Kevin Mullen, INTECSEA: Subsea Developments for FLNG Production
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Transcript of Kevin Mullen, INTECSEA: Subsea Developments for FLNG Production
Subsea Developments for FLNG Production 3-4 December 2013 | Fraser Suites, Perth, Australia Prof. Kevin Mullen
The FLNG Forum 2013 Delivering knowledge on the latest technologies,
concepts and challenges for the FLNG revolution
Agenda
Subsea Developments for FLNG Production
Smaller, Smarter, More Dangerous
Turning constraints of FLNG to advantage
Impact of FLNG on subsea field layout
New subsea technologies for FLNG
Risks to FLNG from subsea developments
Case study
Smaller, Smarter, More Dangerous
Australian LNG projects, capital costs and unit costs
FLNG is small – single train
Typical fields will require several FLNG
Prelude: 3.6 – 5 MTPA LNG
Source: BREE
pa
Smaller, Smarter, More Dangerous
Having FLNG close to wells is an enabler
Allows pipeline heating
Reduces dependence on chemicals
Shorter distance to wells
No need for compression or boosting
Less failure-prone equipment on the seabed
Slugs and liquid hold-up in flowlines is less of a problem
Smaller, Smarter, More Dangerous
FLNG puts all processing equipment in close proximity
FLNG vessel exposed to inventory of risers and flowlines
Prone to escalation
Inherently dangerous, not inherently safe
An as-yet unproven technology
Potentially subject to cost blowouts
More dangerous to your bottom line
FLNG systems will suffer more downtime than onshore LNG
No linepack in long pipelines
More dependent on high availability subsea systems
More risk to your bottom line
Constraints of FLNG
Smaller size of FLNG
Too small for the big WA fields
Browse needs 3!
FLNG entirely offshore
Needs crew offshore (Prelude needs 110 man crew)
Needs crew change/personnel transfer
Constraints of FLNG
Smaller size of FLNG
Too small for the big WA fields
Browse needs 3!
FLNG entirely offshore
Needs crew offshore (Prelude needs 110 man crew)
Needs crew change/personnel transfer
Turning constraints of FLNG to advantage
Smaller size of FLNG
Allows phased development of larger fields
Reduces financial exposure and initial CAPEX
FLNG entirely offshore
Reduces exposure to environmental direct action
Avoids onshore protest activity (e.g. James Price Point)
Still some risk from offshore activism
FLNG entirely offshore
Less risk of environmental approval delays or native title issues
FLNG entirely offshore
No requirement for WA Domgas
Turning constraints of FLNG to advantage
Smaller size of FLNG
Allows phased development of larger fields
Reduces financial exposure and initial CAPEX
Turning constraints of FLNG to advantage
Smaller size of FLNG
Allows phased development of larger fields (3 FLNG for Browse)
Reduces financial exposure and initial CAPEX
Chart: UWA Subsea Technology 2013 Team 1
Cashflow for FLNG vs onshore LNG
Turning constraints of FLNG to advantage
Smaller size of FLNG
Allows phased development of larger fields (3 FLNG for Browse)
Reduces financial exposure and initial CAPEX
Going from MEGA-Project to Mini-MEGA-Project
$50-60 billion exposure $13 billion exposure
Turning constraints of FLNG to advantage
Smaller size of FLNG
Allows phased development of larger fields (3 FLNG for Browse)
Reduces financial exposure and initial CAPEX
Going from MEGA-Project to Mini-MEGA-Project
$50-60 billion exposure $13 billion exposure
Opposition to gas developments
Courtesy West Australian, 29 Jul 2013
Turning constraints of FLNG to advantage
FLNG entirely offshore
Reduces exposure to environmental direct action
Still some risk from offshore activism
Avoids onshore protest activity (e.g. James Price Point)
Avoids protracted delays (e.g. Corrib)
Shell Corrib timeline
FLNG entirely offshore
Reduces exposure to environmental direct action
Avoids onshore protest activity (e.g. James Price Point)
Still some risk from offshore activism
“Shell has learned, through listening, that you need to go beyond
compliance to win the trust of your neighbours”
Shell Corrib timeline
FLNG entirely offshore
Reduces exposure to environmental direct action
Avoids onshore protest activity (e.g. James Price Point)
Still some risk from offshore activism
“Shell has learned, through listening, that you need to go beyond
compliance to win the trust of your neighbours”
Shell Corrib timeline
FLNG entirely offshore
Reduces exposure to environmental direct action
Avoids onshore protest activity (e.g. James Price Point)
Still some risk from offshore activism
“Shell has learned, through listening, that you need to go beyond
compliance to win the trust of your neighbours”
Shell Corrib timeline
FLNG entirely offshore
Reduces exposure to environmental direct action
Avoids onshore protest activity (e.g. James Price Point)
Still some risk from offshore activism
“Shell has learned, through listening, that you need to go beyond
compliance to win the trust of your neighbours”
Turning constraints of FLNG to advantage
FLNG entirely offshore
Reduces exposure to environmental direct action
Still some risk from offshore activism
Avoids onshore protest activity (e.g. James Price Point)
Avoids protracted delays (e.g. Corrib)
Shell Corrib
Mediation failed – “the parties are unable to resolve the differences
between them”
“Shell has learned, through listening, that you need to go beyond
compliance to win the trust of your neighbours”
Is the tolerance of green activism changing?
Paul Watson of Sea Shepherd has faced legal action from the
United States, Canada, Norway, Costa Rica, and Japan
After skipping bail following an arrest in Germany in 2012, Interpol
issued red notices requesting his arrest.
The activist who caused a $314 million temporary plunge in
Whitehaven Coal's share price could face 10 years in jail
Jonathan Moylan issued a fake ANZ press release claiming ANZ had
pulled a $1.2 billion loan because of environmental concerns
Greenpeace vessel Arctic Sunrise arrested by Russia
Piracy charges for boarding the Gazprom drill rig Prirazlomnaya have
been downgraded to hooliganism
Senator Eric Abetz says
"With the Greens it is always a case of the ends justifying the means.’’
Turning constraints of FLNG to advantage
FLNG entirely offshore
Potentially no requirement for WA Domgas
Western Australia’s domestic gas reservation policy, instated in 1977,
was updated in 2006 and requires LNG Producers to make available
domestic gas equivalent to 15% of LNG production from each LNG
export project
Sales revenue of export gas and domestic gas (15% of total gas
production) are approximately $12/MMBTU and $8/GJ
Pie Chart: based on data from UWA Subsea Technology 2013 Team 3
74%
8%
18%
Revenue Component
Export Gas
DomGas
Condensate
New subsea technologies for FLNG
Heating of flowlines for hydrate prevention
Direct electric heating or trace heating or heated water pipes
Eliminate need for MEG
Eliminate need for MEG reclamation on FLNG vessel
Why?
Shell Prelude has 800 m3/day MEG regeneration system to provide
buffer storage, collection and regeneration of MEG
MEG facilities including MEG storage tanks,
MEG desalination package, MEG regeneration package, MEG injector
and MEG booster pumps
Image: Cameron
MEG module for offshore Brazil application
Rich MEG flow 120 m3/day
300 tonne module
x6
New subsea technologies for FLNG
Direct Electrical Heating (DEH)
AC current to pipe
Field Proven: Single phase required
High voltage and power required (100-150 W/m)
Electrical Heat Tracing (EHT)
Heating cables between pipe and insulation
Pipe in Pipe (PIP)
AC three phase power
Low voltage, low power (4-30 W/m)
Higher safety, less dielectric ageing
Qualified wire traces and subsea connectors
Allows redundancy
Integrated Production Bundle (IPB)
Hot water tubes between pipe and insulation
Use spare heat from compression / power generation
Use for risers Images: Technip
Heated Flexible
Flowline
Electrically Trace Heated Pipe-in-Pipe
Image: Total
New subsea technologies for FLNG
Electrical Heat Tracing (EHT)
Low voltage, low power (4-30 W/m)
Redundant trace heating cables
Fibre optic for thermal monitoring
Image: Technip
New subsea technologies for FLNG
Courtesy: Total
Power requirements for Islay EHT
Power required
per metre
Overall power
required
Maintain temperature above
HAT (ca 20°C)4 to 8 W/m Ca. 50 kW
Heat up pipeline from 4
to 20°C in 24 hours15 to 20 W/m Ca. 120 kW
Heat up pipeline from 4
to 20°C in 30 hours with
15% of hydrates30 W/m Ca. 180 kW Power
20 W/m
8 W/m
4ºC
20ºC
Temperature
Heat up
Maintain
Electrical Heat Tracing (EHT)
Low voltage, low power (4-30 W/m)
Redundant trace heating cables
Fibre optic for thermal monitoring
New subsea technologies for FLNG
Reeled installation
Faster than S-lay or J-lay
Fabrication is performed onshore
Controlled environment, off the critical path
Weld repairs are performed onshore
Image: Technip
Courtesy: Chuck Horn/SUT
S-lay
Reeling onto installation vessel
Risks to FLNG from subsea developments
Risk is higher with FLNG than FPSOs
Risk = Likelihood x Consequence
Likelihood is higher with gas than with oil developments
Consequence of loss of FLNG = $13 billion Shell Prelude
Consequence of loss of FPSO = $1.5 billion UIBC 2012 data
Shell statement in Prelude EIS
After comprehensive studies, model testing and in-depth reviews,
Shell’s FLNG design safety is considered equal to the latest FPSO or
integrated off shore facility.
Risks to FLNG from subsea developments
Ignominious
Marked by shame or disgrace
Image: Woodside
The Real Estate for Browse LNG
at James Price Point
Risks to FLNG from subsea developments
Ignominious
Marked by shame or disgrace
Image: Woodside
The Real Estate for Prelude
Risks to FLNG from subsea developments
Ignominious
Marked by shame or disgrace
Image: Woodside
The Real Estate for 3 x FLNG
Case Study
Courtesy: UWA Subsea Technology 2013 Team 1
Case Study – Browse LNG Development
Courtesy: Geoscience Australia
Major gas fields: development status, as of March 2012
Case Study – Browse LNG Development
Reservoir Gas Condensate CO2
Content
Torosa 8.5 Tcf 159 MMbbl 8% CO2
Brecknock 4.0 Tcf 144 MMbbl 8% CO2
Calliance 3.0 Tcf 114 MMbbl 12% CO2
Remoteness of Browse Basin from Existing Infrastructure
Challenging Access
Courtesy: UWA Subsea Technology 2013 Team 1
Case Study – Browse LNG Development
Courtesy: Scott Reef Rugbjerg_2009
Case Study – Browse LNG Development
Courtesy: UWA Subsea Technology 2013 Team 1
Case Study – Browse LNG Development
Courtesy: UWA Subsea Technology 2013 Team 1
Case Study – Browse LNG Development
Subsea systems with LNG facilities on Scott Reef
Image: LNG Conceptual Design Strategies
Case Study – Browse LNG Development
Courtesy: UWA Subsea Technology 2013 Team 1
Case Study – Browse LNG Development
Case Study – Browse LNG Development
UWA Subsea Technology 2013 teams
Case Study – Browse LNG Development
Team 1 Team 2 Team 3 Team 4
Project
Analogues
Shell Prelude Chevron Gorgon (+ Apache
East Spar Control Buoy)
Wandoo B Inpex Ichthys
Topsides FLNG LNG trains at JPP LNG
Precinct
Concrete Gravity Structure
with slug catcher in 45 metre
WD, LNG trains at JPP LNG
Precinct
Infield Central
Processing Facility with
compression, LNG
trains at JPP
Export Pipeline N/A 40" CS 310 km pipeline 26" CS x 115 km, 24" CS
240 km export pipeline
36" CS x 325 km export
pipeline
CAPEX Initial CAPEX 13.4 billion,
total $45 bn
$47.3 bn 22 billion (questionable
benchmark ing )
36 billion
LNG trains 4.2, 4.3, 4.7 MTPA 3 off 4 MTPA 3 off 4.3 MTPA 2 off 3.65 MTPA
Nominal flowrate 717+740+800 MMSCFD 2200 MMSCFD 1748 MMSCFD 1500 MMSCFD
Field life 39 years 19 years 25 years 36 years
Control of field Closed loop MUX-EH Closed loop MUX-EH, via
control buoy
MUX-EH (fibre optic), from
CGS
MUX-EH from CPF
NPV 35 billion,
10% discount rate
18 billion 12 billion 15 billion
Payback 6.5 years after production 6 years after production 6 years after production 8 years after production
First LNG 2024 2017 2018 2017
Well count 53 wells total 26 wells total 46 wells total 19 wells total
Drilling Phases 6 (9+10+12+13+5+3 wells) 13 (19+1+1+1+1+1+2+5+
1+1+1+1+1 wells)
5 (13+8+8+10+7 wells) 7 (6+1+1+1+1+1+1+2+
1+1+1 wells)
Trees 7" horizontal 7" vertical monobore trees 7" enhanced horizontal trees 7" horizontal
Completions 7" completions 9 5/8" and 7" completions 9 5/8" and 7" completions 9 5/8" completions
CO2 Reinject into reservoir Reinject into reservoir, 18"
CS 280 km pipeline
Case Study – Browse LNG Development
Courtesy: UWA Subsea Technology 2013 Team 1
Torosa, Brecknock
and Calliance
Challenging Reservoir
Case Study – Browse LNG Development
Courtesy: UWA Subsea Technology 2013 Team 1
Challenging Environment
Case Study – Browse LNG Development
Courtesy: UWA Subsea Technology 2013 Team 1
Subsea-to-Shore tieback Tieback to Offshore Processing Facility and to LNG Plant Onshore
Floating LNG
Option A
Option C
Option B
Case Study – Browse LNG Development
Courtesy: UWA Subsea Technology 2013 Team 1
TOROSA – South Phase 4
TOROSA – North Phase 3
BRECKNOCK Phase 2
CALLIANCE Phase 1
FLNG 1 10Prod+2 CO2 Injection
TOTAL 12 wells
FLNG 2 13Prod+2 CO2 Injection
TOTAL 15 wells
FLNG 3 11Prod+2 CO2 Injection
TOTAL 13 wells
FLNG 1 11Prod+2 CO2 Injection
TOTAL 13 wells
Case Study – Browse LNG Development
Courtesy: UWA Subsea Technology 2013 Team 1
NPVa = $31.78B, IRR = 6.87%
NPVb =$27.46B, IRR = 5.78%
NPVc=$35.03b, IRR = 10.53%
Arrow shows the Start of Production
Cash flow
Case Study – Browse LNG Development
Courtesy: UWA Subsea Technology 2013 Team 1
0
500
1000
1500
2000
2500
3000
0 5 10 15 20 25 30 35 40
Pro
du
cti
on
rate
MM
SC
F/D
Production Year
Production Rate vs Time
Production capacity
Operation rate
Manifold: C01
Phase 0 (4ea)
Slot - S01,S02,S03,S04 Future expansion wells:
S05,S06
Manifold: C02
• Phase 0 (3ea)
Slot - S01,S02,S03
SDU
UMBILICALS
PLET
X-TREE
JUMPER
UMBILICALS
FIELD LAYOUT: CALLIANCE
Water depth: 500 m
Water depth: 380 m
• Phase 1 (2ea)
Slot - S04, S05
• Phase 2 (1ea)
Slot - S06
Injection Wells
Phase 0 (2ea injection
wells daisy-chain)
RISER BASE + SSIV
UTA
PLET
INJECTION PIPELINE
FLOWLINE
PRODUCTION X-TREE
SPARE SLOT SDU
INJECTION X-TREE
PRODUCTION PIPELINE
MANIFOLD
N
`
Manifold: B01
• Phase 1 (6ea)
Slot - S01,S02,S03,S04,S05,S06
Manifold: B03
• Phase 3 (3ea)
Slot - S01,S02,S03
Water depth: 680 m
Water depth: 500 m
Manifold: B02
• Phase 2 (3ea)
Slot - S01,S02,S03
FIELD LAYOUT: BRECKNOCK
• Phase 4 (1ea)
Slot - S04
Injection Wells
• Phase 1 (2ea CO2
Injection wells)
INJECTION PIPELINE
FLOWLINE
UMBILICALS
SPARE SLOT
PRODUCTION PIPELINE
MANIFOLD
RISER BASE + SSIV
UTA
PLET
PRODUCTION X-TREE
SDU
INJECTION X-TREE
N
Water depth: 290 m
Manifold: T03
Phase 4 (2ea)
Slot - S01,S02
Manifold: T02
Phase 3 (2ea)
Slot - S01,S02
FIELD LAYOUT: TOROSA – NORTH
Manifold: T01
Phase 2 (6ea)
Slot - S01,S02,S03,S04,S05,S06
Phase 5 (1ea)
Slot – S03
(Inset) Manifold T01
Injection Wells
Phase 2
(2ea CO2 injection wells)
INJECTION PIPELINE
FLOWLINE
UMBILICALS
SPARE SLOT
PRODUCTION PIPELINE
MANIFOLD
RISER BASE + SSIV
UTA
PLET
PRODUCTION X-TREE
SDU
INJECTION X-TREE
N
Ave. inclination 10 degrees
Manifold: T04
Phase 3 (6ea)
Slot - S01,S02,S03,S04,S05,S06
Manifold: T05
Phase 4 (2ea)
Slot - S01,S02
Manifold: T06
Phase 5 (3ea)
Slot - S01,S02,S03
Water depth: 1000 m
Water depth: 500 m
Injection Wells
Phase 3 (2ea CO2 injection
wells daisy-chain)
INJECTION PIPELINE
FLOWLINE
UMBILICALS
SPARE SLOT
PRODUCTION PIPELINE
MANIFOLD
RISER BASE + SSIV
UTA
PLET
PRODUCTION X-TREE
SDU
INJECTION X-TREE
FIELD LAYOUT: TOROSA – SOUTH Ave. inclination 5.7 degrees
Water depth: 2000 m
Water depth: 1500 m
N
Case Study – Browse LNG Development
Courtesy: UWA Subsea Technology 2013 Team 1
Case Study – Browse LNG Development
Courtesy: UWA Subsea Technology 2013 Team 2
Carbon Sequestration
Case Study – Browse LNG Development
Courtesy: UWA Subsea Technology 2013 Team 1
Project Economics Key Figures
CAPEX - $46.16B Total Project Cost
FLNG -$42.92B
Subsea -$3.24B
OPEX - $440M per FLNG vessel annually
including fuel, staff, transport assistance
NPV10 $35.03B
IRR 10.53%
Closing Remarks
The Shell Prelude development
Single umbilical – single point of failure
9% CO2 vented up flare stack – 2.3 MTPA
Image: Shell Environment Plan Prelude Drilling
FLNG – Another South Sea Bubble?
The South Sea Bubble
1718-1721
The first stock market crash
FLNG – Another South Sea Bubble?
The South Sea Bubble
1718-1721
The first stock market crash
FLNG – Another South Sea Bubble?
The South Sea Bubble
1718-1721
The first stock market crash
Subsea Developments for FLNG Production
Smaller, Smarter, More Dangerous