Choke Sizing

Choke calculations Choke calculations are performed for Dagny subsea case 2A for the forecast production in years 2015 to 2019. The choke is assumed to be non collapsible labyrinth type choke. Worst case scenario mal operation is based on start-up with gas filled riser from maximum pressure with fully open choke. The choke calculations are based on not exceeding the capacity of three of the four installed PSV’s on the inlet separator when the choke is mal operated. The PSV`s capacity is calculated for each case using HEM-method. The capacity is dependent on relieving pressure, temperature and composition. KO drum and flare capacity checks are not performed. The choke CV will control the pressure drop over the choke and the maximum pressure u/s choke in order to not exceeding the PSV`s capacity. A low CV will give high pressure drop over the choke and a high maximum pressure u/s the choke in a choke mal operation scenario, the opposite with a high choke CV. In a normal choke calculations, shut-in pressure is used as the pressure u/s choke in a choke mal operation scenario. But because the choke size would be low and the pressure drop too high, the pressure u/s choke must be reduced with an active shutdown function on the wells and topside EV. Then the pipeline settle-out pressure can be used as the pressure u/s choke in a choke mal operation scenario. The settle out pressure can be found using formula 1.1 below which gives an approximation to the real settle out pressure. Pipeline simulations are done in HYSYS for pressure drop calculations.

subseaPAHHpressuredispatchSLAp

topsidePAHHepressurarrivalSLAp

pressureoutsettlep

where

pppp

,

,

:3

2

2

1

121

(1.1)

There will be no production if the required pipeline inlet pressure during normal operation is greater than subsea PAHH set pressure.

Figure 1-1: Simulation model

Finding the optimal choke CV is not easy in this case because the wellhead pressure is decreasing fast while the production is increasing from start-up in year 2015 to year 2017. Also the production profile is based on 5 bar pressure drop over the topside choke, which is low in year 2016 and year 2017. See graph 1-1 and table 1-1 below.

Graph 1-1: (Statoil) Flowing wellhead pressure for each well in year 2015 and year 2016. In this period the wellhead pressure will be higher than required pipeline inlet pressure. Table 1-1: (Statoil) Results from OLGA simulations of Dagny – SLA pipeline with corresponding production profile. It is assumed 5 bar pressure drop over the topside choke. The production profile will be altered if the pressure drop over the choke is grater then 5 bara after year 2017 and partly in year 2016. Pressure SLA Flowrate oil (Sm³/d) Flowrate gas (Sm³/d) Pressure Dagny Temperature SLA

2015 95 9000 2.1 114 722016 95 10200 4.3 125 792017 95 12000 6.0 157 872018 40 5644 5.0 100 702019 40 8000 3.4 101 742020 40 5706 4.1 110 712021 40 3865 3.7 106 672022 40 2634 3.2 88 622023 15 1864 4.0 85 51

Three solutions for choke operation are developed, where none of them is an optimal solution. See Appendix A, B and C. The first alternative is based on changing the choke in year 2016, 2017 and year 2018. The new choke CV for each year is based on having 5 bar pressure drop over the choke when the choke is changed. Since the production is increasing from start-up to 2017, the pressure drop over the choke will increase until next choke change. Appendix A shows the estimated increase in pressure drop in-between the choke changes. The pressure drop is estimated based on interpolating on actual total flow through the choke and assuming that the production is constantly increasing between each year. Alternative two and three are outer limits with choke internal change in year 2018. Alternative two is based on having a high subsea PSHH set pressure and high pressure drop over topside choke under normal operation. Alternative 3 is based on having a maximum of 5 bar pressure drop over the topside choke. Subsea PSHH set pressure is close to required pipeline inlet pressure in alternative 3. In all three alternatives the choke must be changed in year 2018 when the operating pressure in inlet separator is reduced to 35 bara. The optimal solution will probably be a compromise between alternative 2 and 3 where we accept 10 bar pressure drop over the choke in year 2017. This will give a better margin between pipeline inlet pressure and subsea PSHH set pressure, but the Dagny will have a reduced production in year 2016 and 2017 due to increased pipeline outlet pressure. Appendix Appendix A Overview over the different alternatives with dp over choke, choke CV,

settle out pressure and PSHH subsea set pressure Appendix B Results from choke calculations Appendix C Sketches showing wellhead pressure, requires pipeline dispatch pressure,

PSHH set pressure and topside choke pressure drop for alternative 1 and 3 in year 2015 to year 2019.

Appendix A

Simulation PAHH Simulation PAHH Simulation PAHHOil Gas actual flow Subsea Oil Gas actual flow Subsea Oil Gas actual flow Subsea

Year Month Sm³/d MSm³/d m³/h CV bara bara Year Month Sm³/d MSm³/d m³/h CV bara bara Year Month Sm³/d MSm³/d m³/h CV bara bara2015 11 9000 2,117 1031 5,0 320 225 228 2015 11 9000 2,117 1031 5,0 320 225 228 2015 11 9000 2,117 1031 1,0 764 147 1512015 12 1159 6,3 - - - 2015 12 1159 6,3 - - - 2015 12 1159 1,3 - - -2016 1 1287 7,7 - - - 2016 1 1287 7,7 - - - 2016 1 1287 1,5 - - -2016 2 1415 9,0 - - - 2016 2 1415 9,0 - - - 2016 2 1415 1,8 - - -2016 3 1543 10,3 - - - 2016 3 1543 10,3 - - - 2016 3 1543 2,0 - - -2016 4 1671 11,7 - - - 2016 4 1671 11,7 - - - 2016 4 1671 2,3 - - -2016 5 1799 13,0 - - - 2016 5 1799 13,0 - - - 2016 5 1799 2,5 - - -2016 6 1927 14,3 - - - 2016 6 1927 14,3 - - - 2016 6 1927 2,8 - - -2016 7 2055 15,7 - - - 2016 7 2055 15,7 - - - 2016 7 2055 3,0 - - -2016 8 10200 4,293 2183 5,0 607 157 168 2016 8 10200 4,293 2183 17,0 - 219 - 2016 8 10200 4,293 2183 3,3 - 148 1592016 9 2268 5,6 - - - 2016 9 2268 17,7 - - - 2016 9 2268 3,4 - - -2016 10 2353 6,3 - - - 2016 10 2353 18,3 - - - 2016 10 2353 3,6 - - -2016 11 2438 6,9 - - - 2016 11 2438 19,0 - - - 2016 11 2438 3,7 - - -2016 12 2523 7,5 - - - 2016 12 2523 19,7 - - - 2016 12 2523 3,9 - - -2017 1 2608 8,2 - - - 2017 1 2608 20,3 - - - 2017 1 2608 4,0 - - -2017 2 2693 8,8 - - - 2017 2 2693 21,0 - - - 2017 2 2693 4,2 - - -2017 3 2779 9,5 - - - 2017 3 2779 21,7 - - - 2017 3 2779 4,3 - - -2017 4 2864 10,1 - - - 2017 4 2864 22,3 - - - 2017 4 2864 4,4 - - -2017 5 2949 10,7 - - - 2017 5 2949 23,0 - - - 2017 5 2949 4,6 - - -2017 6 3034 11,4 - - - 2017 6 3034 23,7 - - - 2017 6 3034 4,7 - - -2017 7 3119 12,0 - - - 2017 7 3119 24,3 - - - 2017 7 3119 4,9 - - -2017 8 12000 6,000 3204 5,0 764 147 164 2017 8 12000 6,000 3204 25,0 - 233 235 2017 8 12000 6,000 3204 5,0 - 147 1642017 9 3157 4,9 - - - 2017 9 3157 24,6 - - - 2017 9 3157 4,9 - - -2017 10 3110 4,9 - - - 2017 10 3110 24,3 - - - 2017 10 3110 4,9 - - -2017 11 3062 4,8 - - - 2017 11 3062 23,9 - - - 2017 11 3062 4,8 - - -2017 12 3015 4,7 - - - 2017 12 3015 23,5 - - - 2017 12 3015 4,7 - - -2018 1 2968 4,6 - - - 2018 1 2968 23,1 - - - 2018 1 2968 4,6 - - -2018 2 2921 4,6 - - - 2018 2 2921 22,8 - - - 2018 2 2921 4,6 - - -2018 3 2873 4,5 - - - 2018 3 2873 22,4 - - - 2018 3 2873 4,5 - - -2018 4 2826 4,4 - - - 2018 4 2826 22,0 - - - 2018 4 2826 4,4 - - -2018 5 2779 4,3 - - - 2018 5 2779 21,7 - - - 2018 5 2779 4,3 - - -2018 6 2732 4,3 - - - 2018 6 2732 21,3 - - - 2018 6 2732 4,3 - - -2018 7 2684 4,2 - - - 2018 7 2684 20,9 - - - 2018 7 2684 4,2 - - -2018 8 5644 5,023 5667 5,0 537 93 107 2018 8 5644 5,023 5667 5,0 537 93 107 2018 8 5644 5,023 5667 5,0 537 93 1072018 9 5515 4,8 - - - 2018 9 5515 4,8 - - - 2018 9 5515 4,8 - - -2018 10 5364 4,7 - - - 2018 10 5364 4,7 - - - 2018 10 5364 4,7 - - -2018 11 5213 4,5 - - - 2018 11 5213 4,5 - - - 2018 11 5213 4,5 - - -2018 12 5061 4,3 - - - 2018 12 5061 4,3 - - - 2018 12 5061 4,3 - - -2019 1 4910 4,2 - - - 2019 1 4910 4,2 - - - 2019 1 4910 4,2 - - -2019 2 4758 4,0 - - - 2019 2 4758 4,0 - - - 2019 2 4758 4,0 - - -2019 3 4607 3,8 - - - 2019 3 4607 3,8 - - - 2019 3 4607 3,8 - - -2019 4 4455 3,7 - - - 2019 4 4455 3,7 - - - 2019 4 4455 3,7 - - -2019 5 4304 3,5 - - - 2019 5 4304 3,5 - - - 2019 5 4304 3,5 - - -2019 6 4153 3,3 - - - 2019 6 4153 3,3 - - - 2019 6 4153 3,3 - - -2019 7 4001 3,2 - - - 2019 7 4001 3,2 - - - 2019 7 4001 3,2 - - -2019 8 8000 3,435 3850 3,0 - 93 101 2019 8 8000 3,435 3850 3,0 - 93 101 2019 8 8000 3,435 3850 3,0 - 93 101

Pressure drop over choke interpolated on actual volume flow through topside chokeAlt 3: Minimizing choke internal changes, Low PAHHProduction profile Pressure

drop over choke

ChokeSettle out pressure

Production profile Pressure drop over

choke

Choke

Alt 1: Maintaining low pressure with choke internal changesSettle out pressure

Settle out pressure

Alt 2: Minimizing choke internal changes, High PAHHProduction profile Pressure

drop over choke

Choke

Appendix B

1 Choke CV with settle out pressure 225 bara 1 Pressure drop over choke when CV = 764CV 320 dp over choke 1,0 barPSV capacity 1086213 kg/hChoke mal operation 1086213 kg/h 2 Max settle out pressure when CV = 764 and PSV`s are full utilized

Settle out pressure 147 bara2 Pressure drop over choke when CV = 320 PSV capacity 1030364 kg/h

dp over choke 5 bar Choke mal operation 1030364 kg/h

3 PAHH from pipeline calculations 3 PAHH from pipeline calculationsPAHH sub sea 228 bara L = 30 km PAHH sub sea 151 bara L = 30 kmPAHH topside 219 bara U = 4 W/m² °C PAHH topside 140 bara U = 4 W/m² °CSettle out pressure 225 bara ID = 16 in Settle out pressure 147 bara ID = 16 in

1 Choke CV with 5 bara over choke 1 PAHH from pipeline calculations 1 Pressure drop over choke when CV = 764Min CV 607 PAHH sub sea 228 bara L = 30 km dp over choke 3,3 bar

PAHH topside 219 bara U = 4 W/m² °C2 Max settle out pressure when CV = 607 and PSV`s are full utilized Settle out pressure 219 bara ID = 16 in 2 Max settle out pressure when CV = 764 and PSV`s are full utilized

Settle out pressure 157 bara Settle out pressure 148 baraPSV capacity 1026721 kg/h 2 Pressure drop over choke when CV = 320 PSV capacity 1020506 kg/hChoke mal operation 1026721 kg/h dp over choke 17 bar Choke mal operation 1020506 kg/h

3 PAHH from pipeline calculations 3 Choke mal operation rate when CV = 320 and settle out pressure = 219 bara 3 PAHH from pipeline calculationsPAHH sub sea 168 bara L = 30 km PSV capacity 1069572 kg/h PAHH sub sea 159 bara L = 30 kmPAHH topside 135 bara U = 4 W/m² °C Choke mal operation 1028461 kg/h PAHH topside 125 bara U = 4 W/m² °CSettle out pressure 157 bara ID = 16 in Excess capacity 41111 kg/h Settle out pressure 148 bara ID = 16 in

1 Choke CV with 5 bara over choke 1 Pressure drop over choke when CV = 320 1 Choke CV with 5 bara over chokeMin CV 764 dp over choke 25 bar Min CV 764

2 Max settle out pressure when CV = 764 and PSV`s are full utilized 2 Max settle out pressure when CV = 320 and PSV`s are full utilized 2 Max settle out pressure when CV = 764 and PSV`s are full utilizedSettle out pressure 147 bara Settle out pressure 223 bara Settle out pressure 147 baraPSV capacity 1008409 kg/h PSV capacity 1059168 kg/h PSV capacity 1008409 kg/hChoke mal operation 1008409 kg/h Choke mal operation 1059168 kg/h Choke mal operation 1008409 kg/h

3 PAHH from pipeline calculations 3 PAHH from pipeline calculations 3 PAHH from pipeline calculationsPAHH sub sea 164 bara L = 30 km PAHH sub sea 235 bara L = 30 km PAHH sub sea 164 bara L = 30 kmPAHH topside 113 bara U = 4 W/m² °C PAHH topside 199 bara U = 4 W/m² °C PAHH topside 113 bara U = 4 W/m² °CSettle out pressure 147 bara ID = 16 in Settle out pressure 223 bara ID = 16 in Settle out pressure 147 bara ID = 16 in

1 Choke CV with 5 bara over chokeMin CV 537

2 Max settle out pressure when CV = 537 and PSV`s are full utilizedSettle out pressure 93 baraPSV capacity 566020 kg/hChoke mal operation 566020 kg/h

3 PAHH from pipeline calculationsPAHH sub sea 107 bara L = 30 kmPAHH topside 65 bara U = 4 W/m² °CSettle out pressure 93 bara ID = 16 in

1 Pressure drop over choke when CV = 537 1 PAHH from pipeline calculationsdp over choke 3 bar PAHH sub sea 107 bara L = 30 km

PAHH topside 65 bara U = 4 W/m² °C2 Max settle out pressure when CV = 537 and PSV`s are full utilized Settle out pressure 100 bara ID = 16 in

Settle out pressure 93 baraPSV capacity 559906 kg/h 2 Pressure drop over choke when CV = 537Choke mal operation 559906 kg/h dp over choke 3 bar

3 PAHH from pipeline calculations 3 Choke mal operation rate when CV = 537 and settle out pressure = 100 baraPAHH sub sea 101 bara L = 30 km PSV capacity 562736 kg/hPAHH topside 77 bara U = 4 W/m² °C Choke mal operation 663398 kg/hSettle out pressure 93 bara ID = 16 in Excess capacity -100662 kg/h

Results from choke calculations

Year 2017 with 5 bar over topside choke

Alternative 3Year 2015 with year 2017 choke and new PSHH

Year 2016 with year 2017 choke and new PSHHYear 2016 with year 2015 choke and PAHH

Year 2017 with year 2015 choke and new PSHH

Year 2016 with 5 bar over new topside choke

Alternative 1 Alternative 2Year 2015 settle out pressure 225 bara

Year 2019 with year 2018 choke CV and new PSHH



Year 2019 with year 2018 choke CV and PAHH

Appendix CSketches showing wellhead pressure,

requires pipeline dispatch pressure,

PSHH set pressure and topside choke pressure drop for

alternative 1 and 3 in year 2015 to year 2019.

T [°C]

P [bara]

PWV

PMV

SCSSV

Well

MEG

PSD

PSD

ESD

HCV

16” ID PIPELINE TO SLA

385 BARG FLOWLINE (TYPICAL)

385 BARG PRODUCTION MANIFOLD

385 BARG MANIFOLD

NOTES:1. Only actuated valves and transmitters with shutdown function are shown.2. PMV and PWV closes on PAHH from a pressure transmitter installed downstream of the choke valve on the well

production flowlines from Dagny production wells. 3. PMV and PWV also closes on PSD signal and ESD signal from SLA.4. SCSSV closes on ESD signal from SLA.5. Pipeline settle-out pressure at active shutdown of Dagny wells on topside PAHH estimated to 225 bara.

LL=PT ESD

-

-

-

APS

385 BARG RISER385 BARG PIPELINE

SSIV

385 BARG

385 BARG

MPM

225

-

-

LL= PT ESD

Typical well

385 BARG PIPELINE

Dagny subsea case 2AYear 2015 – Choke CV = 320

114

-

Rev. 01

EV ESD

PSD

TOPSIDE CHOKE

TO PRODUCTION SEPARATOR

385 BARG TOPSIDE

385 BARG RISER

PT

XV PSD

95

7271

90

HH=219 bara

LL=

PSD

HH=228 bara PT

PSD

PT

PSD

WELL CHOKE

HH=228 bara

dp = 5 bar

T [°C]

P [bara]

PWV

PMV

SCSSV

Well

MEG

PSD

PSD

ESD

HCV




385 BARG MANIFOLD



LL=PT ESD

-

-

-

APS


SSIV

385 BARG

385 BARG

MPM

225

-

-

LL= PT ESD

Typical well

385 BARG PIPELINE

Dagny subsea case 2AYear 2015 alternative – Choke CV = 764

110

-

Rev. 01

EV ESD

PSD

TOPSIDE CHOKE


385 BARG TOPSIDE

385 BARG RISER

PT

XV PSD

91

7271

90

HH=140 bara

LL=

PSD

HH=151 bara PT

PSD

PT

PSD

WELL CHOKE

HH=151 bara

dp = 1 bar

T [°C]

P [bara]

PWV

PMV

SCSSV

Well

MEG

PSD

PSD

ESD

HCV




385 BARG MANIFOLD



LL=PT ESD

-

-

-

APS


SSIV

385 BARG

385 BARG

MPM

175

-

-

LL= PT ESD

Typical well

385 BARG PIPELINE


125

-

Rev. 01

EV ESD

PSD

TOPSIDE CHOKE


385 BARG TOPSIDE

385 BARG RISER

PT

XV PSD

95

7978

90

HH=135 bara

LL=

PSD

HH=168 bara PT

PSD

PT

PSD

WELL CHOKE

HH=168 bara

dp = 5 bar

T [°C]

P [bara]

PWV

PMV

SCSSV

Well

MEG

PSD

PSD

ESD

HCV




385 BARG MANIFOLD



LL=PT ESD

-

-

-

APS


SSIV

385 BARG

385 BARG

MPM

175

-

-

LL= PT ESD

Typical well

385 BARG PIPELINE

Dagny subsea case 2AYear 2016 alternative – Choke CV = 764

123

-

Rev. 01

EV ESD

PSD

TOPSIDE CHOKE


385 BARG TOPSIDE

385 BARG RISER

PT

XV PSD

93

7978

90

HH=125 bara

LL=

PSD

HH=159 bara PT

PSD

PT

PSD

WELL CHOKE

HH=159 bara

dp = 3.3 bar

T [°C]

P [bara]

PWV

PMV

SCSSV

Well

MEG

PSD

PSD

ESD

HCV




385 BARG MANIFOLD



LL=PT ESD

-

-

-

APS


SSIV

385 BARG

385 BARG

MPM

158

-

-

LL= PT ESD

Typical well

385 BARG PIPELINE


157

-

Rev. 01

EV ESD

PSD

TOPSIDE CHOKE


385 BARG TOPSIDE

385 BARG RISER

PT

XV PSD

95

8788

90

HH=113 bara

LL=

PSD

HH=164 bara PT

PSD

PT

PSD

WELL CHOKE

HH=164 bara

dp = 5 bar

T [°C]

P [bara]

PWV

PMV

SCSSV

Well

MEG

PSD

PSD

ESD

HCV




385 BARG MANIFOLD



LL=PT ESD

-

-

-

APS


SSIV

385 BARG

385 BARG

MPM

101

-

-

LL= PT ESD

Typical well

385 BARG PIPELINE


100

-

Rev. 01

EV ESD

PSD

TOPSIDE CHOKE


385 BARG TOPSIDE

385 BARG RISER

PT

XV PSD

40

7066

35

HH=93 bara

LL=

PSD

HH=107 bara PT

PSD

PT

PSD

WELL CHOKE

HH=107 bara

dp = 5 bar

T [°C]

P [bara]

PWV

PMV

SCSSV

Well

MEG

PSD

PSD

ESD

HCV




385 BARG MANIFOLD



LL=PT ESD

-

-

-

APS


SSIV

385 BARG

385 BARG

MPM

100

-

-

LL= PT ESD

Typical well

385 BARG PIPELINE


99

-

Rev. 01

EV ESD

PSD

TOPSIDE CHOKE


385 BARG TOPSIDE

385 BARG RISER

PT

XV PSD

38

7471

35

HH=77 bara

LL=

PSD

HH=101 bara PT

PSD

PT

PSD

WELL CHOKE

HH=101 bara

dp = 3 bar

Results from Choke failure calculations with gas filled riser

Notes:1. Mass flowrate through the choke is equal to maximum massrate through inlet separator B PSV's.2. Choke Cv decreases when shut in gas temperature increases. 3. Selected CV = 357

Pressure drop over Choke with CV = 357

ConclutionsMaximum pressure drop over choke with CV = 357 is 4,2 barTemperature d/s choke = 34°C when operated with 21 bar differential pressure (arrival pressure - inlet separator B operation pressure).

Choke Calculations for Field 15/5-2 in year 2015 - Gas filled Riser Case

Results from Choke failure calculations with gas filled riser

Notes:1. Mass flowrate through the choke is equal to maximum massrate through inlet separator B PSV's.2. Choke Cv decreases when shut in gas temperature increases. 3. Selected CV = 344

Pressure drop over Choke with CV = 344

ConclutionsMaximum pressure drop over choke with CV = 344 is 4,5 barTemperature d/s choke = 34°C when operated with 21 bar differential pressure (arrival pressure - inlet separator B operation pressure).

Choke Calculations for Field 15/5-2 in year 2015 - Wellstream case

a

Choke calculations 1. Gas filled riser case With gas filled riser case the wellflow is separated at shut in pressure = 220 bara and minimum arrival temperature = 30°C. 1.1. PSV, inlet separator B To get the correct temperature down stream PSV, the gas from gas filled riser is flashed through the choke to PSV reliving pressure 114 barg + 10% = 126.5 bara. The temperature is calculated to be 12.5°C. HEM method is used to calculate maximum flow through PSV’s 037, 038, 277 and 278 where one is spare. Maximum acceptable choke failure rate was calculated to be 1 204 402 kg/h. 1.2. Choke CV A CCI program is used to calculate choke CV. To simulate a gas filled riser, wellflow is separated at shut in pressure = 220 bara and 5 different arrival temperatures where the CV calculated with 30 °C will be design. The flow through choke is set to be equal to maximum choke failure rate calculated in chapter 1.1.1. The pressure down stream choke is set to be 126.5 bara. CCI program is based on:

- Custom Drag choke whit: - Body Type: Angle - Flow Direction: Flow to Open (UTP) - Trim Type: Drag, Multi-Path, Multi Stage - Plug Type: Balanced

- One phase: Gas - Gas Type: Natural gas - Critical Pressure: True critical pressure is not calculated in HYSYS so Pseudo

critical pressure = 47 bara is used. - Critical temperature: True critical temperature is not calculated in HYSYS so

Pseudo critical temperature = -65°C is used. - Design pressure is set to be 220 bara - Design temperature is set to be 130/-20

Figure 1.1.2-1: Results from CCI program

Design CV is calculated to be 357 with gas filled riser.

a

1.3. pressure drop over choke A CCI program is used to calculate pressure drop over the choke. Operating conditions are used when simulating pressure drop over choke. Normal operating conditions is set to be 101 bara and 40°C. The pressure drop over chock is changed until CV calculated in chapter 1.1.2 is reached. CCI program is based on:


- Two phases: Gas and liquid - Critical Gas Pressure: True critical pressure = 58 bara - Critical Gas Temperature: True critical temperature = -67°C - Critical Liquid Pressure: True critical pressure = 587 bara - Design pressure is set to be 220 bara - Design temperature is set to be 130/-20


Pressure drop over choke with CV = 357 in gas filled riser case is calculated to be 4.2 bar. 2. Wellstream case With the wellstream case, the wellflow is operated shut in pressure = 220 bara and minimum arrival temperature = 30°C. 2.1. PSV To get the correct temperature down stream PSV, the wellstream is flashed through the choke to PSV reliving pressure 114 barg + 10% = 126.5 bara. The temperature is calculated to be 15.1°C. HEM method is used to calculate maximum flow through PSV’s 037, 038, 277 and 278 where one is spare. Maximum acceptable choke failure rate was calculated to be 1 211 640 kg/h.

a

2.2. Choke CV A CCI program is used to calculate choke CV. Wellflow down stream the choke is operated at shut in pressure = 220 bara. 5 different arrival temperatures where the CV calculated with 30 °C will be design. The flow through choke is set to be equal to maximum choke failure rate calculated in chapter 1.2.1. The pressure down stream choke is set to be 126.5 bara. CCI program is based on:


- Two phases: Gas and liquid - Critical Gas Pressure: True critical pressure is not calculated in HYSYS so Pseudo

critical pressure = 47 bara is used. - Critical Gas Temperature: True critical temperature is not calculated in HYSYS so

Pseudo critical temperature = -65°C is used. - Critical Liquid Pressure: True critical pressure = 225 bara - Design pressure is set to be 220 bara - Design temperature is set to be 130/-20


Design CV is calculated to be 344 with wellstream case.

a

2.3. pressure drop over choke A CCI program is used to calculate pressure drop over the choke. Operating conditions are used when simulating pressure drop over choke. Normal operating conditions is set to be 101 bara and 40°C. The pressure drop over chock is changed until CV calculated in chapter 1.2.2 is reached. CCI program is based on:


- Two phases: Gas and liquid - Critical Gas Pressure: True critical pressure = 58 bara - Critical Gas Temperature: True critical temperature = -67°C - Critical Liquid Pressure: True critical pressure = 587 bara - Design pressure is set to be 220 bara - Design temperature is set to be 130/-20


Pressure drop over choke with CV = 344 in gas filled riser case is calculated to be 4.5 bar. 3. Normal choke operation Under normal operation in year 2015, 15/5-2 will arrive at 101 bara and the inlet separator B will be operated at 80 bara. The differential pressure over the choke will be 21 bar and with 40°C d/s temperature the u/s temperature will be 34°C

Documents

Choke Sizing