ASPIRE for 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 objectives:

• 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 operations;

• 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 & 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 PIPE 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 byc1/c2 = 0.25, 0.5, or 1.0

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

Conclusion of 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 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

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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.

Loading

Axial CompressionPi: - 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 BendingMe:- Bending moment due to environmental condition such as “100

year storm – Wave and current” calculated by SACS softwareMi:- 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 Breathing Window

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 ScanConductor 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

Spla

sh Z

on

e

SPLASH ZONE INSPECTION

Remaining Life Assessment

External Indication Internal Indication

Segm

ent

1(M

arin

e co

rro

sio

n z

on

e)

Segm

ent

2(S

pla

sh z

on

e)Se

gmen

t 3

(Sea

Wat

er z

on

e)

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

MRTtRL

imm )(

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

TrdtCR nom

Corrosion Rates

Mar

ine

Zo

ne

Spla

sh Z

on

eLiterature

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 TheElectrochemical Society.

Current Study

According to HSE Research Report 016 - Guideline for use of statistics analysis of sample

inspection of corrosion

Estimated CR will be the 95% confidence limit

Risk and Risk Based Remaining Life

• Predictive target risk date (RLI)

• Inspection frequency determined

Risk and Risk Based Remaining Life

5

4

3

2

1

CONSEQUENCE

EDCBA

PR

OB

AB

ILIT

Y

Very High

Water

Injection

Unmanned

Very Low Low Medium High

10-2

High

10-3

Medium

10-4

10-5

10-6

Low

Very High

M anned or

OH (1)>15000OH(1)>15000OH(1)<15000OH(1)<15000

Very Low

OP (1)>10000OP (1)<10000OP (1)>10000OP (1)<10000

BS 7910 – Annex K

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

• The remaining time to exceed the Probability of Failure (PoF) target will be considered as the RiskBased Remaining Life (RBRL).

Results per section of 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 YearsCurrent Risk

1 1 2

2 2 2

15 22 25

4 23

25 28 33

1

1

5 1

A B C D E

CONSEQUENCE

Unmanned M anned or

Very Low Low Medium High Very High

10-6

Water

Injection

OP (1)<10000 OP (1)>10000 OP (1)<10000 OP (1)>10000

OH (1)<15000 OH (1)<15000 OH (1)>15000 OH (1)>15000

PR

OB

AB

ILIT

Y

Very High

10-2

High

10-3

Medium

10-4

Low

10-5

Very Low

A B C D E

CONSEQUENCE

Unmanned M anned or

Very Low Low Medium High Very High

10-6

Water

Injection

OP (1)<10000 OP (1)>10000 OP (1)<10000 OP (1)>10000

OH (1)<15000 OH (1)<15000 OH (1)>15000 OH (1)>15000

PR

OB

AB

ILIT

YVery High

10-2

High

10-3

Medium

10-4

Low

10-5

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 validate

Proposed methodology:

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

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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 of corrosion to be defined and a reduction strength factor to be applied.