ASPIRE for In Integrity Management Support for Upstream Assets - - PowerPoint PPT Presentation

ASPIRE for In Integrity Management Support for Upstream Assets

Payam Jamshidi, TWI Ltd Sebastian Hartmann, Innospection Ltd

OVERVIEW

• Discussion of corroded pipe assessment procedures

under combined loading

• What do we need? How we derived to assessment of

conductors?

• Current study and our approach
• Assessment of well conductors
• Some results
• Conclusion

The ultimate objective of this project was to integrate the collection, management and analyses of inspection data for the purpose of providing RBI and repair decision making for upstream assets. This will be achieved by the following

• bjectives:
• To develop a customisable probabilistic based algorithm and software

to use advanced reliability methods to assess failure scenarios for several types of non-standard geometries, loading, environment and

• perations;
• To link the software to different NDT technologies to analyse the

results seamlessly;

• To validate the algorithm through pilot implementations on project

partners’ identified cases.

Objectives

The ASPIRETM - Project 760460 is funded by the EU under the Horizon 2020 Framework Programme

• In the last 10 years, 34% of oil & gas

losses happened in upstream ~ $12 billion

OIL IL & GAS ACCIDENTS

The 100 Largest Losses 1974-2013, Large property damage losses in the Hydrocarbon Industry, 23rd Edition, MARSH

Engineering structures such as flexible risers, free-standing or top- tensioned rigid risers, and steel catenary risers are continuously subject to global bending moments in addition to axial loads and/or internal

• pressure. Global bending plays an important role when the assessment is

applied to deep sea offshore pipes.

ASSETS SUBJECT TO COMBINED LOADING

• Pressure equipment used in the oil and gas industry is typically

subjected to multiple loads (internal pressure, axial stress, global bending).

• There are limited numbers of research programs addressing the

assessment of corrosion defects in pipeline structures subjected to global bending, compressive loading or combination

• Several methods for the assessment of corroded pipeline subjected to

internal pressure loading are currently available; such as ASME B31G, DNV-RP-F101 RSTENGTH, API 579, etc.

• These methods do not take into account the effect of global bending or

longitudinal compressive load on the failure of the corroded structure and their predictions of failure pressure are quite conservative compared to the full scale tests*.

• Benjamin, A.C. (2013). “Prediction of the failure pressure of corroded pipelines subjected to a longitudinal

compressive force superimposed on the pressure loading”, The Journal of Pipeline Engineering, pp301.

CORRODED PIP IPE ASSESSMENT

Past Study at TWI

• Assessment of LTAs in pipe structures subject to global bending and compressive loading

and compares the results to the BS7910 reference stress solutions.

• FEA is carried out to produce collapse loads of pipe structures containing corroded areas

(with different LTA aspect ratios) subject to global bending, internal pressure, axial tension and ultimately combined bending and compression.

• The model was calibrated against BS7910 under conditions of internal pressure and axial

tension.

• All models were analyzed to cover a wide range of LTA depth to pipe thickness ratios and

aspect ratios so as to generate a closed-form or tabulated solution.

Past Study at TWI

• The following depth to pipe wall thickness (B) ratios were analyzed:

a/B = 0.3, 0.5 or 0.7

• The axial lengths given by

c1/c2 = 0.25, 0.5, or 1.0

The LTA was meshed densely whilst away from the LTA, the mesh was coarser.

Conclusion of f Past Study at TWI

• The BS 7910 equations were conservative as would be expected.
• In terms of total axial stress at failure, these analyses showed that compressive

loads reduce the failure load; that the failure load is further reduced under combined loading, but that the BS7910 equations could still be used to provide conservative solutions (for all cases analyzed).

• The failure criterion employed in this work has been validated extensively for

internal pressure loads (and internal pressure with end cap axial forces). However, little experimental work has been done to verify the FEA failure criterion for other external load combinations and therefore experimental testing should be undertaken to verify the numerical procedures.

• Offshore well bores consist of several concentric tubes
• The outermost well casing, the conductor, protects the inside casings from aggressive corrosion.
• The conductor should not leak, nor buckle or collapse under both axial load and bending moment

Well ll Conductors

Past Conductor Failures

• Purpose
• To demonstrate / document viability & integrity of each of conductors
• For next “x” years – Endorsement period – Time/Risk Based Inspection

period

• Avoiding any major repairs
• Process
• Review of available data
• Design analyses and engineering assessments
• Inspection scopes & results
• Operational history including incidents

12

Well Conductors

• Design check of well conductors is a stability check based on international best practices:
• Petroleum and Natural Gas Industries, “Fixed Offshore Platform”, ISO-19902, 2007
• Institute of Petroleum, “Guideline for the Analysis of Jackup and Fixed Platform Well Conductor System”, 2001
• Design of Concentric Tubular Members, G. R. Imm, B. Stahl, Offshore Technology Conference, 1988.
• Design Methodology for Offshore Platform Conductors, B. Stahl, M. P. Baur, Offshore Technology Conference, 1980.
• Minimum Required Thickness (MRT) is the thickness below which the required cross

sectional area is not achieved and failure may occur

• Grouting in annulus of conductor and other internal casing/tubing will influence the MRT
• calculation. It will be in-conservative not to consider the effect of grouting.

Assessment Procedure

In summary, design evaluation of conductors include:

• Determine the equivalent section of the conductor by the supports configuration.
• Determine the stiffness of the conductor based on effective length
• Calculation of the axial loads and bending moment
• Calculation of stress ratio

MRT calculation which is the critical thickness at which the stress ratio is equal to 1.0.

Conductor Subjected to Axial, Internal and Bending Strength Check Stability Check Stress Buckling

Assessment Procedure

Design of Concentric Tubular Members, G. R. Imm, B. Stahl, Offshore Technology Conference, 1988.

Lo Loading

Axial Compression Pi:

• Axial load due to weight of conductor, internal casings etc.

Pe:

• Axial load at each elevation due to weight on top of the conductor

Pi & Pe

Mi & Me

Global Bending

Me:

• Bending moment due to environmental condition such as “100

year storm – Wave and current” calculated by SACS software Mi:

• Bending moment due to eccentricity of casings

• Breathing window in a section causes reduction in Area and consequently reducing

the Second Moment of Inertia of that loading section.

• Based on the size of each window (by using principles of mathematic and solid

mechanic), reduction factors for Area and Moment of Inertia are multiplied in properties of the intact section.

Effect of f Breathing Win indow

Assessment Procedure

Assessment Procedure

• Operations
• Little pipe preparation needed (no couplant)
• Remote controlled deployment
• NDE key points
• up to 1.3” Wall Thickness, sensitive for isolated pit detection, sizing accuracy ≤ +/- 10%
• inspection through coatings (Neoprene etc.) & CRA layers (Monel, Inconel, TSA )
• inspection speed (net average run speed 0.25m – 0.5 m/sec)
• separate C-Scan corrosion mapping of near side & far side or merged
• Direct online data assessment & integrity assessing data set up

Example field applications Flexible Riser Scan Conductor Scan Caisson/Riser scan

MEC TECHNOLOGY

Splash Zone Inspection & Assesment Support

Riser / Caisson / Conductor

• Combined cleaning & inspection
• MEC & UT Technology combination
• Inspecting through coatings
• No operational interruptions
• ROBOTIC TOP SIDE DEPLOYMENT &

REMOTE CONTROLLED DRIVE

Splash Zone

SPLASH ZONE INSPECTION

Remaining Lif ife Assessment

External Indication Internal Indication Segment 1 (Marine corrosion zone) Segment 2 (Splash zone) Segment 3 (Sea Water zone)

The retirement thickness required to meet the loading condition at each segment of the conductor Distribution of corrosion rate per segments based on thickness data or corrosion models

CR MRT t RL

i mm ) (

 

Averaged Minimum measured thickness from the SLOFEC results

Distribution of RL (per segment)

• The remaining time to

exceed the Probability of Failure (PoF) target will be considered as the risk based remaining life. Cumulative Distribution Function (CDF)

SLOFEC Inspection Results

1 2 3 4 5

age Trd t CR

nom 



Corrosion Rates

Marine Zone Splash Zone

Literature

Zones of corrosion for Steel Piling in Seawater

Source: F. L. LaQue, Marine Corrosion cause and Precention, P. 116, john Wiley & Sons, 1975. Reproduced by permission of The Electrochemical Society.

Current Study

According to HSE Research Report 016 - Guideline for use

• f statistics analysis of sample

inspection of corrosion

Estimated CR will be the 95% confidence limit

Ris isk and Ris isk Based Remaining Lif ife

• Predictive target risk date

(RLI)

• Inspection frequency

determined

Risk and Risk Based Remaining Li Life

5 4 3 2 1

CONSEQUENCE

E D C B A

PROBABILITY

Very High

Water Injection Unmanned

Very Low Low Medium High

1 0-2

High

1 0-3

Medium

1 0-4 1

• 5

1 0-6

Low Very High

M anned or OH(1)>1 5000 OH(1)>1 5000 OH(1)<1 5000 OH(1)<1 5000

Very Low

OP

0000 OP

0000 OP

0000 OP

0000

BS 7910 – Annex K

• Distribution of Remaining Life due to the distribution in Corrosion Rate (per each section of the

conductor)

• The remaining time to exceed the Probability of Failure (PoF) target will be considered as the Risk

Based Remaining Life (RBRL).

Results per section of f conductors

5 5 4 4 3 3 2 2 1 1

Total of 98 sections from 25 conductors

9 2 2 Forcasted Risk In 7 Years Current Risk 1 1 2 2 2 2 15 22 25 4 2 3 25 28 33 1 1 5 1

A B C D E

CONSEQUENCE

Unmanned M anned or

Very Low Low Medium High Very High

1 0-6 Water Injection OP

0000 OP

0000 OP

0000 OP

0000 OH(1)<1 5000 OH(1)<1 5000 OH(1)>1 5000 OH(1)>1 5000

PROBABILITY

Very High

1 0-2

High

1 0-3

Medium

1 0-4

Low

1 0-5

Very Low

A B C D E

CONSEQUENCE

Unmanned M anned or

Very Low Low Medium High Very High

1 0-6 Water Injection OP

0000 OP

0000 OP

0000 OP

0000 OH(1)<1 5000 OH(1)<1 5000 OH(1)>1 5000 OH(1)>1 5000

PROBABILITY

Very High

1 0-2

High

1 0-3

Medium

1 0-4

Low

1 0-5

Very Low

AUTOMATED MODELLING

To reduce the level of conservatism built into these equations, finite element modelling can be used. This allows for:

• Accurate/realistic modelling of the corrosion defect geometry
• Incorporation of non-linear strain-hardening properties (full stress-

strain curve)

• Incorporation of non-linear deformation behaviour (buckling/bulging)
• Combined loading conditions

FEA to vali lidate

Proposed methodology:

Method 1: Applying a reduction strength factor. Method 2: Define distance criteria between two patches of corrosion

29

ASPIRE Software

30

ASPIRE Software

31

ASPIRE Software

32

ASPIRE Software

Conclusion

• Methodology for assessment of corroded pipes under combined

loading was proposed.

• This methodology was applied for conductors with probabilistic

approach for reliability assessment.

• This probabilistic risk model was designed for assessment of

conductors in terms of Run Length Index (RLI)

• Application of FEA proposed: distance criteria between two patches
• f corrosion to be defined and a reduction strength factor to be

applied.