modus as mopus: low cost field development · •subsea tree - mopu motions do not allow for dry...

MODUs as MOPUs: Low cost field development

using hybrid risers

Pedro Viana

2H Offshore

Learn more at www.2hoffshore.com

2

Contents

• Objectives

• Background

• Typical Arrangements for FPU / Riser

• Free Standing Hybrid Risers – key aspects

• Proposed Alternative(s)

• MODU as FPU: Drilling & Completion, Production & Installation

• Historical Precedence & Current Scenario

• Comparison: Converted MODU vs. TLP

• Installation Method

• Conclusions & Closing Remarks


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Objectives

• Describe how the conversion of Mobile Offshore Drilling Unit (MODU) into a Floating Production Unit (FPU), keeping drilling and adding installation capabilities, can be a complete and cost effective solution when considered in association with a Free Standing Hybrid Riser (FSHR).

• Present how previous industry experience and current market conditions turns it into an timelly opportunity.


4

Background


5

Background Typ. Arrangements for Floating Production Unit and Risers (and 2H areas of expertise)

Rigid & Flexible Risers

Risers & Well Conductors Engineering

Hybrid Risers

Top Tensioned Risers

Drilling Risers


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• Not highly sensitive to environmental loading or FPU motions

• Low payload on platform and moorings

• Large diameters; “any” water depth

• Pre-Installable • decouples installation from FPU and flowlines schedule

• Flow assurance flexibility • Large insulation thicknesses

• Pipe-in-Pipe

• CRA lined pipe

• Opportunities for Local Content (Africa, Brazil)

• Unique seabed contact point

• Lower installation cost by installing from the MODU • $60MM to $25MM per installed riser

Background Free Standing Hybrid Risers (FSHR) – key aspects

Buoyancy Tank

Tether

Upper Riser Assembly (URA)

Standard Riser Joints

Base Jumper

Foundation

Flexible Jumper

To FPU

Lower Riser Assembly (LRA)


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Proposed Alternative MODU as MOPU


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Proposed Alternative Options

• Option A: MODU re-purposed as FPU only

• Minimal or full processing facility

• Fluid processed at MODU before export

• Future drilling & intervention by a different MODU

• Option B: MODU repurposed as FPU + drilling & workover + FSHR installation

• Drill initial or future wells

• Install production risers - avoid costly heavy lift installation vessel

• Production fluids offloaded to FPSO

• Workover & intervene - maximize reservoir recoverability

• Permanent installation over field life – new requirements


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Proposed Alternative

Drilling & Completion, Production & Installation - OVERVIEW

Flex Jumper

Free Standing Hybrid Riser(s) (FSHR)

Transfer System (s) (mid water or FSHR-flowline-Riser)

FPSO

Mooring

Subsea Tree

Subsea Umbilical

Drilling Riser

Mooring

Flowline

Manifold

Converted Semi-Sub: • Drilling • Production • Installation


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Proposed Alternative Field Layout Arrangement Rationale

• Constraints Accommodated:

• Subsea Tree - MOPU motions do not allow for dry tree Top Tensioned Risers

• FSHR – minimizes riser load even in deepwater

• Production transfer to FPSO - minimizes additional payload and deck space and allows the drilling rig to be maintained

• Subsea trees located under drilling vessel to enable through life drilling/workover access

• Offloads to leased FPSO providing overall low CAPEX solution

• Improved and alternate from TLP-FPSO Solution (W Africa, SE Asia and Brazil)


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Proposed Alternative Applications & Additional Benefits

• Particular value for:

• Fields that would otherwise need a substantial production and drilling host (PDQ)

• Marginal fields

• Early production / extended well test.

• But valuable for any (applicable) field:

• Long lead-time and expensive TLP/FPU can be avoided.

• Heavy construction vessel can be avoided


12

Historical Precedence

&

Current Scenario


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Historical Precedence FSHR’s to Date

Type Field Status Owner/Field

Operator Yr. Installed Region

Water Depth Vessel

(ft) (m)

Bu

nd

le

Green Canyon 29

Garden Banks 388

De-commissioned

Placid Oil Comp/

Ensearch 1988/1994 GoM 1,529/2,096 466/639 Semi-Submersible

Girassol Operating Total Elf 2001 Angola 4,430 1,350 Spread Moored FPSO

Rosa Operating Total Elf 2007 Angola 4,430 1,350 Spread Moored FPSO

BP Greater Plutonio Operating BP 2007 Angola 4,300 1,311 Spread Moored FPSO

Sin

gle

Lin

e

Kizomba A & B Operating Exxon 2004/2005 Angola 3,330-4,200 1,006 to 1,280

Spread Moored FPSO

Block 31 / PSVM Operating BP 2012 Angola 6,890 2,100 Turret Moored FPSO

P-52 Operating Petrobras 2007 Campos Basin

5,906 1,800 Semi-Submersible

Macondo De-commissioned

BP 2010 GoM 5,000 1,515 DP FPSO

Cascade/

Chinook Operating Petrobras 2010 GoM 8,531 2,600 Turret Moored FPSO

Block17/ CLOV Operating Total 2014 Angola 3,600-4,600 1,100-1,400 Spread Moored FPSO

Block32/ Kaombo Construction Total TBC Angola 4,675-6,315 1,425-1,925 Turret Moored FPSO

Note: bold indicates 2H involvement in FEED or Detailed Design Learn more at www.2hoffshore.com

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Historical Precedence MODU Conversions to FPU

• 15 conversions were carried out in last major oil downturn between 1986-1999

• Mostly semi-submersibles

• Typical water depths < 1,000m

• Subsea developments using flexible risers

Ref: Deegan, Loffman, Odufuwa, “The conversion of Mobile Offshore Drilling Units to Floating Production System – Issues, Opportunities and Challenges”, DOT 2014

Vessel Field Startup Region Water Depth (m)

Argyll FPU Argyll Oil Field 1975 UK North Sea 150

Buchan A Buchan oil field 1981 UK North Sea 160

P-09 Corvina Oil Field 1983 Brazil 230

P-15 Pirauna 1983 Brazil 243

P-12 Linguado / Badejo Oil

Field 1984 Brazil 100

P-21 Badejo / Salema Oil

Fields 1984 Brazil 112

Deepsea Pioneer FPU Argyll & Duncan Oil

Fields 1984 UK North Sea 150

P-22 Morela 1986 Brazil 114

P-07 Bicudo Oil Field 1988 Brazil 207

Veslefrikk B Veslefrikk Oil Field 1989 Norwegian Sea 175

AH001 Ivan Hoe Rob Roy Oil

Field 1989 UK North Sea 140

P-20 Marlim 1992 Brazil 625

P-08 Marimba Oil Field 1993 Brazil 423

P-13 Bijupira / Salema Oil

Field 1993 Brazil 625

P-14 Coral / Esrela /

Caravela Oil Fields 1993 Brazil 195

Nan Hai Tiao Zhan Luihua 1995 South China Sea 300

P-25 Albacora II Oil Field 1996 Brazil 252

P-27 Voador 1996 Brazil 533

Tahara PY-3 1997 Indian Ocean 339

P-19 Marlim 1997 Brazil 770

Janice A Janice Oil Field 1999 UK North Sea 80

P-36 Roncador 2000 Brazil 1360

SS-11 Coral 2003 Brazil 145

P-40 Marlim Sul 2004 Brazil 1080

ATP Innovator Gomez Oil Field 2006 Gulf of Mexico 914

Northern Producer

FPF

Originally Galley Oil

Field now at Don Oil

Field

2009 UK North Sea 350Learn more at www.2hoffshore.com

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Historical Precedence - Case Example Liuhua Field Development – Production and Drilling

Background:

• 300m water depth, South China Sea

• Marginal field, low recovery, high water cut

• Extend well tests

• Adjustable drilling & intervention requirements

Solution:

• Converted MODU: production and drilling capability

• Converted FPSO

• On seabed transfer – from manifold to FPSO

• Solution made development economically viable

Ref: Hall, Sheng, Krenek, Douglas, Macfarlane, “Liuhua 11-1 Development – Subsea Production System Overview”, OTC 1996, Paper 8175


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Current Scenario Worldwide Rig Count (Ref: HIS, Q3 2015)

• Opportunity for using idle low cost drilling vessel instead of new build TLWP w/ drilling rig

• Take advantage of current overcapacity in the drilling vessel market Learn more at www.2hoffshore.com

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Converted MODU

vs.

TLP/TLWP


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Converted MODU vs. TLP/TLWP Key MODU Advantages over TLP or Spar

• CAPEX - saving of up to 50% vs. TLWP/Spar

• Schedule - first oil anticipated by one year or more

• RISKEX - lower installation risk compared with TLP and Spar installations

• Maintain life of field workover capability for maximum reservoir recoverability

• Manage reservoir uncertainty

• Maximum end of life well count is not a driver for drilling vessel selection - flexibility

• Can also be an early production system

• Subsea architecture is organically expandable using the drilling vessel and a support vessel (MSV) to install more trees, risers, flowlines and jumpers

• Vessel and riser system can be readily retrieved and relocated


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Converted MODU vs. TLP/TLWP Key MODU Advantages over TLP/Spar

• Schedule - first oil anticipated by one year or more

• CAPEX - saving of up to 50% vs. TLWP/Spar

• RISKEX - lower installation risk compared with TLP and Spar installations

• Maintain life of field workover capability for maximum reservoir recoverability

• Manage reservoir uncertainty

• Maximum end of life well count is not a driver for drilling vessel selection - flexibility

• Can also be an early production system

• Subsea architecture is organically expandable using the drilling vessel and a support vessel (MSV) to install more trees, risers, flowlines and jumpers

• Vessel and riser system can be readily retrieved and relocated


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Converted MODU vs. TLP/TLWP Schedule Comparison

1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q

X

X

X

FSHR Installation (1 off)

Install flexibles and umbilicals (w flex

lay vessel)First oil (with 3 wells)

1st Batch 3 off Subsea Trees Delivery

(w manifold, well jumpers and 1st Batch 1 off Riser Delivery (w

surface and seabed jumpers)Mooring Pre Installation

Semi Installation

Drilling and completion from Semi (3

wells)

Integrated Rig With TLP

FEED

Sanction & Detailed Design

Puchase semi and conversion (w

permanent moorings)

Semi-submersible with FSHR

Tendon Installation

TLP Installation & Commissioning

(Ready to drill or complete)First completion and first oil (1 well)

Producing (3 wells)

MODU Drilling (Batch set conductors

and drill 4 wells)

FEED - 20 Slot TLP


TLP Construction & Integration

TLP Tendon Fabircation

1st Batch Riser Delivery (3 production

and 1 drilling)

Year 1 Year 2 Year 3 Year 4 Year 5

1st oil reduction over 1 year

Integrated Rig with TLP

Semi-Sub with FSHR


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Converted MODU vs. TLP/TLWP CAPEX Comparison

USD ~ 1.4 MM USD ~ 0.4 MM

$1,377,250,000

Integrated Rig With TLP

TLP Installation & Commissioning

(Ready to drill or complete)

First completion and first oil (1 well)

Producing (3 wells)

MODU Drilling

(Batch set conductors and drill 4 wells)

FEED - 20 Slot TLP


TLP Construction & Integration

TLP Tendon Fabircation

1st Batch Riser Delivery

(3 production and 1 drilling)

Tendon Installation

$90,000,000

$1,000,000,000

$90,000,000

$40,000,000

$25,000,000

$39,000,000

-

-

$93,250,000

Total $417,250,000Total

Mooring Pre Installation

Semi Installation

Drilling and completion from Semi (3 wells)

FSHR Installation (1 off)

Install flexibles and umbilicals

(w flex lay vessel)

First oil (with 3 wells)

FEED

-

-

$35,000,000

$290,000,000

$35,500,000

Semi-submersible with FSHR


Puchase semi and conversion

(w permanent moorings)1st Batch 3 off Subsea Trees Delivery

(w manifold, well jumpers and umbilical)1st Batch 1 off Riser Delivery

(w surface and seabed jumpers)$25,000,000

$5,250,000

$6,500,000

-

$12,500,000

$7,500,000


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Installation Method


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Installation Method (key steps) Field Proven

Foundation installed Aircan brought to moonpool

Vertical riser run w/ LRA attached (at bottom) URA connected (at top)


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Aircan connected to top of URA, lowered into water and ballasted

LRA landed and latched Aircan deballasted


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Vertical riser free-standing

Light construction vessel pays out flexible jumper ROV attaches A&R wire and connects jumper to URA


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Conclusions

&

Closing Remarks


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Conclusions & Closing Remarks

MODUs as MOPUs: Low cost field development using hybrid risers

• Solution achievable with a combination of field proven technical solutions

• Surplus rigs in the drilling market is an additional opportunity to reduce CAPEX by up to 50% and time to 1st Oil by 1 year compared to an equivalent TLWP

• Subsea trees and freestanding risers enable a MODU to be repurposed as a permanent moored drilling and workover vessel for deepwater

• Arrangement provides expansion flexibility to minimize upfront CAPEX and protect against reservoir uncertainty

• Risers and vessels can be retrieved and relocated


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Questions?

Thank you for your attention

Obrigado!

Pedro Viana | Technical Manager | 2H Offshore +44 1483 775027 [email protected]


mailto:[email protected]

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Proposed Alternative

Drilling & Completion, Production & Installation - OVERVIEW

Flex Jumper

Free Standing Hybrid Riser(s) (FSHR)

Transfer System (s) (mid water or FSHR-flowline-Riser)

FPSO

Mooring

Subsea Tree

Subsea Umbilical

Drilling Riser

Mooring

Flowline

Manifold

Converted Semi-Sub: • Drilling • Production • Installation


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Murphy Azurite FDPSO


modus as mopus: low cost field development · •subsea tree - mopu motions do not allow for dry...

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