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MANAGING RISK
Experiences with new DNV pipeline codes
Tommy BjørnsenDet Norske Veritas
Milestones in Offshore/Onshore Pipeline ResearchJapan – Norwegian SeminarTokyo, Japan, 27 May 2003
MANAGING RISK
Content of presentation
• Introduction• Historical perspective• Basis for the new DNV codes• Development of the new codes• Industry feedback• Further development• Summary and conclusions
MANAGING RISK
DNV Objective
To safeguard life, property and the environment
Foundation established 1864
2
MANAGING RISK
DNV - Main Industries
ProcessOil & Gas RailShipping Automotive
3
MANAGING RISK
DNV Pipeline Services• Assisting customers in:
– Selecting optimum technology and solutions
– Qualifying technology (incl. R&D)
– Verifying that technology is correctly applied
• Based on:– An in-house multidiscipline
technology environment– A close collaboration with
research institutions– Knowledge and experience
from all over the world
MANAGING RISK
The Blue Stream Project
• 2 x 24” pipelines, WT 31.8 mm• Offshore length 390 km• Project challenges:
– Water depth of 2150 m– Sediments with H2S content– Seismic activity– Sediment flow– Difficult topography– The required technological
innovation– Tight schedule– Development of repair
systems
MANAGING RISK
Pipelines in a historical perspective
• 1000 AC:First known gas pipelines made of bamboo, in Japan
MANAGING RISK
Pipelines in a historical perspective
• First oil pipeline was built for the Nobel brothers in Baku, 1878 – About 10 km and
76 mm diameter– Balakhany fields to
Nobel's refinery in Cherny Gorod
– Decreased transport cost with 95%
– The whole pipeline was paid back in one years time!!
MANAGING RISK
Pipelines in a historical perspective
Pipeline from Baku to the Black Sea in 1905
• 8 inch diameter• 800 km's long
MANAGING RISK
Historical perspectiveDesign code development
• In the US, the development of a national pressure piping code was discussed as early as 1915
• In March 1926, the American Standards Association initiated project B31
• In 1935 the American Tentative Standard Code for pressure piping, B31, was published
• In 1951, B31.4 & 8 were published
MANAGING RISK
DNV involvement in Pipelines
Historical perspectiveDesign code development
1900 1950 2000
ASM
E B3
1.4
&B3
1.8
DNV
Rule
s fo
r Sub
mar
ine
Pipe
line
syst
ems
1976
DNV
Rule
s fo
r Sub
mar
ine
Pipe
line
syst
ems
1981
BS 8
010:
3IS
O 1
3623
Allowable stress design
ASM
E B3
1 19
26
Limit state d.
DNV
Offs
hore
Sta
ndar
d F-
101
SUPERB1992-1996
The first limit statebased Pipeline design code with calibrated
safety factors!
DNV
Rule
s fo
r Sub
mar
ine
Pipe
line
syst
ems
1996
MANAGING RISK
Historical perspectivePremises for the “best” pipeline code
• Which one is the best design code?– The one that gives the thinnest wall?– The one that gives the thickest wall?
MANAGING RISK
Historical perspectivePremises for the “best” pipeline code
The first requirement of the code is:• Document sufficient safety level
Given the first premises, the second is:• Give the lowest total life-cycle cost
MANAGING RISK
Historical perspectivePremises for the “best” pipeline code
• What is sufficient safety level?– Traditional design codes have a historical
record accepted by society at large, hence they do provide sufficient safety level for traditional pipeline design in general
– For new applications and for optimisations (concepts, temperatures, pressures, water depths etc.) limit state based design codes are required to ensure consistent safety level
MANAGING RISK
Historical perspectivePremises for the “best” pipeline code
• Lowest life cycle cost
• Offshore pipelines cost appr. US$ 1000/m
• Cost optimisation
As installed pipeline cost
Installation40 %
Materials30 % Intervention
20 %
Engineering/ Admin
10 %
MANAGING RISK
Design format - Expressions
• Limit state methodology– Consider each failure mode independent
• Load and Resistance Factor Design (LRFD)– A “deterministic” design criteria with partial
safety factors (One interpretation of the limit state format)
• Structural reliability - probabilistic analyses– Tool to, for a given failure probability, calculate
partial safety factors
MANAGING RISK
Typical limit states in pipeline design
• Pressure containment• Local buckling
– Collapse– Combined loading– Propagating pressure
• Global buckling– Snaking– Upheaval buckling
• On bottom stability• Trawling interference
• Fatigue due to– Pressure variations– Temperature– Vortex shedding
• Fracture– Fracture propagation
(Content dependent)– ECA
• Ovalisation• Ratcheting
MANAGING RISK
Collapse and propagating buckling
MANAGING RISK
Design formatLRFD versus ASD
• ASD– Easy to use– Less checks– (Should) Give(s)
same result as LRFD for ”normal design”
– Includes (implicit) design rule of thumbs
• LRFD– Consistent safety
level– Flexible– Allows optimisation– Less dependent on
assumptions– Can easier be
extended to new scenarios
MANAGING RISK
SUPERB Project
• ObjectiveDevelopment of a SUbmarine PipelinEReliability Based design guideline and in that respect to review and update design recommendations and criteria for pipeline design
MANAGING RISK
SUPERB-The Project
Pre-phase Phase 1M Phase 2M Phase 3M• Pilot
studies• Safety
assessment• State of art
Technology
• Technologydevelopment
• Revised Safetyand CalibrationProcedures
• Draft Guideline
• Synthesis• Finalization• Guidelines
US$ 100 k US$ 500 k US$ 500 k US$ 400 k
MANAGING RISK
SUPERB -Database; Model uncertainty
Property Data points Projects Validity
Burst 76 (22SUPERB)
X52-X1206<D/t<25
Collapse S=0,Seamless, UOE
3500 (39) (6-7) X65-X7016<D/t<45
Collapse+axial 15-20
Collapse+moment 148 X52-X70
MomentSmall pipes
>100(+50 FEM)
X52-
Internal pressure+moment
2 (+100 FEM)
Burst (corroded) >100 (60)(+500 FEM)
MANAGING RISK
SUPERB -Database; Material (Welded only)
Property Data points Projects Validity
Yield >1000 >20 X60-X80
Ultimate >1000 17 X60-X80
Y/T >100 >5 X60-X80
CTOD 291 100
MANAGING RISK
New DNV pipeline codes
• DNV’96 was published on the basis of the results from the SUPERB project
• This included:– Limit state based design – Calibrated safety factors– Further benefit to improved material quality
(ductility and yield stress distributions)• DNV’96 was updated and published as
DNV-OS-F101 in 2000• An extensive list of additional documents
supporting the main pipeline standard
MANAGING RISK
Recommended PracticesDNV-RP
Offshore StandardDNV-OS
Offshore Service Specification
DNV-OSS
DNV Offshore Codes
Quali
ty &S
afety
Stru
ctur
es Systems
Special Facilities
Pipelines & RisersMater
ials T
echn
ology
FA B C D E
Clas
s
Shelf
Com
pl.
Cert.
MANAGING RISK
DNV Offshore CodesOffshore Standard (OS)
• Technical requirements only
• Harmonised with ISO– ISO 13623 Pipeline
Transportation Systems– ISO 3813-3 Linepipe
• Limit state based design criteria
• Calibrated safety factors
MANAGING RISK
Under developmentExisting
Residual strength
Corroded pipes(British Gas)
Mechanical Pipeline Couplings
Gudesp(DHI)
Multispan(DHI, Snamprogetti)
Protection(Statoil)
Reeling JIP(Sintef & TWI)
DNV Offshore CodesRecommended Practices (RP)
TrawlingDNV-RP-F10X
Design of HT/HP
Pipelines
DNV-RP-F10XDesign of
HT/HP Pipelines
Hotpipe(Statoil, ShellSnamprogetti)
Design of Titanium Risers
MANAGING RISK
DNV Offshore Codes DNV-OS-F101 -The World
Blue StreamGazprom/ENI
Two 610 mm diameter pipelines from Russia to Turkey across the Black Sea. Maximum water depth is 2150 meters. Length is 2 x 400 km
Nam Con Son BP Amoco
A 360 km, 32” submarine pipeline from the offshore field complex to
the onshore gas terminal.
West Natuna Pipeline Project Conoco
A 600 km, 28” submarine pipeline from the offshore field complex in Indonesian waters to the onshore
gas terminal in Singapore.
Zakum Gas Injection Project Adma-Opco
Two high pressure gas injection pipelines for the Zakum field. This was the first project that applied the DNV’96 in the Middle East.
Tangguh Field Development Arco
Situated in the "Bird’s Head" area of West IrianJaya,. The Upstream platform facilities are
approximately 25km km apart with conventional platforms and gas being exported by submarine
pipelines, 20km to 30km in length, to the Onshore Receiving Facility (ORF). The gas has a relatively high CO2 and H2S content and includes free water.
Mardi Gras Pipeline transportation system (BP)Several fields including Crazy Horse (6300ft)MMS approved use of DNV-OS-F101 for this
project
MANAGING RISK
DNV Offshore CodesReception from the industry
“Comparing DNV’96 to traditional pipeline design is
like comparing a modern computer to a computer from
the 1980ies...”
Prof. A. Palmer OPT Conference 25-26 Feb. 1999 Amsterdam
MANAGING RISK
Upstream, 18 February 2000: (ExxonMobil Natuna Project, Indonesia)
• • Adoption of the ‘1996 DNV Rules for submarine pipeline systems’, resulting in a safer and lower-cost pipeline design.
DNV Offshore CodesReception from the industry
MANAGING RISK
DNV Offshore CodesReception from the industry
• Norwegian Deep-water Program (NDP)– Andrew Palmer and Associates, UK, evaluated
different codes in order to recommend one particularly suited for deep water applications
– They recommended DNV-OS-F101 • BP (Houston / GoM)
– Intec (Houston) evaluated different codes with the objective to recommend one for the deep-water field MardiGras
– They recommended DNV-OS-F101
MANAGING RISK
Further development
• Plans for an update of OS-F101• High strength steel (X80+)• New Recommended Practises are being
developed as required (e.g. HT/HP pipelines and pipelines undergoing plastic deformation during installation and operation))
• Large effort on the in-service phase, Pipeline Integrity Management (PIM)
• New EU directive on safety hazards, DNV leads consortium on PIM guidelines
MANAGING RISK
Summary and conclusions
• DNV pipeline codes have been developed based on an extensive industry collaboration and international Joint Industry Projects (Norwegian participants has played a key role)
• These codes represents cutting edge within pipeline technology
• They are in line with current ISO standards• They are in use world wide• Feedback from the users are being used to update
and improve
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