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


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


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


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


Too small for the big WA fields

Browse needs 3!


Needs crew offshore (Prelude needs 110 man crew)

Needs crew change/personnel transfer



Allows phased development of larger fields

Reduces financial exposure and initial CAPEX


Reduces exposure to environmental direct action

Avoids onshore protest activity (e.g. James Price Point)

Still some risk from offshore activism


Less risk of environmental approval delays or native title issues


No requirement for WA Domgas



Allows phased development of larger fields




Allows phased development of larger fields (3 FLNG for Browse)


Chart: UWA Subsea Technology 2013 Team 1

Cashflow for FLNG vs onshore LNG





Going from MEGA-Project to Mini-MEGA-Project

$50-60 billion exposure $13 billion exposure





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






Avoids protracted delays (e.g. Corrib)

Shell Corrib timeline





“Shell has learned, through listening, that you need to go beyond

compliance to win the trust of your neighbours”



























Avoids protracted delays (e.g. Corrib)

Shell Corrib

Mediation failed – “the parties are unable to resolve the differences

between them”



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.’’



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


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


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




Redundant trace heating cables

Fibre optic for thermal monitoring

Image: Technip


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



Redundant trace heating cables

Fibre optic for thermal monitoring


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


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.


Ignominious

Marked by shame or disgrace

Image: Woodside

The Real Estate for Browse LNG

at James Price Point


Ignominious


Image: Woodside

The Real Estate for Prelude


Ignominious


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


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: Scott Reef Rugbjerg_2009






Subsea systems with LNG facilities on Scott Reef

Image: LNG Conceptual Design Strategies





UWA Subsea Technology 2013 teams


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



Torosa, Brecknock

and Calliance

Challenging Reservoir



Challenging Environment



Subsea-to-Shore tieback Tieback to Offshore Processing Facility and to LNG Plant Onshore

Floating LNG

Option A

Option C

Option B



TOROSA – South Phase 4

TOROSA – North Phase 3

BRECKNOCK Phase 2

CALLIANCE Phase 1

FLNG 1 10Prod+2 CO2 Injection

TOTAL 12 wells


TOTAL 15 wells


TOTAL 13 wells


TOTAL 13 wells



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



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





Carbon Sequestration



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



1718-1721


http://vreaa.files.wordpress.com/2010/12/picture-14.jpg



1718-1721


http://vreaa.files.wordpress.com/2010/12/picture-14.jpg

http://static.businessinsider.com/image/515b40886bb3f7bd49000013/image.jpg

Subsea Developments for FLNG Production


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Kevin Mullen, INTECSEA: Subsea Developments for FLNG Production

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