow conditions could potentially lead to pressure surges. From Genesis experience of similar dense phase CO2 systems, the pressure surges are expected to be negligible, due to the very low liquid velocities

7, and the fact that the speed of sound in liquid CO2 is relatively small

compared with typical hydrocarbon systems.

8.3 “Steam type” Condensation

The second possible type of pressure surge to be considered is the so-called condensation-induced fluid hammer. It is frequently encountered in steam systems and corresponds to a rapid condensation event. If the pipeline is operated in single phase then hot CO2 vapour could only come into contact with cold liquid CO2 during transient situations. The analysis of the transient simulations performed for start-up, ramp-up, line pack and depressurisation have not indicated any significant pressure surges due to condensation-induced fluid hammer.

7 Even with a conservative assumption of instantaneous valve closure the surge pressure is still very small.


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9 Supporting References

S1. Basis of Design for Studies - Phase 1A, KCP-GNS-PCD-STU, August 2010

S2. Steady State Analysis (Pipeline), KCP-GNS-FAS-DRP-0002, June 2010

S3. Transient Analysis – Start-up (Pipeline), KCP-GNS-FAS-DRP-0003, June 2010

S4. Plant Layout Review, KCP-GNS-PTL-REP-0001 (to be issued)

S5. Platform and Pipeline Relief, Vent and Depressurisation System Design Philosophy,

KCP-GNS-PCD-DPR-0003, July 2010.

S6. Transient Analysis – Pigging (Pipeline), KCP-GNS-FAS-DRP-0006, October 2010


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10 Appendix A Onshore Pipeline Depressurisation Results

10.1 Vapour Phase Operation

Figure 10-1 Downstream Temperature during Onshore Pipeline Depressurisation, Vapour Phase Operation


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Figure 10-2 Upstream Pressure during Onshore Pipeline Depressurisation, Vapour Phase Operation

Figure 10-3 Mass Flowrate during Onshore Pipeline Depressurisation, Vapour Phase Operation


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Figure 10-4 Pipeline Liquid Content during Onshore Pipeline Depressurisation, Vapour Phase Operation


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10.2 Dense Phase Operation

Figure 10-5 Downstream Temperature during Onshore Pipeline Depressurisation, Dense Phase Operation

Figure 10-6 Upstream Pressure during Onshore Pipeline Depressurisation, Dense Phase Operation


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Figure 10-7 Mass Flow Rate during Onshore Pipeline Depressurisation, Dense Phase Operation

Figure 10-8 Minimum Pipe Wall Temperature during Onshore Pipeline Depressurisation, Dense Phase Operation


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Figure 10-9 Minimum Fluid Temperature during Onshore Pipeline Depressurisation, Dense Phase Operation

Figure 10-10 Liquid Content during Onshore Pipeline Depressurisation, Dense Phase Operation


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11 Appendix B Offshore Pipeline Depressurisation Results

11.1 Vapour Phase Operation

Note that the OLGA trend plot for calculated minimum fluid temperature in the branch (MINTMBRCT) is not shown for this case as it is misleading; the temperatures provided by Olga show “spikes” which appear to be physically unreasonable.

Figure 11-1 Downstream Temperature during Offshore Pipeline Depressurisation, Vapour Phase Operation


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Figure 11-2 Upstream Pressure during Offshore Pipeline Depressurisation, Vapour Phase Operation

Figure 11-3 Mass Flowrate during Offshore Pipeline Depressurisation, Vapour Phase Operation


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Figure 11-4 Minimum Wall Temperature during Offshore Pipeline Depressurisation, Vapour Phase Operation


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Figure 11-5 Liquid Content during Offshore Pipeline Depressurisation, Vapour Phase Operation


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11.2 Dense Phase Operation

Figure 11-6 Downstream Temperature during Offshore Pipeline Depressurisation, Dense Phase Operation

Figure 11-7 Upstream Pressure during Offshore Pipeline Depressurisation,


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Dense Phase Operation

Figure 11-8 Mass Flowrate during Offshore Pipeline Depressurisation, Dense Phase Operation

Figure 11-9 Minimum Wall Temperature during Offshore Pipeline Depressurisation, Dense Phase Operation


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Figure 11-10 Minimum Fluid Temperature during Offshore Pipeline Depressurisation, Dense Phase Operation

Figure 11-11 Liquid Content during Offshore Pipeline Depressurisation,


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Dense Phase Operation

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6.26 Transient Analysis Depressurising and Venting (Pipeline)

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