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3 rd International Pipeline Technology Conference, May 22-24, Brugge, Belgium

An Assessment Procedure to Justify Operation of Gas Transmission Pipelines at Design Factors up to 0.8 A. Francisa , A.M. Edwardsa , R.J. Espinera and G. Seniora a

BG Technology Ltd., Gas Research & Technology Centre, Ashby Road, Loughborough, Leicestershire, LE11 3GR, UK. The objective of the recommendations given in IGE/TD/1 is to ensure that onshore highpressure gas transmission pipelines are designed, constructed and operated safely. The current recommendations limit the design factor to 0.72 but allow deviation from this limit if justified through a reliability/risk analysis. It is thus accepted that pipelines may operate at design factors above 0.72 provided that a detailed reliability/risk based assessment demonstrates that it is safe to do so. The production and review of such assessments involves considerable effort from both the operator and the regulator. It is recognised that a more expedient course of action is to develop a set of design requirements that allow safe operation at design factors greater than 0.72 and accordingly recommend amendments to IGE/TD/1. This paper presents the analysis and results of a work programme aimed at providing justification for increasing the maximum allowable design factor in IGE/TD/1 to 0.8. Structural reliability analysis is used to quantify the level of safety that is implicitly acceptable in the current edition of IGE/TD/1 and to identify the generic requirements that will allow safe operation at design factors up to and including 0.8. It is concluded that safe operation at design factors of 0.8 is achievable and a 3-level assessment procedure detailed within this paper is recommended for inclusion in IGE/TD/1 Edition 4 due for publication late 2000. 1. INTRODUCTION The UK pipeline operator Transco has recently uprated 230 km of high-pressure transmission pipelines to a design factor of 0.78. The integrity of these lines was demonstrated using structural reliability assessment (SRA) and was possible because, although the governing design code IGE/TD/1 [1] specifies a maximum design factor of 0.72, it does not preclude operation above this limit subject to the use of improved techniques.


3 rd International Pipeline Technology Conference, May 22-24, Brugge, Belgium

The production and review of such assessments requires considerable effort from both the operator and the regulator. However, previous work has shown that design factor is not the only parameter governing the likelihood of failure. Other important parameters include minimum wall thickness, inspection interval, material grade and defect repair criteria. The effect of these parameters is not explicitly recognised by IGE/TD/1. Thus whilst operational experience has led to pipelines designed and operated to IGE/TD/1 being regarded as inherently safe, the simplicity of the design recommendations precludes explicit recognition of the contributions to safety of some these key parameters and means that there are inconsistencies in safety levels. In particular it is possible that some pipelines operating at high design factors are safer than others operating at a lower design factor. This paper presents the results of a study to identify a set of generic requirements for safe operation at design factors greater than 0.72. SRA is used to quantify the effect of all parameters that influence safety and quantify the level of safety implicitly acceptable in the current edition of IGE/TD/1. SRA is then used to identify the design requirements that will allow equally safe operation at design factors up to and including 0.8. The outcome of the study shows that safe operation at design factors of 0.8 is achievable and it is recommended that results of the study are included in Edition 4 of IGE/TD/1. 2. APPROACH TO JUSTIFYING OPERATION AT A DESIGN FACTOR OF 0.8 It is proposed that a pipeline may be safely operated at a design factor, f+ , of 0.8 if the risk is less than or equal to the risk level which is implicit in IGE/TD/1 at present. There is significant safe operational experience at the current IGE/TD/1 design factor limit of 0.72 and the risk associated with this operational limit is therefore considered to be acceptable. For rural area (Type R) pipelines, IGE/TD/1 defines 8 pipeline diameter ranges. The consequences of a pipeline failure are controlled through specified building proximity distances (BPDs) that are a function of the diameter range and pressure. Therefore, provided the BPD requirement is satisfied, limiting the probability of failure for a pipeline operating at f = 0.8 to a level implicitly acceptable for a pipeline of the same diameter range at f = 0.72 ensures that safety is also maintained to an implicitly acceptable level. In order to maintain the basic structure of IGE/TD/1 the analysis presented here considers the probability of failure for each diameter range. 2.1 Proposed assessment procedure A 3-level SRA based assessment procedure is proposed for justifying operation at a design factor up to and including 0.8. Each level of the procedure will require an increasing complexity of analysis, with the full SRA approach detailed in [3, 6, 7, 10] forming the most complex level.


3 rd International Pipeline Technology Conference, May 22-24, Brugge, Belgium

Level 1.

A comparable level of safety to that implicitly accepted in IGE/TD/1 Edition 3 at f = 0.72 can be demonstrated at f = 0.8 without the need for protective measures + beyond the minimum recommendations given in IGE/TD/1 Edition 3.

Level 2.

A comparable level of safety to that implicitly accepted in IGE/TD/1 Edition 3 at f = 0.72 can be demonstrated at f = 0.8 if protective measures beyond the minimum recommendations given in IGE/TD/1 Edition 3 are applied.

Level 3.

A comparable level of safety to that implicitly accepted in IGE/TD/1 Edition 3 at f = 0.72 can be demonstrated at f = 0.8 if a full Structural Reliability Analysis (SRA) is conducted.

The proposed procedure for justifying operation at f = 0.8 is illustrated in the flow diagram given in Fig. 1. Define all credible failure modes that will cause the pipeline to reach the Ultimate Limit States

Does the pipeline case satisfy the Level 1 assessment criteria?

YES

NO

Does the pipeline case satisfy the Level 2 assessment criteria?

YES

NO Level 3 assessment (full SRA) required (See Fig. 2)

+

Design factor, f, defined in IGE/TD/1 [1] Section 6.4.2

Pipeline suitable for operation at f = 0.8


3 rd International Pipeline Technology Conference, May 22-24, Brugge, Belgium

Fig 1. Proposed 3-level Assessment Procedure The requirements of the Level 1 and Level 2 analysis and their formulation are detailed in Sections 3 to 5. The Level 3 approach follows the methodology given in Section 3.1 and has been extensively reported elsewhere [3, 6, 7, 10].


3 rd International Pipeline Technology Conference, May 22-24, Brugge, Belgium

3. DEVELOPMENT OF LEVEL 1 AND LEVEL 2 CRITERIA 3.1 Overview of Structural Reliability Analysis SRA comprises six basic elements, namely: 1. 2. 3. 4. 5. 6.

Establishment of limit states Identification of failure modes Formulation of limit state functions Uncertainty analysis Evaluation of the failure probability Assessment of the results

The interaction of these elements is shown schematically in Fig. 2 and a general description of each element is given in [10]. Establish limit states

1 . 2

Identify failure modes

3

Identify limit state functions

. . 4 . 5

Quantify variation in pipeline geometry

Quantify variation in material properties

Quantify variation in defect size and growth

Quantify variation in loads

Evaluate failure probability, pf

. 6 .

N

Is pf acceptable ?

o Y

es

Report results

Fig 2. Schematic of the SRA methodology

Introduce further mitigating measures


3 rd International Pipeline Technology Conference, May 22-24, Brugge, Belgium

In the following sections each element of the SRA methodology is discussed with application to the justification of increasing the design factor in IGE/TD/1 from 0.72 to 0.8.


3 rd International Pipeline Technology Conference, May 22-24, Brugge, Belgium

3.2 Limit States The objective of the recommendations given in IGE/TD/1 is to ensure that pipelines are designed, constructed and operated to an acceptable level of safety. As such IGE/TD/1 provides recommendations to ensure that the likelihood of a loss of gas incident does not exceed an acceptable level. Ultimate limit states (ULSs) therefore require consideration in order to justify an increase in the maximum permissible design factor. 3.3 Failure Modes Although, with sufficient imagination, one could conceive of an 'endless' list of failure modes for a pipeline failure, the list of most likely or 'credible' failures is relatively short. Data from the European Gas Incident Data Group (EGIG) (2) indicates that the dominant failure modes for the 2x106 kilometre-years of EGIG operating experience on gas transmission pipelines are external interference, external corrosion, ground movement and fatigue crack growth of defects. These failure modes account for at least 65% of loss of gas incidents on the UK high-pressure gas transportation system. All credible failure modes should be addressed when applying SRA methods, however the Level 1 and 2 analyses have focused on pipelines where the only credible failure modes are external interference and external corrosion. In situations where this is not the case a Level 3 analysis will be required and the other failure modes will need to be considered. 3.4 Limit State Functions In order to quantify the effect of a change in design factor, the limit state function must be rearranged to include design factor as an explicit parameter. The limit state function for external corrosion is given below. For the sake of brevity, only the functional form of the limit state function for external interference is given. The full limit state function for external interference however is given in [3, 6, 7, 10] and the algebraic manipulation to formulate the function in terms of design factor explicitly is identical to that detailed for external corrosion. 3.4.1 External Corrosion Guidelines for predicting the failure pressure of part wall corrosion defects in pipelines were developed by the Linepipe Corrosion Group Sponsored Project [11] through a combination of analysis and full scale testing. However, the limit state function given in the guidelines may be conservatively represented by [12] 1− a = t*

P* D* * 2t *σ y

P* D* 1 − * * M −1 2t σ y

(1)

where the quantities, P*, D*, t* and σy* denote operating pressure, outer diameter, wall thickness and yield tensile strength respectively and the suffix '*' has been used to denote


3 rd International Pipeline Technology Conference, May 22-24, Brugge, Belgium

actual values. The depth of corrosion at failure is denoted by a and failure will occur when equation (1) is satisfied. The Folias factor, M, [13] is given by 1

  l M = 1 + 0.52 * *   Dt 

   

2

2   

(2)

where l is the axial length of the corrosion defect. If these actual values were known then the criterion given by (1) could be used to help ensure safe operation of the pipeline. However, in reality, the actual values of the quantities involved are not known due to statistical variation. The actual value of each parameter may however be related to relevant nominal parameters through the following definitions P * = Pop (1 + δ P )

(3)

*

D = Dnom (1 + δ D )

(4)

*

t = t min (1 + δ t + δ t )

(5)

*

σ y = SMYS (1 + δ σ + δ σ )

(6)

where Pop denotes the nominal operating pressure, Dnom denotes the nominal outer diameter, t min denotes the minimum wall thickness and SMYS denotes the specified minimum yield strength. The parameters δP, δD, δt and δσ are distributed dimensionless quantities with zero mean and δ w and δ σ are fixed positive dimensionless quantities. The determination of each of these parameters is discussed in [7]. The failure criterion given by (1) may therefore be replaced by

a crit = t min

 (1 + δ P )(1 + δ D ) 1+ δt + δt −η   1+ δσ + δσ 

(

   1−η   1+ δσ + δσ 

(

)

(1 + δ P )(1 + δ D )2

) (1 + δ ) (1 + δ 2

D

t

+ δt

2

)

    2    l + 0.52     Dnom t min  

(7)

where t is a dimensionless parameter known as the design factor given by Pop Dnom 2t min

= t SMYS

(8)


3 rd International Pipeline Technology Conference, May 22-24, Brugge, Belgium

Equation (7) defines the lower limit on corrosion depths that will lead to failure and has the following functional dependencies, a crit = Yl (t min , f , δ P , δ D , δ t , δ σ , Dnom , l )

(9)

and it is noted that safe operation can be achieved by controlling a, l, t min, Dnom f or any combination of these quantities. The time dependent and stochastic nature of corrosion defect depth can be described by a time dependent probability density function. However, one of the key features of this probability density function, which has a significant impact on the failure probability, is the upper bound value of defect depth. A consideration of this value is presented below. The upper bound value of corrosion defect depth is a time dependent quantity and depends on the corrosion growth rate, however a more direct control of this quantity is achieved through the defect repair criteria and the interval between inspections. Repair criteria generally stipulate the maximum depth of defects that can be present following an on-line inspection. The maximum depth, a0, present immediately after repair is usually expressed as a fraction of the minimum wall thickness and therefore must satisfy a 0 < ε t min

(10)

The value of ε may be dependent on both the defect length and the design factor but typically lies within the range 0.1 < ε < 0.5. The depth, a, to which this defect will grow before the next inspection at time τ2 is dependent on ε, tmin, corrosion defect depth growth rate, a'(τ) and on-line inspection interval, T I. If the previous on-line inspection was at time t 1, T I denotes the interval (τ1, τ2). Thus we can write τ2

a < ε t min + ∫ a ' (τ ) dτ

(11)

τ1

The right hand side of the above inequality denotes the deepest defect that can be present prior to the next inspection. The upper bound value of defect depth therefore has the following functional dependencies, a upper = Yu (t min , ε , TI )

(12)


3 rd International Pipeline Technology Conference, May 22-24, Brugge, Belgium

where aupper is the deepest defect that can be present at the end of the inspection interval. The values of ε, tmin and T I are nominal values and can be specified precisely. The growth rate is a stochastic parameter and strictly should be represented by a probability density function. However, an estimate may be made of the largest growth rate through assuming that no corrosion defects exist at the time of commissioning and that the growth rate of a given defect is constant. The largest possible defect immediately following the first inspection, a0, will therefore, from the above assumptions, be the fastest growing defect. The criteria given in Equation (11) may therefore be replaced by a < ε t min + a 'TI .

(13)

The above analysis has shown that although the probability of failure is dependent on f it is strongly dependent on t min and the maintenance and inspection parameters ε and T I. A relationship between the failure probability and these quantities is derived in Section 3.6.1 and evaluated and discussed in Section 4. 3.4.2 External Interference Although occurring infrequently due to the use of mitigating measures such as surveillance, external interference defects, in the form of dent/gouges, are randomly introduced into a pipeline during service. Failure occurs by an elastic-plastic fracture mechanism according to the R6 Rev. 2 failure assessment diagram [14]. The limit state function may be expressed in the following functional form F = F (f , δ P , δ D , δ t , δ σ , t min , a g , Lg , d , Dnom , K IC , SMYS )

(14)

where F is the impact force required to cause a dent of depth d, ag denotes gouge depth, Lg denotes gouge length and KIC is the material fracture toughness. Failure will occur when equation (14) is satisfied. An expression for failure probability in terms of f, d, tmin, SMYS and KIC is derived in Section 3.6.2 and evaluated and discussed in Sections 4 and 5. 3.5 Data The physical parameters identified in the above limit state functions are subject to natural variation and in principle should be treated as stochastic variables. However, in practice only the physical parameters that the limit state function is most sensitive to and are subject to significant variation need to be treated as stochastic variables, the remaining parameters may be represented by nominal or conservative deterministic values. Uncertainty in the four design parameters detailed in Section 3.4.1 is quantified through consideration of pipe mill data (diameter, wall thickness and yield strength) and operational restrictions and records (operating pressure). The actual value of each of these parameters is


3 rd International Pipeline Technology Conference, May 22-24, Brugge, Belgium

related to relevant nominal parameters through the definitions given in equations (3) to (6). The derivation of each of these distributions is given in [7]. Experience [3-8] has shown that the probability of failure is more sensitive to the distributions assumed for damage parameters than for the design parameters. Corrosion defect depth and length, gouge depth and impact force required to create a dent of given depth are largely system independent parameters and as such probability density functions have been constructed for these parameters from consideration of extensive data provided by Transco [38]. 3.6 Evaluation of Failure Probabilities It is shown in Section 3.4 that the design, maintenance and inspection parameters play a role in addition to the design factor in maintaining pipeline safety. In this section the failure probability is related to these parameters for each failure mode. 3.6.1 External Corrosion Noting the functional dependencies given by equations (9) and (12), the probability of failure in the time period TI between inspections τ1 and τ2, given that a corrosion defect exists, can thus be expressed as ∞

p f | defect =

Yu (.)

∫ p(δ ) ∫ p(δ ) ∫ p(δ ) ∫ p(δ )∫ p(l ) ∫ p(a) da dl dδ t

−∞

D

−∞

P

−∞

σ

−∞

0

σ

dδ P dδ D dδ t (15)

Yl (.)

From equations (9), (12) and (15) it is seen that for given pdfs, p f|defect depends on f, tmin, ε, TI, and Dnom. It is therefore possible to increase the design factor without increasing the probability of failure due to external corrosion defects by making appropriate adjustments to any of tmin, Dnom, ε or TI. The application of equation (15) is illustrated in Section 4. The probability of failure, per unit length, due to external corrosion is given by p f = (p f | defect )φ corr

(16)

where φcorr is the expected density of external corrosion defects per unit length. The defect density is dependent on factors that include the coating quality, effectiveness of cathodic protection and the soil properties. 3.6.2 External Interference Noting the functional form given in equation (14) and assuming KIC to be a known deterministic quantity the probability of failure given a defect exists can thus be expressed


3 rd International Pipeline Technology Conference, May 22-24, Brugge, Belgium

p f | defect =

t

∫ p(δ t ) ∫ p(δ D ) ∫ p(δ P ) ∫ p(δ σ )∫ p(a g )

−∞

−∞

−∞

−∞

0

∫ p( F ) dF da

g

dδ σ dδ P dδ D dδ t

(17)

Fcrit

From equations (14) and (17) it is seen that for given pdfs, pf|defect depends on f, t min, KIC, SMYS and Dnom. It is therefore possible to increase the design factor without any increase in failure probability due to external interference defects by making appropriate adjustments to any of t min, KIC, SMYS or Dnom. The application of Equation (17) is illustrated in Sections 4 and 5. The probability of failure, per unit length, due to external interference is given by p f = (p f | defect )φ ext int

(18)

where φext int is the expected frequency of occurrence of damage due to external interference per unit length. The frequency of damage is dependent on factors that include the depth of cover, impact protection and aerial surveillance frequency. 3.7 Assessment of Results For rural (Type R) pipelines IGE/TD/1 defines 8 diameter ranges for which have, in addition to the relationship between pressure and building proximity distance, a prescribed least nominal wall thickness. The analysis presented here retains these diameter ranges in order to preserve the basic structure of IGE/TD/1. Operation at f equal to or greater than 0.72 is possible for 7 of the 8 diameter ranges, these and the corresponding least nominal wall thicknesses are shown in Table 1. Table 1 IGE/TD/1 diameter classifications Outside diameter of pipe (mm) Diameter classification Exceeding Not Exceeding AA

1066.8

1219.2

IGE/TD/1 Least nominal wall thickness (mm) 12.70

A

914.4

1066.8

11.91

B

762.0

914.4

9.52

C

609.6

762.0

9.52

D

457.2

609.6

7.92

E

323.8

457.2

6.35

F

168.3

323.8

6.35


3 rd International Pipeline Technology Conference, May 22-24, Brugge, Belgium

The highest probability of failure implicitly acceptable in IGE/TD/1 for each failure mode, * p fi , indicates the level of safety implicitly acceptable in IGE/TD/1 and is given by *

*

p f i = ( p f | defect ) i φ i

(19)

The parameter φI, which is the expected incident frequency per unit length for randomly occurring modes and expected defect density per unit length for time dependent modes, is independent of pipeline diameter and as such does not require evaluation; therefore the highest * value of ( p f | defect ) i implicitly acceptable in IGE/TD/1, denoted by ( p f i | defect ) i , can thus be used as a measure of the limiting level of safety implicitly acceptable in the design code. From equations (15) and (17) it is evident that the failure probabilities due to a given external interference or external corrosion defect increase as the wall thickness decreases. Linepipe specifications state the allowable tolerance on wall thickness and as such specify a relationship between the minimum wall thickness, wmin, and the nominal wall thickness, t nom. The Transco technical specification LX1 [15] for SAW linepipe requires that t min is not less than 0.95 of tnom and this tolerance has been adopted for determining the Level 1 and Level 2 criteria. In order to determine the level of safety implicitly acceptable in IGE/TD/1 it is assumed that t min is equivalent to the least minimum wall thickness for each diameter range which corresponds to 0.95 of the least nominal wall thickness, as given in Table 1. In situations where specifications other than LX1 have been used the designer must ensure that the wall thickness tolerance is not significantly different from that given in LX1, else a Level 3 analysis is required. IGE/TD/1 considers commonly used API 5L strength grades up to and including X80. The analysis presented here considers commonly used grades in the range X42 to X80, inclusive. The recommendations given in IGE/TD/1 cover pipelines with an operating pressure not exceeding 100 bar and this criterion is invoked in the analysis. The level of safety implicitly acceptable in IGE/TD/1 is quantified in Sections 4 and 5 from a consideration of external corrosion and external interference. 4. LEVEL 1 APPROACH 4.1.1 External Corrosion From equation (15) it is seen that the probability of failure is dependent on ε for given values of f, tmin, Dnom and TI, and given distributions of l, δP, δD, δt and δσ. Commonly adopted repair criteria for corrosion defects are dependent on the design factor, f, and defect length, l. Defects satisfying the inequality l < 3tnom are classified as pitting corrosion defects, and defects satisfying l ≥ 3tnom are classified as general corrosion defects.


3 rd International Pipeline Technology Conference, May 22-24, Brugge, Belgium

The repair criteria adopted by Transco for pipelines operating at f = 0.72 are given in Table 2 and have been used in this analysis. Table 2 Repair criteria for corrosion defects at f = 0.72 Defect length, l Repair criterion, ε <3 tnom

0.5

≥ 3 tnom

0.2

The value of (pf|defect)* due to external corrosion for each diameter range has been evaluated using equation (15) with f = 0.72, TI equivalent to the IGE/TD/1 limit of 10 years, ε as defined in Table 2, Dnom equivalent to the lower bound value for each diameter range, as given in Table 1 and t min equivalent to 0.95tnom, where t nom is given in Table 1. The values of (pf|defect)* provide an indication of the limiting level of safety implicitly acceptable in IGE/TD/1 and as such are used as criterion values for determining the range of pipeline cases which are acceptable for operation at f = 0.8. The repair criteria given in Table 2 have been reviewed by BG Technology and Transco and the recommended criteria for pipelines operating in the range 0.72 < f ≤ 0.8 are given in Table 3. The values of (pf|defect) for operation at f = 0.8 were evaluated using the criteria given in Table 3 and found to be equivalent to or lower than the criterion values (pf|defect)*, thus indicating that operation at f = 0.8 may be justified using the Level 1 procedure if repair criteria equivalent to or more stringent than detailed in Table 3 are adopted. Table 3 Recommended Repair Criterion for Corrosion Defects at 0.72 < f ≤ 0.8 Defect length, l

Repair criterion, ε

<3 tnom

0.5

≥ 3 tnom

0.15

4.1.2 External Interference The value of (pf|defect)* due to external interference for each diameter band was evaluated using equation (17) with f = 0.72, Dnom equivalent to the lower bound value for each diameter range, as given in Table 1, tmin equivalent to 0.95tnom, where tnom is given in Table 1 and SMYS in the range X42 to X80, the highest grade evaluated however was restricted by the 100 bar pressure constraint for a given Dnom, t min and f. A deterministic value of fracture toughness, KIC, was assumed and was inferred from the specified minimum average value of Charpy toughness, Cv.


3 rd International Pipeline Technology Conference, May 22-24, Brugge, Belgium

The values of (pf|defect)* provide an indication of the level of safety implicitly acceptable in IGE/TD/1 and as such are used as criterion values for determining the range of pipeline cases which are acceptable for operation at f = 0.8. The range of pipeline cases that satisfy the (pf|defect)* criteria for operation at f = 0.8 have been evaluated. The value of t min, and thus t nom, required to satisfy the criteria has been evaluated for discrete values of SMYS in the range X42 to X80 inclusive. The least nominal wall thickness requirements were found to be largely independent of steel grade and thus a conservative grade independent value is adopted for each diameter classification and is presented in Table 4. It is noted that the least nominal wall thickness values presented in Table 4 satisfy the current IGE/TD/1 requirements given in Table 1. Table 4 therefore defines the wall thickness requirements to satisfy the Level 1 assessment procedure. Operation at Ρ = 0.8 may be justified using the Level 1 procedure if nominal wall thicknesses not less than those presented in Table 4 are adopted.


3 rd International Pipeline Technology Conference, May 22-24, Brugge, Belgium

Table 4 Level 1 requirements on least nominal wall thickness for operation at f = 0.8 Least nominal wall Diameter band thickness (mm) AA

14.1

A

13.6

B

10.4

C

10.4

D

8.7

E

7.5

F

7.5

4.2 Level 1 Criteria In addition to the general requirements of IGE/TD/1 the following criteria should be satisfied to justify operation in the range 0.72 < f ≤ 0.8 using the Level 1 assessment procedure:       

The nominal outer diameter is in IGE/TD/1 band AA to F inclusive. The steel strength grade must be in the range API 5L X42 to X80 inclusive. No credible modes of failure other than external interference and external corrosion must exist. The nominal wall thickness must not be less than the values given in Table 4. The wall thickness tolerance is not significantly different to that given in LX1 The pipeline must be suitable for condition monitoring using internal inspection devices Corrosion defect repair criteria equivalent to or more stringent than given in Table 3 must be adopted.

5. LEVEL 2 APPROACH The Level 2 approach to justifying operation at f = 0.8 extends the requirements of the Level 1 analysis. EGIG operational experience indicates that external interference is the dominant failure mode of onshore high-pressure gas transmission pipelines and any mitigating measures, additional to those required in the Level 1 analysis, to reduce the failure probability of these pipelines should therefore initially address this failure mode. The Level 2 approach considers pipelines for which the only credible failure modes are external interference and external corrosion and external interference is the dominant mode. If other failure modes exist or external interference is not predicted to be the dominant mode a Level 3 analysis will be required.


3 rd International Pipeline Technology Conference, May 22-24, Brugge, Belgium

The level of safety implicitly acceptable in IGE/TD/1 for each failure mode is given by equation (19). However, for external interference φext int is independent of pipeline diameter and the values of (pf|defect)* are used as criterion values to justify operation at f = 0.8. The introduction of mitigating measures additional to those required for the Level 1 criteria for protection against external interference has the effect of reducing φext int, thus implying that higher values of (pf|defect)* may be permitted if the criterion given by equation (19) is adopted. The reduction (DRFj >1) in φext int due to the introduction of mitigating measure j is given by DRF j =

φ ext int φ ext int j

(20)

where φext int j denotes the frequency of occurrence of external interference damage when mitigating measure j is introduced and DRFj is the damage reduction factor for measure j. The highest acceptable value of (pf|defect) when mitigating measure j is introduced, (pf|defect)^j is given by

(p

| defect )j = p f | defect * DRF j ^

f

(21)

It should be noted that (pf|defect)^ may exceed unity for high values of DRF and as such is not a true failure probability. 5.1 Mitigating Measures The effect of (i) increasing the depth of cover above the pipeline and (ii) introducing a reinforced concrete slab above the pipeline, on the frequency of occurrence of external interference damage is considered and the pipeline cases which satisfy the criterion given in (21) at f = 0.8 are defined below. 5.1.1 Increased Depth of Cover The depth of cover above the buried pipeline will have a significant effect on φext int as pipelines with a greater depth of cover will be less likely to be affected by external interference than shallow pipelines. A relationship between the depth of cover and the DRF has been developed by BG Technology though field trial studies. The minimum depth for pipelines designed and built according to IGE/TD/1 is 1.1 m and the DRF is conveniently defined as 1.0 at this depth. Cover depth is subject to natural variation and in principle should be treated as a stochastic variable. However, extensive data on Transco’s 18000 km of transmission pipeline system


3 rd International Pipeline Technology Conference, May 22-24, Brugge, Belgium

designed to IGE/TD/1, indicates that the average depth of cover is 1.3 m and therefore the system average depth of cover may be assumed to be (1.3/1.1) of the minimum depth of cover. The least nominal wall thickness requirements to justify operation in the range 0.72 < f â&#x2030;¤ 0.8 for minimum cover depths of 1.3 m and 1.5 m have been determined. The DRF is evaluated to be 1.30 and 1.85 for minimum cover depths of 1.3 m and 1.5 m respectively. The least nominal wall thickness values are subject to the current IGE/TD/1 requirements on wall thickness given in Table 1. The least nominal wall thickness values for minimum cover depths of 1.3 m and 1.5 m are presented in Table 5 and include the requirements given in Table 1. Table 5 therefore defines the wall thickness requirements to satisfy the Level 2 assessment procedure when an increased minimum depth of cover is adopted. 5.1.2 Reinforced Concrete Slab Field trial studies conducted by BG Technology have investigated the effect of introducing a reinforced concrete slab above the pipeline on the parameter Ď&#x2020;ext int and evaluated the DRF to be 5.3. The design of the slab will be detailed in the forthcoming Edition 4 of IGE/TD/1. The least nominal wall thickness requirements to justify operation in the range 0.72 < f â&#x2030;¤ 0.8 when an appropriate slab is placed above the pipeline have been determined. The least nominal wall thickness values are presented in Table 5 and include the requirements given in Table 1. Table 5 therefore defines the wall thickness requirements to satisfy the Level 2 assessment procedure when appropriately designed reinforced concrete slabs are introduced above the pipeline. Table 5 Level 2 requirements on least nominal wall thickness Least nominal wall thickness (mm) Diameter band

Minimum depth Minimum depth Minimum depth Reinforced of cover = 1.1 m of cover = 1.3 m of cover = 1.5 m concrete slab

AA

14.10

13.40

12.70

12.70

A

13.60

12.70

11.91

11.91

B

10.40

9.70

9.52

9.52

C

10.40

9.70

9.52

9.52

D

8.70

7.92

7.92

7.92

E

7.50

6.35

6.35

6.35


3 rd International Pipeline Technology Conference, May 22-24, Brugge, Belgium

F

7.50

6.35

6.35

6.35


3 rd International Pipeline Technology Conference, May 22-24, Brugge, Belgium

5.2 Level 2 Criteria In addition to the general requirements of IGE/TD/1 the following criteria should be satisfied to justify operation in the range 0.72 < f ≤ 0.8 using the Level 2 assessment procedure:         

The nominal outer diameter is in IGE/TD/1 band AA to F inclusive. The steel strength grade must be in the range API 5L X42 to X80 inclusive. External interference must be the dominant failure mode. No credible failure modes other than external interference and external corrosion must exist for the pipeline. The nominal wall thickness must not be less than the values given in Table 5 for the mitigation method used. The wall thickness tolerance is not significantly different to that given in LX1 The pipeline must be suitable for condition monitoring using internal inspection devices. Corrosion defect repair criteria equivalent to or more stringent than given in Table 3 must be adopted. If slabs are used the design must be in accordance with recommendations that will be given in the forthcoming Edition 4 of IGE/TD/1.

6. CONCLUSIONS AND RECOMMENDATIONS Structural reliability analysis (SRA) has been applied to identify the key parameters, in addition to the design factor, that govern the reliability of onshore high-pressure gas transmission pipelines. SRA has been used to quantify the limiting level of safety, in terms of these parameters, that is implicitly acceptable in the current edition of IGE/TD/1. A three level approach to the justification of safe operation at a design factor of 0.8 has been established based on this work. Level 1.

Scenarios have been identified for which various combinations of the key parameters, currently allowed by IGE/TD/1, together with a design factor, f, of 0.8, lead to safety levels which are as least as high as those associated with other allowable combinations of parameters at f = 0.72. It is recommended that a revision should be made to IGE/TD/1 to allow operation at f = 0.8 in these circumstances without need for any additional measures.

Level 2.

Scenarios, not covered by Level 1, have been identified for which operation at a design factor of 0.8 that is as safe as operation at a design factor, f, of 0.72 can be achieved through the introduction of various specified additional measures. It is recommended that the revision to IGE/TD/1 should allow operation at f = 0.8 in


3 rd International Pipeline Technology Conference, May 22-24, Brugge, Belgium

these circumstances when the appropriate specified additional measures are introduced. Level 3.

In situations where the combinations of parameters and additional measures are not covered by the revised recommendations covered by Levels 1 and 2 it is suggested that safe operation may be justified using a case specific structural reliability analysis. It is recommended that the revised edition of IGE/TD/1 should describe the basic requirements for this undertaking.

REFERENCES 1. Institution of Gas Engineers, ‘Steel Pipelines for High Pressure Gas Transmission’, IGE/TD/1 Edition 3, 1993. 2. European Gas Incident Data Group (EGIG), ‘3rd Report of the European Gas Incident Data Group’, Document number EGIG 98.R.0120, December 1998. 3. Francis, A., Espiner, R., Edwards, A., Cosham, A. & Lamb, M., ‘Uprating an In-Service Pipeline Using Reliability-based Limit State Methods’; 2nd International Conference on Risk Based and Limit State Operation of Pipelines, Aberdeen, 1997 4. Francis, A., Batte, A.D. & Haswell, J.V., ‘Probabilistic Analysis to Assess the Safety and Integrity of Uprated High Pressure Gas Transmission Pipelines’; IGE Annual Conference, Birmingham, 1997 5. Francis, A. & Senior, G., ‘The Applicability of a Reliability Based Methodology to the Uprating of High Pressure Pipelines’, IGE Midland Section meeting, Hinckley, March 1997 6. Francis, A., Espiner, R.J., Edwards, A.M. & Senior, G., ‘The Use of Reliability Based Limit State Methods in Uprating High Pressure Pipelines’; International Pipeline Conference, Calgary, 1998 7. Francis, A., Edwards, A.M. & Espiner, R.J., "Reliability Based Approach to the Operation of Gas Transmission Pipelines at Design Factors Greater Than 0.72’, 17th International Conference on Offshore Mechanics and Arctic Engineering, Lisbon, Portugal, July 1998 8. Senior, G., Francis, A. & Hopkins, P., ’Uprating the Design Pressure of In-service Pipelines Using Limit State Design and Quantitative Risk Analysis’, 2nd International Pipelines Conference, Istanbul, Turkey, December 1998 9. Lamb, M., Francis, A. & Hopkins, P., ‘How do you Assess the Results of a Limit State Based Pipeline Design’, 3rd International Conference on Risk Based & Limit State Design & Operation of Pipelines, Aberdeen, UK, October 1998 10. Francis, A., Edwards, A.M., Espiner, R.J., & Senior, G., ’Applying Structural Reliability Methods to Ageing Pipelines’, Paper C571/011/99, IMechE Conference on Ageing Pipelines, Newcastle, UK, October 1999. 11. Det Norske Veritas, ‘Recommended Practice RP-F101, Corroded Pipelines’, 1999. 12. ASME B31.G, ‘Manual for determining the remaining strength of corroded pipelines’, 1991. 13. Folias, E.S., ‘Fracture of Nuclear Reactor Tubes’, Paper C4/5, SmiRT III, London, 1975


3 rd International Pipeline Technology Conference, May 22-24, Brugge, Belgium

14. British Standards Institution, ‘Guidance on Methods for Assessing the Acceptability of Flaws in Fusion Welded Structures’; PD6493, 1991. 15. Transco, ‘Technical Specification for Submerged-arc Welded Pipe 400 mm to 1400 mm Inclusive Nominal Size for Operating Pressures Greater than 7 Bar’; LX1, 1993.


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