kupe flow assurance
TRANSCRIPT
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
Flow Assurance Challenges
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
8
10
12
14
16
18
20
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
Flow Assurance Challenges
CO2 and CorrosionHydratesWaxAsphaltenesSlugging
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
20% Glycol in Aqueous Phase
40% Glycol in Aqueous Phase
Design Point
Flow Assurance Challenges
CO2 and CorrosionHydratesWaxAsphaltenesSlugging
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
Source: Ondeo Nalco Flow Assurance Report Dec 03
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
Wax Management Strategy
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 Wax Deposition
Pipeline Restart
Production Station
Wax Management Strategy
Wellhead Platform Wax Deposition
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
Wax Management Strategy
Wellhead Platform Wax Deposition
Pipeline Wax Deposition
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
-20
-10
0
10
20
30
40
50
-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
-30
-20
-10
0
10
20
30
40
50
0 5,000 10,000 15,000 20,000 25,000 30,0000
20
40
60
80
100
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
20
30
40
50
0 5,000 10,000 15,000 20,000 25,000 30,0000
20
40
60
80
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
Source: Ondeo Nalco Flow Assurance Report Dec 03
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
Wax Management Strategy
Topsides Wax Deposition
Pipeline 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
Flow Assurance Challenges
CO2 and CorrosionHydratesWaxAsphaltenesSlugging
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)
Flow Assurance Challenges
CO2 and CorrosionHydratesWaxAsphaltenesSlugging
0
500
1000
1500
2000
2500
3000
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
5000
10000
15000
20000
25000
30000
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
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
100
150
200
250
300
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
100
150
200
250
300
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
50
75
100
125
150
175
200
0 0.5 1 1.5 2 2.5 3 3.5 40
25
50
75
100
125
150
175
200
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?