kupe flow assurance

HYDROCARBONS | MINERALS, METALS & CHEMICALS | INDUSTRIAL & INFRASTRUCTURE | POWER WATER & DEVELOPMENTS

12 April 2006

Stephen Henzell

Kupe Flow Assurance

Acknowledgments

This SPE presentation is being given with the kind consent of the Origin on behalf of the Kupe Joint Venture partners:

Mitsui(4%)

NZ Oil & Gas(15%)

Genesis Energy(31%)

Origin Energy – Operator(50%)

Agenda

Project Description and BackgroundFlow Assurance Challenges for the Kupe FieldCO2 and CorrosionHydratesWaxAsphaltenesMultiphase Pipeline OperationSummary

Taranaki Region

Source: Google Earth

Kupe Field

Kupe 1 drilled in 1975 by Shell

• Interpreted residual oil column

Discovered by NZOG in 1986 with Kupe South 1Rich gas column with an underlying oil legField was proved up with Kupe South 3B well in 1988

• Most recent well drilled in the field

Central Field Area is contractedKS4 and KS5 drilled different accumulations to the south

Reserves and Production

Kupe Field Proved and Probable (2P) reserves of:

The final development will likely produce around 20 PJ per annumof sales gas

394TOTAL

8214.7 million bblsCondensate

31627 ktonnesLPG

281281 PJSales Gas

PJe2P RecoveryProduct

Development Concept

Wellhead Platform

Normally unmanned installationPrimary access by helicopterJack-up installable6 slots + 3 future risersWireline workoverMinimum facilities (no processing)Metering, multi-pig launcher, chemical injection, crane, HPU, HPPS, F&G and ESDPower, comms and chemical by umbilical from shore

Raw Gas Pipeline

Pipeline Shore Crossing

Shore Crossing and Production Station

HYDROCARBONS

Onshore Facilities - Description

Greenfield Production Station Site

Kupe’s Long History

Kupe was NZ’s third largest gas field when discovered in 1986. behind Maui and Kapuni

• Pohokura was subsequently discovered in 2000Maui gas dominated the market, maintaining a low gas price

• Maui is now substantially depleted and the market price for gas is increasing

WMC was the initial operator for the Kupe field developmentInitial concepts by WMC concentrated on oil production but the difficult fluid properties discouraged developmentWMC divested their petroleum portfolio in late 1996 and their share of Kupe was sold to Fletcher ChallengeFletcher Challenge looked at gas development concepts several times in the late 1990’sIn 2001 Shell acquired Fletcher Challenge Energy’s assets

Kupe’s Long History

Due to Shell’s dominant position in the New Zealand market it was required to divest part of the Fletcher Challenge portfolio Kupe was sold to Genesis Energy, who were keen to secure gas supply to their Huntly Power StationGenesis performed a number of engineering studies to firm up the development concept and costs

• Genesis’s intent was to sell part of its holding to an experienced oil and gas operator

Origin acquired 50% of Kupe in February 2004 and immediately commenced field development plans

• Leaving Genesis with 31%All onshore regulatory approvals were granted by the TaranakiRegional Council and the South Taranaki District Council in October 2005

Flow Assurance Challenges

Kupe’s long gestation was in large part due to the fluid characteristics of the field

CO2 at 11 mol% Corrosion, exotic materialsWet gas and low temps HydratesProduced water Hydrates, scaleWax Blockage of pipeline

Gelling of pipeline liquidsAsphaltenes Blockage of pipeline

Fouling of production equipment


CO2 and CorrosionHydratesWaxAsphaltenesSlugging

CO2 Corrosion

Designed for 12.5% CO2

Wet gas production at elevated pressuresWells, Flowlines, Production Header, Service Header specified in duplex stainless steelExport pipeline specified in carbon steel

• Continuous glycol injection• Continuous corrosion inhibitor injection

0

2

4

6

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18

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0 5 10 15 20 25 30

Liquid Without Glycol

Condensing Gas Phase without Glycol

Liquid with Glycol

Condensing Gas Phase with Glycol

Distance from Inlet (km)

Cor

rosi

on R

ate

(mm

/yr)

CO2 Corrosion Predictions

CO2 Corrosion

High integrity corrosion control requiredCorrosion inhibitor injection from onshore and piped to offshore – blended with glycol

• Very high availability specified• Dedicated injection pipeline

Corrosion monitoring tools installed both onshore and offshore

• Field signature method corrosion monitoring tool at platform• Monitoring of pigging products onshore

Top of Line Corrosion

When water condenses rapidly from the gas phase and liquid based corrosion inhibitor does not mix with the water

Controlled by routine pigging required for wax management• The pig will distribute liquids to top of pipeline

Hydrates

Raw gas production to shoreWater of condensation in raw gas pipeline

• 50 b/dPotential for produced water in raw gas pipeline

• 1200 b/dHydrate prevention by continuous glycol injection

• High availability required• Glycol injected from shore• Low flow alarms offshore• Alternative injection routes provided

0

5000

10000

15000

20000

25000

30000

-50 -30 -10 10 30 50 70

Suppression of Hydrates

Temperature (˚C)

Pre

ssur

e (k

Pag

)

Hydrate Formation Curve

Pipeline Operating Conditions

Hydrate Curve 10% Glycol in Aqueous Phase

30% Glycol in Aqueous Phase



Design Point

Waxy Crude and Condensate

Key Parameters – Fluid Properties

3.9 wt%2.5 wt%Hard Wax Content (C30+)

34°C25°CPour Point

81°C56°CWax Appearance Temp

Crude OilCondensate

Source: Ondeo Nalco Flow Assurance Report Dec 03

Pour Point

Pour point for crude/cond mixes

First Wax Appearance Temp


Second Wax Appearance Temp

Pour point for crude/cond mixes

Temperature °C

Vis

cosi

ty m

Pa.

s

Taranaki Experience

Waxy crude oils are common in TaranakiThe wax management strategies are all differentKapuniWaihapaMauiPohokura

Kapuni

Gas wells experienced significant wax problems early in lifeSteam injection required at well pad separators for start-upWax issues disappeared after a number of years due to retrograde condensation

Waihapa

Waxy crude exported to Omata Tank Farm at New PlymouthContinuous injection of PPD requiredIntermediate valve stations provided to allow pipeline to be restartedHigh pipeline design pressure to allow restart

Maui B

Oil discovered at Maui B platformSTOS agonised over waxy oil export through the gas pipeline to Maui A platform and Oaonui Production StationFPSO Whakaaropai installed at site in 1996 to process all oil

Pohokura

Pohokura has onshore and offshore wellsInsulated flowline to shoreMinimum flow specified for pipeline (swing to onshore production)PPD injection from shore through umbilicalZero intervention platform (2 year visit frequency)

Other Wax Experience – SPE as a resource

Wax Management Strategy

Wellhead Platform Wax Deposition

Pipeline Wax Deposition

Pipeline Restart

Production Station


Wellhead Platform Wax Deposition• Continuous downhole injection of WCM/PPD chemical• Dead-legs minimised• Heat tracing of small bore fittings• Provision for batch solvent injection for removal of

accumulated wax• Provision for heat tracing of production flowlines


Pipeline Restart

Production Station



Pipeline Wax Deposition• Continuous downhole injection of WCM/PPD chemical• Regular scraper pigging (likely 3-7 day interval)

Pipeline Restart

Production Station

Thermal Profile for Pipeline

Source: AWT Flow Assurance Review

Pipeline Wax Deposition Modelling

Source: AWT Flow Assurance Review Rev 2 Dec 04

1 day

3 days

7 days

MDQ gas rates80% oil trapped in wax

Automatic Pig Launcher

Platform visit frequency driven by pig launchingAutomatic pig launchers investigatedAutomatic sphere launchers are commonAutomatic scraper launchers are rarer

• Gabon• Subsea equipment

Pig Launcher Loading

Launcher Door Pressure Testing

Pig Launching




Pipeline Restart• PPD injection to reduce pour point temperature and gel

strength• Adequate differential pressure to restart “gelled” pipeline

sections if chemical injection fails

Production Station

Pipeline Restart

Operation below WAT and Pour PointUnplanned shutdown leaves operating liquid inventory to settle-out into pipeline low points Concern regarding gel strength and differential pressures required for restartAvailable differential pressure for restart is:

• Normal 4,500 kPa• “Emergency” 12,000 kPa

Normal pipeline differential pressure:• MDQ 1,000 kPa

Pipeline Liquid Holdup

Operating Condition

Shutdown Condition

Pipeline Elevation Profile

-40

-30

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-10

0

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-2 0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30

Pipeline Length (km)

Pip

elin

e E

leva

tion

(m)

HDDShore

Crossing

-50

-40

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-10

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0 5,000 10,000 15,000 20,000 25,000 30,0000

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Liquid Holdup at Operating Conditions

Elevation

Ele

vatio

n (m

)

Pipeline Length (m)

Liqu

id %

Hol

d-U

p

-50

-40

-30

-20

-10

0

10

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50

0 5,000 10,000 15,000 20,000 25,000 30,0000

20

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100

2900m201m³

Liquid Holdup at Shutdown Conditions

Elevation

Pipeline Length (m)

Ele

vatio

n (m

)

Liqu

id %

Hol

d-U

p

Shear Stress for Restart

25 PaWorst Case


Restart Pressures

Conservative CaseShear required to break gel

• 25 Pa• For crude/condensate mix• Untreated with PPD

Max slug length• 4000 metres (at min DCQ)

Restart pressure

=1300 kPa

DLP /4 ⋅⋅=∆ τ

Restart Pressures

Worst case conditions• Condensate has lower shear stress required to break

gel• As low as 10 Pa

Unknowns• Effect of MEG / Water / Condensate emulsions• Effect of PPD on gel strength

Restart Pressures

“More Likely” CaseShear required to break gel

• 10 Pa• For condensate • Untreated with PPD

Max slug length• 2500 metres

Restart pressure

=350 kPaWith PPD addition (4 times reduction?)

=100 kPa

DLP /4 ⋅⋅=∆ τ


Topsides Wax Deposition


Pipeline Restart

Production Station

Production Station Wax Considerations

Pig receiver• Specified to manage wax scraped from the wall of the

pipelineSlugcatcher

• Warm condensate recycle to melt wax deposits and to maintain process temperatures

Liquids handling and storage• Steady increase in operating temperatures for processing• Warm recycle for start-up

Export• Provision for additional PPD injection

Heat tracing of all instrumentation and stagnant lines

Wax Removal from Scraper Receiver

Asphaltenes

Asphaltenes –“heavy components of crude oil not soluble in heptane”Exist as solids that are dispersed by resinsAsphaltenes were detected in the original oil samples from Kupe South 3B

• 0.03 wt%But resins are only 1.8 wt%SARA (Saturates, Aromatics, Resins, Asphaltenes) analysis indicates that Kupe crude oil is unstableReduction of resins or mixing with paraffin compounds can de-stabilise the asphaltene

• By mixing with condensateExperience at Port Bonython is invaluable

Moomba - Port Bonython

Port Bonython

Gas

Oil

CO2Removal

CryogenicPlant

Stabiliser De-Ethaniser

Sales Gas

Ethane

De-Ethaniser

De-Propaniser

De-Butaniser Naphtha

Splitter

NGLs

Ethane

Propane

Butane

Naphtha

Crude

Moomba

Port Bonython

Asphaltene Deposits

Port Bonython Experience

0.05 wt% asphaltene in blend of crude and NGLsPlant shutdown after six months

• 30 tonnes of solids removed from de-ethaniser• Mixture of asphaltenes and waxes

Plant runtimes extended to 18 months by• Asphaltene dispersant injection• Careful control of feedstock

Kupe Asphaltenes

Asphaltene production with crude oil could seriously affect gas deliverabilityDecision taken to avoid targeted crude oil productionHowever there is potential for crude oil to commingle with gas productionPrecautions:

• Provision for asphaltene dispersant injection• Provision to install stand-by equipment (mostly heat exchangers)• Equipment specified to allow cleaning/removal (trayed columns,

vessel inlet devices)

0

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0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 250

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35000

Liquid Inlet Flow to Slugcatcher at 50% DCQLi

quid

Flo

wra

te (m

³/hr)

Time (hrs)

Pig

Pos

ition

in P

ipel

ine

(m)

Pig Launched

Slugcatcher Inventory at 50% DCQ

Time (hrs)

Liqu

id F

low

rate

(m

³/hr)

Inve

ntor

y (m

³)

0

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3000

5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 250

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Slugcatcher Inventory

Slugcatcher Inventory at 50% DCQ

Time (hrs)

Liqu

id F

low

(m

³/hr)

Inve

ntor

y (m

³)

0

500

1000

1500

2000

2500

3000

5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 250

50

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Liquid Draw-Down at 50% DCQ Rate

Liquid Draw-Down at DCQ Rate

Liquid Draw-Down at MDQ Rate

Terrain Induced Slugging

Slu

gcat

cher

Inve

ntor

y (m

³)

Liqu

id F

low

(m³/h

r)

Time (hrs)

0

25

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200

0 0.5 1 1.5 2 2.5 3 3.5 40

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Slugcatcher Size

250 m3Working Capacity

15% to cover the unknowns30 m3Contingency

5 m3Terrain Slugging

Gas: 50% DCQLiquids: DCQ

215 m3Pigging Slug

CommentSlug Size

Summary

SynergiesDevelopment concept based on ALL flow assurance issues

Synergies

Hydrate and corrosion management require very high availability

• Glycol and corrosion inhibitor mixed onshore• Transferred to shore via dedicated pipeline• High integrity monitoring systems both onshore and offshore

Routine pipeline pigging• Wax build-up control• Top of line corrosion control

Chemical injection• Required for pour point depressant injection• Can be augmented to provide asphaltene dispersant injection if

required

Flow Assurance Input to Development Concept

Umbilical from shore to platform• Power for heat tracing of platform• Power for heat tracing of future satellite developments• High bandwidth communications for monitoring critical platform

operating parameters• Chemical transfer from onshore – high availability• Provision for future chemicals

Design provisions for wax and asphaltene• Affects project design from wells through to export• Consistent approach required in all facilities

Kupe Flow Assurance

Thank you

Questions?

kupe flow assurance

Documents

flow assurance

wax appearance

port bonython

liquid holdup

genesis energy

production

aqueous phase

crude oil