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The Marlim FieldDevelopment: Strategies and
Challenges
Ricardo Juiniti Bernardo -Petrobras
Presentation Summary
Campos Basin Overview
Marlim Field Development Strategies
Evolution of Driling and Completion
Techniques
Challenges to Be Overcome
Conclusions
Campos Basin Overview
Marlim Field Development Strategies
Evolution of Driling and Completion
Techniques
Challenges to Be Overcome
Conclusions
The Campos Basin
Title SlideShallow reservoir(~ 3,000 m total depth)
Mild environmental conditions( presence of high currents)
Steep slope seabed profile(including even canyons)
Unconsolidated sandstone indeepwater
The Campos BasinThe Campos Basin
• 1971 - Jack-ups - WD 50 m– TD from 1,500 m to 3,500
m. – OBS Systems
• 1972 - Drillships - WD > 80 m– Different Wellhead
Systems (SG- 1 and HB 3 - 16 3/4”)VinegarronVinegarron
The Campos Basin The Campos Basin • December 1974 – Well 1 RJS 9A - Garoupa Field
– WD: 124 m – TD at 3,750 m
Drillship Petrobras IIDrillship Petrobras II
The Campos Basin The Campos Basin
• August 13, 1977 – Well 3 EN 1 RJS –Early Production System of Enchova Field
– One vertical well producing through the BOP (10,000 bopd)
– TD: 2,520 meters
The Campos Basin The Campos Basin • 1979: Garoupa - Namorado Project
– Drilling:–Directional Wells ( max. deviation 35
degrees ) – Completion:
–7 gas lift valves + 1 kill valve–Permanent Downhole Gauge
The Campos Basin
1979: Garoupa - Namorado
The Campos Basin The Campos Basin
• 1979 : Subsea Completion in Bonito Field – Well 4 RJS 38
• 4 casing strings + 7” liner
• TD at 2,800 meters
• First sand control installation from a floating rig
The Campos Basin The Campos Basin
• 1979 – 1983 Implementation of Other Early Production Systems and Floating Production Units
– Standardization of the wellhead systems (18 ¾”).
– Drilling design: 30” / 20” / 13 3/8”/ 9 5/8” production casing or 7” production liner.
– Poor Performance of Permanent Downhole Gauges
– Use of Subsea Trees and gas lifting
Corvina EPSCorvina EPS
The Campos Basin The Campos Basin
• 1981 - 1984 Installation of Fixed Platforms from 108 to 170 m
– Wells drilled after platform installation
– 4 casing strings plus a 7” liner when required.
– Directional drilling : max. deviation 45 degrees.
– Sand control was not mandatory
Garoupa PlatformGaroupa Platform
The Campos Basin The Campos Basin
• 1989 - Installation of Fixed Platforms in “Polo Nordeste”
– Wells drilled from semis and drillships during the jackets construction.
– 4 casing strings plus a 7” liner– Use of Electrical Submersible
Pumps
Garoupa PlatformGaroupa Platform
The move towards deeper watersThe move towards deeper waters
1982 - Exploratory drilling in WD > 400 m
1984 - Dynamic Positioning Rigs
• Exploratory drilling in WD > 500 m
• Workovers in shallow and cluttered areas
1982 - Exploratory drilling in WD > 400 m
1984 - Dynamic Positioning Rigs
• Exploratory drilling in WD > 500 m
• Workovers in shallow and cluttered areas
The Campos Basin
The Marlim Field
Discovered in 1985
Total Area: 132 square Km.
WD: 650 to 1,050 m
Oil Gravity: 19 to 24 API
High Productivity Index
Poorly Consolidated Sandstone
Dependent on water injection
First Oil in 1991
The Challenges
Technological
Capital Expenditure
Period: 1986 to 1991
Portfolio: 109 projectsPetrobras 13
Marlim Field Development Strategies
Subsea Completions with Floating Production Units
Early Production System guided the Definitive development plan
Phased Development with the incorporation of the lessons learned in the previous phases
Marlim Field Development - 1989
• 135 production wells
• 20 water injection wells
• 9 FPU’s
• Peak Production : 430,000 bopd
Present Situation
Unit Type WD (m)Processing
Capacity (m³/day)
Start up
P-20 SEMI 620 10.350 June/92P-18 SEMI 910 15.900 June/94P-19 SEMI 770 15.900 Dec/97P-26 SEMI 990 20.000 March/98P-32 FSO 160 18.480 June/98P-33 FPSO 780 10.000 Dec/98P-35 FPSO 850 20.700 Aug/99P-37 FPSO 905 28.800 July/00
Current Production:490,000 bopd 129 subsea wells5 subsea manifolds
Present SituationReservoir Management
The Marlim Field
Evolution of Drilling and CompletionTechnology in Deepwater
Evaluation of Drilling and Completion Technology
• Well Design
• Sand Control Operations
Well Design
1991 / 95: Vertical and directional wells
1995: First Horizontal Well -•Water injection ( 8 MRL 38H ) 905m WD
screens with no gravel pack
2005- 27 horizontal production wells and 7 horizontal water production wells160 to 1,138 m of horizontal section
3 MRL 3 RJSDrilled in 1989
48”Conductor
30”20”
13 3/8’
9 5/8”
• Vertical well• 48” conductor pipe• 4 casing strings• 9 5/8” production casing
3 MRL 3 RJSon stream since 1991
• 20 m of perforations• Gravel pack (slurry pack)• 5 1/2” Production string• 6,000 bopd
7 MRL 150 HPdrilled in 2001
30“Condutor
13 3/8“
9 5/8“
- Jetted 30”casing- 9 5/8” casing shoe
inside the reservoir
7 MRL 150 HPdrilled in 2001
- Open hole 8 1/2”- 400 to 420 meters long
30“Condutor
13 3/8“
9 5/8“
7 MRL 150 HPon stream since 2001
- 5 1/2” OD screens- Gravel Pack- External Casing Packer- 15,000 bopd
ECP
30“Condutor
13 3/8“
9 5/8“
Sand Control OperationsVertical and Directional Wells
• 1991 - Slurry PackSignificant drop of the PI
• 1995 - Water PackImprovement over slurry pack operations
• 1998 - Frac PackSimplified sand control operationsNo significant drop of the PI
Sand Control in Deepwater Developments
Slurry Pack•Perforations in underbalance
•Flow the well to clean perforations
• Adequate casing and stringcleaning
• Significant drop of the PI
• Acid Jobs were required
Sand Control in Deepwater Developments
Water Pack•Introduced in 1995
•Improved the PI if comparedto slurry pack systems
•Nowadays is limited to 12 meters long intervals wherethe oil/water contact is present
Sand Control OperationsHorizontal Wells
• Stand Alone systems in injection and production wells
higher PI sand production above 0,01 %
• Open Hole Gravel Packsuccessfully used for sand control
Sand Control OperationsHorizontal Wells
• OHGP systems with ECP
• Expandable screens
Challenges in Sand Control Operationsin the Campos Basin ( 1 )
• Long Horizontal sections up to 2,000 meters in unconsolidated sandstone
• To improve Drill in Fluid removal in water injection wells ( time x efficiency )
Challenges in Sand Control Operationsin Campos Basin ( 2 )
• Selective Open Hole Gravel Pack Operations
• Smart Completions + Sand Control in Deviated and Horizontal Wells
Marlim Field Development Strategies
SubseaStandardization Program for the Subsea Trees
Standardization on the Flowlines ConnectionSystems
2 8 7 1731 38
58
76
102
122 127 129
31
0
20
40
60
80
100
120
140
1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003
Year
Num
ber o
f Wel
ls
0
0,25
0,5
0,75
1
Rat
io o
f In
terv
entio
ns
Number of Wells % of Interventions
Present SituationNumber of Interventions
Challenges to Be Overcome
Oil Production until 2025
Water Injection
Produced Water Processing
Aging of the wells
In a profitable way…..
Oil Production until 2025
Water Injection
Produced Water Processing
Aging of the wells
In a profitable way…..
Challenges to Be Overcome
Topsides
Subsea Separation
Raw Water Injection
Topsides
Subsea Separation
Raw Water Injection
W-O SEPARATION SUBSEA SYSTEM
WATER INJECTION
OIL+GAS
PRODUCER
water
oil
gas
wellstream
Challenges to Be Overcome
Flow Assurance
Hydrates
Emulsion
Flow Assurance
Hydrates
Emulsion
Challenges to Be Overcome
Well Operations
Workovers / New Wells
Cost of the rigs
Subsea Equipment
Integrity of the subsea equipment
Flowlines and risers inspection
Well Operations
Workovers / New Wells
Cost of the rigs
Subsea Equipment
Integrity of the subsea equipment
Flowlines and risers inspection
Conclusions ( 1/2)
• Drilling and Completion projects werehighly influenced by technologicalinnovations.
• Significant evolution in spud in operations decreased drilling time.
• Use of horizontal wells allowed reduction of total number of wells.
Conclusions ( 2 / 2 )
• Evolution of Sand Control Techniquesimproved productivity indexes.
• Marlim Field: Laboratory for thedevelopment of deepwater technology.
• With the field maturation new challenges willhave to be overcome to ensure the forecasted levels of production.
