6.32 Transient Analysis Ramp Up and Line Pack (Pipeline)

KCP-GNS-FAS-DRP-0005

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Project Title: Kingsnorth Carbon Capture & Storage Project Page 1 of 40

Document Title: Transient Analysis – Ramp Up and Line Pack (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 – Ramp Up and Line Pack (Pipeline)

Table of Contents 1. Executive Summary 1.1. Introduction 1.2. Line Pack 1.3. Transition from Vapour Phase to Dense Phase Operation 1.4. Ramp Up 1.5. Uncertainties and Recommendations 2. Scope of Work 2.1. Description of System 2.2. Operating Scenarios 2.3. Scope of Study 3. Basis of Design and Assumptions 3.1. Ramp up rate 3.2. Heater Setpoints 3.3. Pressure Control at Hewett 3.4. Reporting of Results 4. Line Pack 4.1. Introduction 4.2. Base Case Vapour Phase Operation 4.3. Full Flow Dense Phase Operation 5. Transition from Vapour Phase to Dense Phase 5.1. Introduction 5.2. Liquid Formation 5.3. Pressure Trends 5.4. Temperature Trends 6. Ramp-up 6.1. Introduction 6.2. Vapour Phase Operation 6.3. Dense Phase Operation 7. References 8. Appendix 1 Line Pack Results 9. Appendix 2 Phase Transition Results 10. Appendix 3 Ramp Up Results


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List of Abbreviations

CCS Carbon Capture and Sequestration

CITHP Closed-In Tubing Head Pressure

FEED Front End Engineering Design

HAZID Hazard Identification

HP High Pressure

LP Low Pressure

OLGA Scandpower Olga Flow Assurance Software

PCV Pressure Control Valve

P-T Pressure-Temperature

RP Reservoir Pressure

U/S Upstream


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1. Executive Summary

1.1. Introduction

E.ON UK are considering investment in a new state of the art, coal fired power plant at Kingsnorth, which is on the Isle of Grain. 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.

The primary objective of the transient analysis described in this work is to provide the data necessary to update the relevant operating philosophies using OLGA simulation cases and analysis of the results. Similarly, high level HAZID studies for the Kingsnorth to Hewett CO2 system are planned and these will also be used to modify the operating philosophy.

The transient analysis takes into account three operating scenarios agreed previously:

Table 1-1 Pipeline Operating Scenarios

Property Base Case Full Flow Max Capacity

Vapour Density LP Vapour HP Dense HP Dense

Power Plant Capacity 400 MWg 1600 MWg N/A

CO2 Flowrate 6600 te/d 26,400 te/d Max

The base case and full flow scenarios are considered in this ramp-up analysis. The maximum capacity cases are not considered in the transient studies.

During production upsets or outages of the wells it may be necessary to pack the line while the problem is rectified. This will cause the flowline pressure to increase, which can lead to condensation of liquids (if operating in the vapour phase) or the pipeline pressure reaching the design pressure (if operating in the dense phase). The line must also be packed in order to transition from vapour phase operation to dense phase operation. During production upsets or outages in the power plant, it may be necessary to operate the pipeline at a reduced inlet flowrate. When the flow rate is subsequently increased, adjustments will likely be required to the heater and choke arrangement at the Hewett platform to maintain steady operation. This report considers the line pack, phase transition and ramp down operations for the pipeline.


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1.2. Line Pack

1.2.1. Vapour Phase Operation

When the line is packed during vapour phase operation the dew point is reached after a period of time and liquid starts to condense in the pipeline. The time taken for the first drop of liquid to form in the system at low ambient air temperatures is significantly reduced by utilising trace heating on the topsides pipework. Following the first condensation of liquid, the liquid content in the pipeline generally increases slightly with time and then falls back to near zero prior to bulk condensation occurring. The times taken to form the first drop of liquid and the time for bulk liquid condensation to occur (assuming trace heating is utilised on the topsides pipework) are compared for reservoir pressures of 2.1 and 29.5 barg in Table 1-2.

Table 1-2 Comparison of liquid formation time for 2.1 and 29.5 barg reservoir pressures

Reservoir pressure barg

Time from closing Hewett chokes (hrs)

First liquid formation Bulk liquid formation

2.1 16 201

29.5 13 183

The impact of utilising heat tracing and operating at a reduced turndown on the time before liquid is formed is shown in Table 1-3 below. The time taken to condense liquid at 100% of base case flow (6600 te/d) and 25% of base case flow are compared. Utilising trace heating on the topsides can improve the line pack capacity as the worst case air temperature on the Hewett platform is -6 °C thus, without heat tracing, liquid will condense in the topsides pipework before the subsea pipeline (worst case ambient temperature 4°C)

This demonstrates that both trace heating on the topsides pipework and reducing the flow from Kingsnorth may be used to extend the length of time for which the line can be packed before condensing liquid CO2. It should however be noted that, as the line is pressurised above the CITHP, additional heating duty will be required upon restart. The topsides heaters are only specified as 1 MW and are only able to start up individually therefore additional simulation of re-starting a line-packed pipeline may be beneficial.

Table 1-3 Time taken to condense first liquid during linepack (2.1 barg RP)

Heat tracing Time until first liquid formation (hr)

100% base case flow 25% base case flow

Without heat tracing 16 41

Heat tracing on topsides pipework 34 135

1.2.2. Dense Phase Operation

For dense phase operation, the pipeline is already operating in the dense phase prior to line packing, thus the additional CO2 introduced will cause a rapid increase in pressure. The time taken to increase the pressure at the pipeline inlet from normal operating pressure (87 barg at 100% of full flow i.e. 26,400 te/d, 81 barg at 25% of full flow) to the design pressure of 150


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barg is shown in Table 1-4. Also shown are the times taken to reach the alternative design pressures of 120 barg and 200 barg, which are considered as sensitivity cases in this project. These times are applicable to all reservoir pressures for dense phase operation, as the flowline pressure profiles are constant through field life for the full flow scenario.

Table 1-4 Time taken to pressurise dense phase pipeline during line packing

Pressure (barg)

Time to reach pressure (hr)

100% full flow 25% full flow

120 2.4 15

150 4.4 26

200 7.5 40

The calculated time of 4 hours for the pipeline inlet pressure to reach 150 barg indicates that the system is only able to be line-packed for a short time of c. 4 hours before flow into the pipeline can no longer be sustained. Flow into the pipeline cannot continue once the inlet pressure of the pipeline reaches the maximum discharge pressure of the compressor; at this point the compressor would need to be shut down or put into recycle while the CO2 is vented. The length of time the line can be packed for increases significantly at low turndown; flow may continue for around one day at 25% turndown before the pipeline design pressure of 150 barg is approached.

It should be noted that the times above are based on winter conditions which is the most conservative case with respect to maximum line pack time before liquid condensation. The line may be packed to a higher pressure for maximum summer ambient temperatures before liquid will be formed in the pipeline.

1.3. Transition from Vapour Phase to Dense Phase Operation

As the pipeline inlet pressure at Kingsnorth increases it will become necessary to change from vapour phase operation of the pipeline to dense phase operation, to avoid the potential for operating with two phase vapour/liquid flow. The assumed mechanism for this is packing of the line to condense the vapour. Once the pipeline becomes liquid filled it will then be pressurised to the assumed Hewett arrival pressure of 79 barg and injection can then be resumed in the dense phase. The 443 psia / 29.5 barg reservoir pressure case was used as a basis, with inlet flows of 6600 te/d (base case) and 26400 te/d (full flow) considered. The times taken for liquid formation are shown in Table 1-5.

Table 1-5 Time to fill pipeline with liquid during phase transition (29.5 barg RP)

Flowrate te/d

Time from closing Hewett chokes (hr)

First liquid formation(1)

Bulk liquid formation

Pipeline liquid-filled

6600 13 183 393

26400 2 46 111

(1) Refers to liquid formation in the subsea pipeline. Liquid may condense prior to this in the topsides piping which is exposed to a worst case ambient temperature of -6°C .


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The time at which the pressure at the Hewett platform reaches 79 barg, the assumed normal operating pressure of the Hewett manual chokes, is shown in Table 1-6

1. Also noted is the

time taken for the pressure in the pipeline to reach the design pressure of 150 barg.

Table 1-6 Time to pressurise to assumed Hewett arrival pressure and pipeline design pressure

Flowrate (te/d)


assumed arrival 79 barg

Design pressure 150 barg

Difference

6600 397 422 25

26400 112 120 8

If the line is pressurised at the full flow scenario power plant capacity of 26400 te/d then the wells must be opened within 8 hours of reaching the assumed Hewett arrival pressure upstream of the manual chokes of 79barg or the flow into the pipeline must be stopped to avoid exceeding the pipeline design pressure.

1.4. Ramp Up

Following a period of low turndown (assumed for this study to be 25% of normal flow) it will be necessary to resume normal injection rates. If flow into a pipeline is suddenly increased there is the potential to cause instability in the system.

For vapour phase operation, it was found that a significant length of time was required for the system to reach steady state following a ramp-up. For both 2.1 and 29.5 barg reservoir pressure cases the system took c. 220 hrs / 9 days to achieve a steady state mass balance with no accumulation

2. There were no instabilities observed when ramping up.

Some instability was observed in early dense phase operation (reservoir pressure 45.4 barg) when the system was ramped up. This was found to be due to liquid formation downstream of the Hewett chokes, however it was demonstrated that this effect could be minimised by employing additional heating during ramp-up. There was no such instability observed in later dense phase operation (reservoir pressure 157.5 barg), when the wellbore operated in dense phase (c.f. vapour phase for early dense phase operation). It is however recommended that further investigation into the stability of both the wellbore itself and the heater model within Olga be performed in more detail.

1 The PCV setpoint of 79 barg is specified a small margin above the critical pressure of 73 barg therefore the PCV

setpoint will be reached slightly after the pipeline becomes liquid-filled.

2 As noted in section 3.3 this will likely be optimistic due to simplified modelling of the pressure control at Hewett.


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1.5. Uncertainties and Recommendations

It is recommended that research or validation work be performed to determine if the following effects are genuine phenomenon of modelling anomalies:

Vaporisation of condensed liquid during line pack for vapour phase operation (section 1.2.1 and 4.2, also relevant for section 5.2 phase transition)

Instability of dense phase wellbore during ramp-up (section 1.4 and 6.3)


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2. Scope of Work

2.1. Description of System

The system is detailed in Figure 2-1:

Figure 2-1 System schematic

The carbon dioxide (CO2) which originates from the proposed new coal-fired power station at Kingsnorth on the Isle of Grain is planned to be delivered via a pipeline to the depleted Hewett gas field for carbon dioxide disposal in the Lower Bunter reservoir (30 km off the Norfolk coast).

The project is proceeding on the basis that the pipeline will be routed directly from Kingsnorth to the Hewett field (c. 6 km onshore pipeline followed by c. 270 km offshore pipeline).

2.2. Operating Scenarios

The pipeline will operate in the vapour phase during the demonstration period, up to a maximum practical pipeline inlet pressure of c. 39 barg (higher pipeline inlet pressures will result in two phase flow at the minimum seabed temperature of 4°C). Following this the pipeline will switch to dense phase operation, with the arrival pressure at Hewett controlled to 79 barg. The switch to dense phase operation is presumed to coincide with an increase in power plant capacity from 400 MWg (6600 te/d CO2) to 1600 MWg (26400 te/d CO2). These two modes of operation are referred to as base case and full flow scenarios respectively, summarised in Table 2-1 below.


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Table 2-1 Description of Base Case and Full Flow Scenarios

Parameter Base Case Scenario Full Flow Scenario

Pipeline operating phase Vapour Dense

CO2 flowrate (te/d) 6,600 26,400

Pipeline inlet pressure (barg) <39 c. 87

Choking at Hewett None 79 barg U/S choke

Heating at Hewett None Single phase in wellbore

and ≥0°C at wellhead

A third scenario considered in flow assurance analyses is the maximum capacity scenario. This involves operating the pipeline in dense phase at its maximum hydraulic capacity. However, as this scenario is not sufficiently defined, it will not be considered in this pipeline operating philosophy.

Note that the previous steady state analysis assumed a CO2 flowrate of 6700 te/d for a 400 MWg power plant (thus 26,800 te/d for a 1600 MWg plant); this has since been revised to 6600 te/d (Ref Error! Reference source not found.). This study, and all future flow assurance studies, will assume a CO2 flowrate of 6600 te/d for a 400 MWg power plant (hence 26,400 te/d for a 1600 MWg plant).

The operating scenarios have been described in previous steady state simulations; details of base data are provided in Refs [1] and [2]. The four cases considered further in the transient analysis are summarised in Table 2-2.

Table 2-2 Transient Analysis Cases

Reservoir pressure psia


Scenario Pipeline operating

phase

45 2.1 Base case Vapour

443 29.5 Base case Vapour

673 45.4 Full flow Dense

2299 157.5 Full flow Dense

2.3. Scope of Study

This study will examine the following start-up scenarios for the cases described in Table 2-2 above:

Line pack upon shutdown of Hewett

Transition from vapour phase to dense phase operation

Ramp up from 25% turndown to 100% production

The analysis will cover the cases through field life defined in Table 2-2 above.


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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 1.

3.1. Ramp up rate

A ramp up / ramp down rate of 32 MWe per minute has been assumed for the cooldown and start-up simulations. As the base case power output is 300 MWe (400 MWg), the time required to ramp up from 25% to 100% flow is therefore 7 minutes for the base case scenario. Similarly the full flow power output is 1200 MWe (1600 MWg) thus the time to ramp up from 25% to 100% flow is 28 minutes for the full flow scenario. A linear ramp down / ramp up was assumed.

It is acknowledged that power production ramp-up is not the ideal proxy for the carbon dioxide compression ramp-up. There will be a significant delay between boiler fuel consumption and power output increase however in the absence of a better proxy, it will be assumed that the ramp up rate is similar to the power production ramp up rate, but with an unknown time delay.

3.2. Heater Setpoints

Heater setpoints for normal dense phase operation (with the heaters upstream of the chokes) are as follows:

Table 3-1 Heater setpoints for steady state operation

Reservoir pressure Heater setpoint

Psia Barg °C

673 29.5 52

2299 157.5 33

3.3. Pressure Control at Hewett

The flow to each of the twelve wells during dense phase operation will be controlled individually with manual remotely-operated chokes, such that the pressure is also maintained at a suitable margin above the critical pressure of 74 barg to ensure the pipeline is maintained in single, dense phase. A 5 bar margin above the critical pressure was assumed for the purpose of this study. It is not practical to model 12 manual chokes within Olga and thus a pressure controller was utilised to specify a target arrival pressure at Hewett (upstream of the wellhead chokes) of 79 barg. A pressure controller will clearly result in a smoother return to


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steady state following disturbances than can be achieved using manual chokes and thus the times taken to reach steady state quoted in this report will be overly optimistic.

3.4. Reporting of Results

There are a number of locations referred to in this report; these are illustrated in Figure 3-1 overleaf.


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Figure 3-1 Schematic of Olga Model


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4. Line Pack

4.1. Introduction

During periods when the injection wells are unavailable, for example due to maintenance, it may be desirable to maintain flow into the pipeline. This will cause the pipeline to pressurise, known as “line packing”. When the pipeline is operating in vapour phase, the increase in pressure will cause the vapour to condense to liquid. When the pipeline is operating in dense phase mode the pressure will increase much more rapidly as more CO2 is introduced into the pipeline, since dense phase CO2 is much less compressible than vapour phase CO2.

Production rates from Kingsnorth of 100% and 25% of normal flow were considered, as a common method of mitigating against rapid pressure rises during line packing is to reduce the flow into the pipeline. A turndown of 25% was selected as per the Options Review Workshop Report.

Three reservoir pressure cases were considered: the 2.1 barg and 29.5 barg reservoir pressure cases for vapour phase operation life and the 45.4 barg case for dense phase operation. The 29.5 barg reservoir pressure case is discussed in more detail in the phase transition analysis, whereby the system is line-packed in order to change from vapour phase to dense phase operation. For dense phase operation, only one case was considered as the simulations would be identical for all three cases, which have identical pressure and temperature profiles in the pipeline (it is only the profiles downstream of the chokes which differ).

The CO2 flow rates and corresponding power station outputs considered are summarised in Table 4-1 below.

Table 4-1 CO2 Flow Rates at 100% and 25% Kingsnorth Capacity

Scenario CO2 flow rate (te/d) Power station output (MWe)

100% 25% 100% 25%

Base Case 6600 1650 300 75

Full Flow 26400 6600 1200 300

The chokes at Hewett were closed and the line pressurised by maintaining flow from Kingsnorth. It was assumed for the purposes of this study that all the Hewett chokes close simultaneously, as this gives the most conservative pressurisation times. For the 25% turndown cases it was assumed that production from Kingsnorth was ramped down at a rate of 32 MWe per minute, as described in section 3.1, beginning at the time the chokes were closed.


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4.2. Base Case Vapour Phase Operation

As the pressure increases in the pipeline the dew point pressure will be reached. This causes liquid to form within the system. The time at which this occurs depends on whether the topsides piping is heat traced. If no heat tracing is utilised then the topsides piping, which is exposed to a worst case ambient temperature of -6°C

3, will quickly reach dew point. If heat

tracing is utilised to maintain the fluid at 4°C this will significantly extend the period of time for which the CO2 within the system is completely vapour phase. The time taken to form liquid in the topsides piping (ambient temperature -6°C) and subsea flowline (ambient temperature 4°C) are tabulated below:

Table 4-2 Time taken to condense first liquid during linepack (2.1 barg RP)

Heat tracing Time until first liquid formation (hr)

100% flow 25% turndown

Without heat tracing 16 41

Heat tracing on topsides pipework 34 135

It should be noted that, although the pipeline routing assumed in the flow assurance studies may be slightly superseded, any minor changes to the routing are unlikely to have any significant effect on the time taken to condense bulk liquid in the pipeline. Any liquid formed will drain to low points in the system; this will occur regardless of the routing. The impact on the pressure and temperature profiles will be negligible and thus the bulk condensation times will be largely unaffected.

However, following this initial condensation, the small volume of liquid evaporates prior to bulk condensation of the pipeline contents. The total liquid content, shown as a percentage of the pipeline volume, is provided in Figure 4-1. It is not clear whether this is a genuine phenomenon or a modelling difficulty, as it is known that simulation results are less reliable in the near-critical region. Upon closer inspection of the results, the vapourisation coincides with a step increase in pressure and temperature in the pipeline. There are also step changes in pressure and temperature earlier in the simulation, coinciding with the decreases in liquid content visible in Figure 4-1 below. Pressure trends are shown in Figure 4-2. It is not clear why pressurisation should occur in a step-wise manner; it is recommended that this be examined in more detail during front end or detailed design, to determine whether it is a genuine effect or a modelling anomaly.

3 For the purposes of the flow assurance studies, a minimum air temperature of -6°C was assumed. The ambient

temperature will normally be higher than -6°C.


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Figure 4-1 Liquid content during linepack – 2.9 barg reservoir pressure

The liquid content in the pipeline generally increases with time from the first liquid condensation at 34 hours then falls back to near zero prior to significant condensation occurring. The reason for this is not entirely clear, however the P-T trends for most positions in the flowline show movement around the dew line as the pressure increases. Bulk condensation of the CO2 then occurs, whereby the hold up in the pipeline increases to 100% at low points and then to the remainder of the flowline. The time at which this begins to occur is shown in Table 4-3.

Table 4-3 Time taken to condense bulk liquid during linepack (2.1 barg RP)

Heat tracing Time until bulk liquid formation (days)

100% flow 25% turndown

Without heat tracing 8 >20 (1)

Heat tracing on topsides pipework 8 >20 (1)

Significant liquid condensation had yet to occur at the end of an extended 20-day simulation

It should however be noted that the pressure required to achieve this level of condensation may be in excess of the maximum pressure that can realistically be delivered by the Kingsnorth compressor for the base case scenario

4. The pressures at the pipeline inlet,

160km distance and arrival at Hewett are shown vs. time in Figure 4-2.

4 The design of the compression plant has not been completed at this pre-FEED stage of the

project.


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Figure 4-2 Pressure Trends during Linepack – 2.1 barg RP case

The maximum discharge pressure of the compressor during vapour phase operation is not known, however it is currently assumed that a compressor will be specified for vapour phase duty (i.e. up to c. 40 bar) and this will be upgraded with further stages of compression for the full flow scenario. Therefore it may not be possible in reality to pressurise the flowline to such an extent that it becomes liquid-filled.

The times to condense liquid in the pipeline are compared below for the 2.1 and 29.5 barg reservoir pressure cases (29.5 barg reservoir pressure results are extracted from the phase transition results – section 5) in Table 4-4 for 100% base case flowrate of 6600 te/d and assuming insulation to maintain 4°C in the topsides pipework. The greater the reservoir pressure the greater the initial back-pressure in the pipeline and thus liquid will condense sooner.

Table 4-4 Comparison of liquid formation time for 2.1 and 29.5 barg reservoir pressures


Time from closing Hewett chokes (hrs)

First liquid formation Bulk liquid formation

2.1 16 201

29.5 13 183


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4.3. Full Flow Dense Phase Operation

For dense phase operation, the pipeline is already operating in the dense phase prior to line packing, thus the additional CO2 introduced will cause the pressure to increase more rapidly than for vapour phase operation as dense phase CO2 is less compressible than vapour phase CO2. The time taken to increase the pressure at the pipeline inlet from normal operating pressure (87 barg at 100% flow, 81 barg at 25% flow) to the design pressure of 150 barg is shown in Table 4-5. Also shown are the times taken to reach the alternative design pressures of 120 barg and 200 barg, which are considered as sensitivity cases in this project.

Table 4-5 Time taken to pressurise dense phase pipeline during line packing

Pressure (barg)

Time to reach pressure (hr)

100% flow 25% flow

120 2.4 15

150 4.4 26

200 7.5 40

It should be noted that the maximum discharge pressure of the compressor is likely to be less than the design pressure of the pipeline and thus the 150barg inlet pressure may not be achievable in practice. In spite of this, the calculated time of 4 hours for the inlet pressure to reach 150 barg does indicate that the system is only able to be line-packed for a short time of c. 4 hours before flow into the pipeline can no longer be sustained. Flow into the pipeline cannot continue once the inlet pressure of the pipeline reaches the maximum discharge pressure of the compressor; at this point the compressor would need to be shut down or put into recycle while the CO2 is vented or injection into the wells is resumed.

The length of time the line can be packed for increases significantly at low turndown - flow may continue for around one day at 25% turndown before the pipeline design pressure of 150 barg is approached.

The increase in pressure (measured at Kingsnorth) with time is compared below for 100% and 25% flow in Figure 4-3.


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Figure 4-3 Pressure during linepack, dense phase operation, 100% and 25% flow

The analysis above assumed winter conditions, with a minimum ambient air temperature of -6°C and minimum seabed temperature of 4°C. Were the line pack to occur during the summer, the maximum ambient air and seabed temperature would be 35°C and 17°C respectively. At 17°C the dew point pressure of carbon dioxide is 52 barg while at 35°C CO2 exists as a vapour or supercritical fluid, depending on the pressure. Therefore the contents of the pipeline would not begin to condense until the higher pressure of 52 barg (vs. 39 barg for ambient temperature of 4 °C) had been reached. The line will therefore be able to be packed for a longer time before liquid is formed.

The potential exists, however, for the combination of summer water temperature and autumn/winter air temperature, for example during an autumn frost. This would result in liquid formation in the Hewett topsides pipework which would then condense and free drain to the subsea pipeline. The subsea pipeline would be at a higher temperature due to the warm seawater and so the liquid CO2 would be re-vaporised. A reflux cycle would be established; the only way to avoid this would be to heat trace the topsides pipework to the temperature of the seabed – worst case 17°C.

Hewett chokes closed


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5. Transition from Vapour Phase to Dense Phase

5.1. Introduction

As the pipeline inlet pressure at Kingsnorth increases it will become necessary to change from vapour phase operation of the pipeline to dense phase operation, to avoid the potential for operating with two phase vapour/liquid flow. At the minimum winter sea bed temperature of 4°C the dew point pressure of CO2 is 39 barg and so operating at pressures above this will likely result in two phase flow in the pipeline. Therefore when the inlet pressure in the pipeline approaches 39 barg it is planned to switch to dense phase operation, whereby the pressure of the CO2 will be maintained at a 79 barg arrival pressure at Hewett, corresponding to an inlet pressure at Kingsnorth of 87 barg (Ref 0). The assumed mechanism for changing from vapour phase to dense phase liquid operation by packing the line followed a similar methodology to the line pack simulations described in section 4, whereby the chokes at Hewett are closed while CO2 continues to flow into the pipeline from Kingsnorth, packing the line. The 443 psia / 29.5 barg reservoir pressure case was used as a basis, with inlet flows of 6600 te/d (base case) and 26400 te/d (full flow) considered.

5.2. Liquid Formation

As per the vapour phase linepack simulations (section 4.2), it was found that a relatively small volume of liquid formed in the pipeline and was subsequently re-vaporised prior to the bulk condensation of the CO2, as shown below

5. The times taken for initial liquid formation and

significant bulk liquid formation to occur are tabulated in Table 5-1 and illustrated in Figure 5-1. Of more significance is with the time taken for the pipeline to become entirely liquid-filled, from which point the pressure starts to increase more rapidly.

Table 5-1 Time to fill pipeline with liquid during phase transition (29.5 barg RP)

Flowrate te/d


First liquid formation

Bulk liquid formation

Pipeline liquid-filled

6600 13 183 393

26400 2 46 111

It should be noted that the times above for first liquid formation refer to liquid formation in the subsea pipeline (ambient temperature 4°C) - liquid will form in the topsides section (worst case ambient temperature of -6°C) prior to this unless heat tracing is utilised.

5 It is not clear whether this is a genuine phenomenon or a modelling anomaly; this has been discussed in section

4.2.


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The pipeline will take a significant length of time to become liquid-filled i.e. transition from vapour to dense liquid phase. The time required is c. 16 days for base case flow of 6600 te/d and c. 5 days for full flow of 26400 te/d.

Figure 5-1 Pipeline Liquid Content for CO2 Flow Rates of 6600 and 26400 te/d

5.3. Pressure Trends

The time at which the pressure at the Hewett platform reaches 79 barg, the assumed normal arrival pressure upstream of the manual chokes at Hewett, is shown in Table 5-2. Also noted is the time taken for the pressure in the pipeline to reach the design pressure of 150 barg.

Table 5-2 Time to pressurise to assumed 79 barg arrival pressure at Hewett and pipeline design pressure of 150 barg

Flowrate (te/d)


Assumed arrival 79 barg

Design pressure 150 barg

Difference

6600 397 422 25

26400 112 120 8

Hewett chokes closed


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It can be seen from the above table that there is a relatively short time of 8 hours between reaching the assumed Hewett arrival pressure of 79 barg and the design pressure of 150 barg if the line is packed at a rate of 26400 te/d (1600MWg power plant output). Therefore if the line is pressurised at the full power plant capacity of 26400 te/d then the wells must be opened within 8 hours of reaching the assumed normal Hewett arrival pressure of 79barg or the flow into the pipeline must be stopped to avoid exceeding the pipeline design pressure.

If the line is pressurised at the base case flowrate of 6600 te/d (400 MWg power plant output), the line may be packed for a further 25 hours / 1 day once the assumed arrival pressure at Hewett is reached before the design pressure is exceeded.

As discussed for dense phase line packing (section 4.3), it should be noted that it may not be feasible in reality to reach the pipeline design pressure, depending on the maximum discharge pressure of the Kingsnorth compressor.

The pressure trends are compared below for flows of 6600 te/d and 26400 te/d. For both cases the pressure increases while the pipeline is still in vapour phase. While the CO2 condenses from vapour to liquid the rate of pressure increase is very low then, when the pipeline is liquid filled, the additional inflow of CO2 results in a rapid pressure rise as the CO2 is now much less compressible.

Figure 5-2 Max Pressure in Pipeline for CO2 Flow Rates of 6600 and 26400 te/d


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5.4. Temperature Trends

No excessively high or low temperatures are encountered during the line-pack. The arrival temperature at the Hewett platform when the set pressure of 79 barg is reached is c. 28-29°C for both line pack rates. This is higher than the normal arrival temperature of c. 4°C and so a lower heater duty will initially be required to maintain the fluids in the wellbore in single phase when the chokes are opened. As injection is resumed the arrival temperature at Hewett will decrease due to heat loss from the subsea pipeline and the required heating duty at Hewett will increase to that of normal operation. The temperatures at key locations in the system are shown in Appendix 2 Phase Transition Results.

When the arrival pressure at Hewett increases to 28-29°C the temperature in the onshore and offshore pipelines also increase such that the majority of the system is at a temperature of around 30°C. This should have minimum additional influence on the environment, as the majority of the onshore pipeline operates at around 30°C during normal operation. Similarly there is assumed to be negligible influence on the environment for the offshore pipeline as it is uninsulated and exposed to the seawater.


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6. Ramp-up

6.1. Introduction

Following a period of low turndown (assumed for this study to be 25% of normal flow) it will be necessary to resume normal injection rates. If flow into a pipeline is suddenly increased there is the potential to introduce a disturbance into the system. The ramp-up rate of the power plant is 32 MWe per minute and so the equivalent ramp-up of CO2 flow rate was calculated to be c. 8.2 kg/s per minute (300 MWe is equivalent to 6600 te/d).

6.2. Vapour Phase Operation

For vapour phase operation, it was found that a significant length of time was required for the operating conditions (pressure, temperature, mass flow) to reach those of normal operation following a ramp-up. For both 2.1 and 29.5 barg reservoir pressure cases the system took c. 220 hrs / 9 days to achieve a steady state mass balance with no accumulation. There were no instabilities observed when ramping up. The mass flow at various positions in the system are shown for the 2.1 barg reservoir pressure case in Figure 6-1 below. Full results can be found in Appendix 2 Phase Transition Results.

Figure 6-1 Mass flow during ramp-up: 2.1 barg reservoir pressure case

Superimposed trends


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6.3. Dense Phase Operation

Reservoir pressures of 45.4 and 157.5 barg (673 and 2299 psia) were considered for dense phase operation, i.e. mid and late field life respectively. The 157.5 barg case, which had exhibited some fluctuations prior to the ramp-up, stabilised very quickly after the Kingsnorth flow was ramped up. The action of the chokes at Hewett helps to establish steady state quicker than for vapour phase operation

6. The system took c. 36 hrs / 1.5 days to achieve a

steady state mass balance with no accumulation though it should be noted that, due to simplified modelling of the pressure control utilised in Olga it will take longer to reach steady state in reality than was achieved in Olga. The pressure control at Hewett was modelled in Olga using a pressure controller, whereas in reality the arrival pressure at Hewett is proposed to be controlled using twelve individual remotely operated manual chokes thus it will take longer to reach steady state in reality with manual choking rather than the automatic pressure control modelled in Olga.

Conversely for the 45.4 barg reservoir pressure case, which was relatively stable prior to ramp-up, significant instability was displayed when the flow was ramped up. Unlike the 157.5 barg case, which operates with the entire system above the critical pressure, the 45.4 barg case operates with the pipeline in dense phase and the wells (i.e. all piping and tubing downstream of the Hewett chokes) in vapour phase. Upon examining the P-T profiles of the 45.4 barg case the wellbore can be seen to operate around the dew point line, which is causing instability in the system due to liquid formation.

Two alternative methods of stabilising the system were investigated:

increasing the heater setpoint (to move the operating conditions away from the dew point)

decreasing the ramp-up rate (to reduce the rate of change to the system)

It was found that increasing the heater outlet temperature significantly reduced the oscillations in the system while decreasing the ramp up rate had a very limited effect on the system stability, as liquid was still formed downstream of the Hewett choke. It is therefore recommended that the heater setpoint is increased during ramp-up for dense phase operation when the wellbore is operating in the vapour phase.

6.3.1. Increasing Heater Setpoint

The heater outlet temperature was increased from the normal setpoint of 52°C for normal operation to 60°C, the setpoint assumed for pressurised start-up. Increasing the heater setpoint significantly reduces the fluctuations in flowrate at the Hewett platform, as illustrated below: the mass flow rates at arrival at Hewett (up-val), heater outlet (heater-outlet) and downstream of the choke (dwn-val) are compared for heater outlet temperatures of 52°C (Figure 6-2) and 60°C (Figure 6-3).

6 There were no instabilities observed utilising a pressure controller at Hewett. It is assumed that the manual

controllers would be opened at a suitable speed to avoid introducing significant disturbances into the system.


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Figure 6-2 Mass flows at Hewett during ramp-up, heater setpoint 52°C, 45.4 barg RP

Figure 6-3 Mass flows at Hewett during ramp-up, heater setpoint 60°C, 45.4 barg RP


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The P-T trend at the position immediately downstream of the Hewett chokes is plotted in Figure 6-4 as a function of time for both heater outlet temperatures. This clearly shows that the P-T conditions have moved sufficiently far away from the dew line to prevent liquid formation downstream of the Hewett choke. The 52°C heater outlet temperature model is unstable, with the fluid downstream of the choke fluctuating between liquid and vapour phase. The 60°C heater outlet temperature model initially starts near the dew point but as the heater outlet temperature is increased the fluid downstream of the choke moves further away from the dew point line and into the vapour phase, avoiding the problems associated with two-phase flow.

Figure 6-4 P-T Trend Downstream of Hewett Choke for Heater Setpoints 52°C and 60°C

setpoint 52°C

setpoint 60°C

Beginning of simulation

End of simulation


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6.3.2. Decreasing Ramp-up Rate

The ramp-up rate assumed in the simulations was equivalent to 32 MWe per minute, which is equal to the ramp-up rate of the Kingsnorth power plant. Therefore for dense phase operation the ramp-up occurs over a period of 28 minutes (25% and 100% of full flow is equivalent to 300 MWe and 1200 MWe respectively). This was increased by a factor of four such that the ramp-up occurred over a period of four hours i.e. 7.5 MWe per minute.

Decreasing the ramp-up rate had some effect on reducing the magnitude of fluctuations in flow at the platform, though not as significantly as increasing the heater setpoint. The mass flows at the Hewett platform are shown in Figure 6-5; these can be compared with the original ramp up rate shown in Figure 6-2. Upon checking the P-T trend at the position dwn-val it was observed that there is still liquid formed downstream of the Hewett choke valve, thus the instability remains in system.

Figure 6-5 Mass flows at Hewett during ramp-up at 7.5 MWe/min


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6.3.3. Wellbore Instabilities

Instability in the wellbore was also observed for the 45.4 barg reservoir pressure case (and also the 29.5 barg reservoir pressure case) during the cooldown simulations, due to convective counterflow in the wellbore. This is discussed in the Start-up analysis (Ref[3]). The mass flow trend for this cooldown case is shown in Figure 6-6. It is therefore possible that the wellbore has a tendency for instability during transient operations at this reservoir pressure.

Figure 6-6 Mass Flows during Cooldown Simulation, 45.4 barg Reservoir Pressure


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6.3.4. Olga Uncertainties

Although increasing the heater setpoint has been shown to improve the stability of the model, it should be borne in mind that the Olga heater model was shown to be problematic in earlier flow assurance work for this project. The temperature at the position immediately downstream of the heater is plotted in Figure 6-7 (only the beginning of the simulation is shown for clarity). It can be seen to fluctuate significantly and often fall below the set point of 52°C.

Figure 6-7 Heater Outlet Temperature Trend during Ramp-up, 45.4 barg RP

Therefore, while the instabilities observed in the model may be genuine wellbore instabilities, the potential that the instability is a feature of the Olga model which would not be observed in real life should be considered.


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7. References

[1] Kingsnorth Basis of Design for Studies – Phase 1A, KCP-GNS-PCD-STU-0001, Rev 01, April 2010

[2] Steady State Analysis (Pipeline), KCP-GNS-FAS-DRP-0002 Rev A1, May 2010

[3] Transient Analysis – Start Up (Pipeline), KCP-GNS-FAS-DRP-0003_02,June 2010


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8. Appendix 1 Line Pack Results

8.1. Vapour Phase Operation, 25% Turndown

Figure 8-1 Pressure Trends during Line Pack, 2.1 barg RP, 25% Turndown

Figure 8-2 Temperature Trends during Line Pack, 2.1 barg RP, 25% Turndown


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8.2. Vapour Phase Operation, 100% Flow

Figure 8-3 Pressure Trends during Line Pack, 2.1 barg RP, 100% Flow



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8.3. Dense Phase Operation, 25% Turndown

Figure 8-5 Pressure Trends during Line Pack, 45.4 barg RP, 25% Turndown

Figure 8-6 Temperature Trends during Line Pack, 45.4 barg RP, 25% Turndown


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8.4. Dense Phase Operation, 100% Flow


Figure 8-8 Temperature Trends during Line Pack, 45.4 barg RP, 100% Flow


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9. Appendix 2 Phase Transition Results

9.1. Base Case Scenario 400 MWg Flowrate 6600 te/d

Figure 9-1 Pressure Trends during Phase Transition, 29.5 barg RP, 6600 te/d

Figure 9-2 Temperature Trends during Phase Transition, 29.5 barg RP, 6600 te/d


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9.2. Full Flow Scenario 1600 MWg Flowrate 26400 te/d

Figure 9-3 Pressure Trends during Phase Transition, 29.5 barg RP, 26400 te/d

Figure 9-4 Temperature Trends during Phase Transition, 29.5 barg RP, 26400 te/d


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10. Appendix 3 Ramp Up Results

10.1. Vapour Phase Operation

Figure 10-1 Pressure Trends during Ramp-up, 2.1 barg RP

Figure 10-2 Temperature Trends during Ramp-up, 2.1 barg RP


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10.2. Dense Phase Operation




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6.32 Transient Analysis Ramp Up and Line Pack (Pipeline)

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