nace conference paper

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EVALUATION OF AVAILABLE CODES FOR CAPACITY ASSESSMENT OF CORRODED PIPELINES

Belachew C. T., Mokhtar C. Ismail, and Saravanan K. Universiti Teknologi PETRONAS, Mechanical Engineering Department

Bandar Sri Iskandar, 31750 Tronoh, Feb 2009

ABSTRACT

Evaluation of the capacity of corroded pipeline is an issue for several researchers and pipeline operators. Though there are various methods used for the assessment of remaining strength of corroded pipes, some of these methods are too much simplified and rely only upon the defect length and depth, ignoring the defect width and orientation. Moreover, most of these well known methods are limited to internal pressure and non interacting defects. In this paper evaluation of the most widely applicable corrosion assessment methods of ASME B31G, Modified B31G, RSTRENG, DNV RP-F-101 and PCORRC is conducted. As expected, the evaluation result shows that these methods are too much conservative. This means when pipeline operators use these codes for their fitness for service assessment; they are subjected to either unnecessary maintenance or premature replacement of pipelines. Therefore, further research towards the development of less conservative capacity assessment method based on burst test and nonlinear finite element method (FEM) is recommended.

Key Words: Corrosion Assessment, Capacity, FEM, Corroded Pipeline, Burst Pressure

1. INTRODUCTION

Metallic pipelines are widely used as the most efficient and safest way of oil and gas transportation. Nowadays, failures due to corrosion have been one of the greatest concerns in maintaining the pipelines integrity. Therefore, corrosion defects must be accurately evaluated to avoid economic loss and environmental damages. The determination of the corroded pipes load capacity is important topic for several researchers around the world. There are several empirical and semi-empirical methods available to determine the load capacity of corroded pipelines based on experimental tests. However, these methods are known to be conservative and limited since they are dependent on material properties, pipelines geometries and defect geometry. This fact implies any change in either of these properties will require the development of a large test set in order to update the empirical solutions. Therefore, the use of numerical simulation methods to obtain better results from any structure analysis, with lower cost is becoming popular.

The objective of this paper is to evaluate some of most widely applicable corrosion assessment methodologies against burst test result on machined defects. These corrosion assessment codes used to estimate the burst pressure of corroded pipeline. Even though, currently there are numerous

commercial and in-house codes, only five from the commercial codes (ASME B31G, Modified B31G, RSTRENG, DNV RP-F-101 and PCORRC) will be discussed in the preceding sections. All of these methods are primarily concerned with the longitudinal extent of the corroded area and internal pressure loading. Except the DNV-RP-F101, the other four are used for assessment of non-interacting defects.

2. CORROSION ASSESSMENT METHODS

Researchers are working towards developing more reliable and advanced corrosion assessment methods. Today, there are various methods used for the assessment of remaining strength of corroded pipes. Some of the methods are very simple and rely only upon the defect length and depth, while the others are much more complicated, based on finite element method (FEM) modeling. The most well known methods are limited to internal pressure and non interacting defects.

The basis for the well known ASME B31G was developed in the late 1960s and early 1970s in a project sponsored by AGA-NGI8, where a semi-empirical fracture mechanics formula for calculating the remaining strength of a metal loss defect was made [1]. The original formula was modified and became known as B31G, and there

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Nomenclature

cA Longitudinal cross sectional area StD Standard deviation

0cA Unflawed area in the longitudinal plane t Wall thickness of the pipe

pcA Projected area in the longitudinal plane T Temperature de-rating factor D Nominal diameter

d Fractile value for the corrosion depth d Maximum depth of defect

u Ultimate strength (UTS ) F Design factor; ASME: B31.4, B31.8 or B31.11 SMTS Specified minimum yield strength L Axial extent of the defect

yield Specified minimum yield stress ( SMYS ) QM , Folias factor

m Partial safety factor for model prediction

bp , fp Burst (failure) pressure of corroded pipe

d Partial safety factor for corrosion depth

actbp int, Burst pressure of intact pipe

have been several minor modifications to the criterion and other methods as the Shell criterion, RSTRENG, etc are available. In the recent years new methods have been developed based on extensive use of finite element analyses and full scale testing, as for instance the PCORRC and the BG/DNV (BS 7910) methods.

Different levels of defect assessment, ranging from simple screening methods to very sophisticated three-dimensional elastic-plastic finite element stress analyses, are under studies. The method used depends upon the type of defect detected, the loading conditions, the objective of the assessment, and the type and quality of data that is available. The pipelines defect assessment manual (PDAM) suggested five stages of defect assessment [2, 3]. The different levels and the required data are shown in Figure 1.

2.1 Intact Pipeline Under Internal Pressure

The simplest and, in general, the most conservative formula to calculate the capacity of pressurized intact pipeline can be calculated by Barlow equation. The assumption is based on the

allowable maximum hoop stress and more conservative for thicker walled pipelines.

uactb tDtp

=2

int, (1)

Figure 1 The Five Stages of PDAM [4]

2.2 ASME B31G Criterion The ASME B31G criterion [1] is developed

based on full scale tests of pressured to failure corroded pipes. It allows determination of the remaining strength of the corroded pipes and estimating of the maximum allowable operating pressure (MAOP). However, the B31G criterion contains some simplifications. Another shortage, is the possibility of only proving the pipe integrity under internal pressure, other stresses are not taken into account. There is also restriction in assessable defects, namely the corroded area depth can not be greater than 80% of the wall thickness and not less than 10%.

This method is based on the measurement of the longitudinal extent of the corroded area as shown in Figure 2. It considers the depth and longitudinal extent of corrosion, but ignores its circumferential extent.

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Figure 2 Longitudinal extent of the corrosion area [1]

The corroded area is approximated depending on the defect length as parabolic or rectangular shape. Short longitudinal extent of corrosion areas are approximated by the parabolic shape and long longitudinal extent of corrosion areas are approximated by the rectangular shape, as shown in Figure 3 and Figure 4, respectively.

=>

=

dLADt

dLADtL

c

c

203220 (2)

Figure 3 Assumed parabolic corroded area for relatively

short corrosion defect

The predicted failure pressure can be estimated by Equation (3) and Equation (4) for short and long defect, respectively. However, the maximum allowable operating pressure (MAOP) can be limited to a multiple of the estimated failure pressure by the design factor, F.

=

td

M

td

DtSMYSp f

3211

3212 (3)

=td

DtSMYSp f 1

2 (4)

DtLM

2

8.01 += (5)

Figure 4 Assumed rectangular corroded area for longer

corrosion defect

2.3 Modified B31G Criterion (0.85dL Area Method)

The B31G method was found to be too conservative and has been modified, the new method is called Modified B31G or 0.85-area Method [5]. One of the most significant changes to the original B31G method is the defect geometry approximation. Corrosion area is defined by 0.85dL as illustrated in Figure 5.

Figure 5 Assumed dLAc 85.0= method for corrosion defect

This method removes some conservation by changing the flow stress limit to

)10(69 ksiMPaSMYS + . This is very close to the conventional fracture mechanism definition of the flow stress: the average of the yield and ultimate strength. This modification results in the change of the failure equation, which is also dependent on the limit on defect length. The equation to calculate the failure pressure is modified as follows.

( )

+=

td

M

td

DtMPaSMYSp f 185.01

85.0121.69

(6)

For DtL 50 , the Folias factor is given by:

222

003375.06257.01

+=

DtL

DtLM (7)

But if DtL 50>

DtLM

2

032.03.3 += (8)

2.4 RSTRENG Criterion (Effective Area Method)

RSTRENG (Remaining Strength of Corroded Pipe) is a modified B31G based on real shape of corrosion defects. The basic difference between the Modified B31G and RSTRENG is the geometry description [5, 6]. The modified B31G method can

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be taken as a simple calculation with an approximate geometric shape, while RSTRENG takes into account the actual profile of the defect. Therefore more measurements have to be done to determine the bottom profile as shown in Figure 6.

Figure 6 Actual corrosion areas calculation method

Such area assessment results in obtaining better failure pressure prediction, which is given by the following formula:

( )

+=

0

0

11

121.69

c

pc

c

pc

f

AA

M

AA

DtMPaSMYSp (9)

Where the Folias factor M is equal to the factor used in modified B31G (Equation 7 or Equation 8).

2.5 DNV RP-F-101 Criterion

The DNV guidelines are still under development, but the DNV RP-F101 issued in 2004 is treated hear [7]. It provides guidance on single and interacting defects under pressure only and combined loading. The RP-F101 provides two methods of analysis: a partial safety factor method and an allowable stress design method. The allowable corroded pipe pressure of a single metal loss defect subjected to internal pressure loading is given by the following acceptance equation.

= *

*

11

12

td

Q

td

tDtSMTSp

d

d

mf

(10)

Where the relative corrosion depth and the factor Q are given as:

+

=

tdStD

td

td

dmean

(11)

2

31.01

+=

DtLQ (12)

In the allowable stress design approach, the failure pressure of the pipe is calculated and

multiplied by safety factors. These factors may be based on design factor and can consider uncertainties such as presented above. The uncertainties caused by the presence of a corrosion defect, can be described by the additional 0.9 factor. This is a commonly used approach because of its simplicity.

=

td

Q

td

tDtSMTSFp f 11

129.0 (13)

2.6 PCORRC Criterion

Battelle [8] has selected to use an exponential function for the capacity equation labeled PCORRC, defined as:

( )

=

dtD

LC

ub etd

DtP 2112 (14)

On comparison with experimental test result, estimation of PCORRC equation proved to be conservative and the closest when using 95% of UTS of tensile test, Testu , as u . The C value varies from 0.142 to 0.224 with the change of pit depth. However for conservative prediction of damaged pipe, we can choose maximum value of 0.224 as curve fit constant and the above equation is rewritten as follows.

( )

=

dtD

L

Testub etd

DtP 2

224.0

, 11295.0 (15)

3. ILLUSTRATIVE EXAMPLE

The above mentioned corrosion assessment methodologies are evaluated based on a pipeline with known corrosion defects and mechanical properties. The API 5L X65 grade carbon steel pipeline used for demonstration has diameter of 762 mm and the wall thickness is 17.5 mm. Single defects with rectangular cross section and uniform depth, as dimensions shown in Table 1 were considered for comparison of the methods. First the methods were compared against burst test result database. Finally, they were used in calculating the failure pressure by varying the defect depth and the defect length.

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Table 1 Simple rectangular defect and experimental burst pressure [9]

Defect No. L (mm)

d/t (%)

Burst Pressure (MPa)

1 200 25 24.1 2 200 50 21.8 3 200 75 17.2 4 100 50 24.3 5 300 50 19.8 6 200 50 23.4 7 200 50 22.6

4. RESULT AND DISCUSSION

The comparison of predicted burst pressure by the selected assessment codes against the burst test result is shown in Table 2 and Figure 7. The result confirmed that these methods are much conservative. The maximum deviation was observed for ASME B31G codes, which is as high as 30%. Even though the DNV and PCORRC codes are known for relatively less conservativeness, deviated up to 20% were observed. The effects of defect depth and defect length on failure pressure prediction were also investigated. Figure 8-11 shows the predicted failure pressure with respect to the corrosion depth. It was found that the pressure capacity of the pipeline is decreasing with the increase of the defect length. For example for a single defect of 60% defect depth and longitudinal extent of 450 mm the failure strength is reduced up to 55% for PCORRC. However further increase in defect length do not affect the failure pressure any more. Similarly through Figure 11-15 the predicted failure pressure with respect to the corrosion length is shown. The predicted failure pressure is reduced significantly with the increase of defect depth. It is noted that the ASME B31G codes are relatively more conservative for smaller defect depths.

Table 2 Comparison of burst test with predicted results

Cas

es

L (m

m)

d/t (

%)

Failure Pressure (MPa)

Bur

st T

est

Predicted Failure Pressure

B31

G

M B

31 G

RST

REN

G

DN

V

PCO

RR

C

1 200 25 24.1 14.9 23.2 22.7 16.9 23.4 2 200 50 21.8 13.2 19.8 18.3 14.4 19.3 3 200 75 17.2 11.2 15.1 11.7 10.1 13.3 4 100 50 24.3 14.7 22.8 21.9 16.8 22.2 5 300 50 19.8 12.5 18.2 16.5 12.9 17.3 6 200 50 23.4 13.2 19.8 18.3 14.4 19.3 7 200 50 22.6 13.2 19.8 18.3 14.4 19.3

Comparison of Corrosion Assessment Methodologies

0.55

0.60

0.65

0.70

0.75

0.80

0.85

0.90

0.95

1.00

0 1 2 3 4 5 6 7 8

Defect Number

Pred

icte

d Fa

ilure

Pre

ssur

e

B31 G ModifiedB31 G

RSTRENG DNV PCORRC

Figure 7 Comparison of corrosion assessment methods

against the burst test

Predicted Failure Pressure, d = 0.2t

0.60

0.65

0.70

0.75

0.80

0.85

0.90

0.95

1.00

0 1 2 3 4

Defect Length,

Failu

re P

ress

ure,

B31GM B31GDNVPCOORC

Figure 8 Predicted failure pressure with 20% defect depth


0.50

0.55

0.60

0.65

0.70

0.75

0.80

0.85

0.90

0.95

0 1 2 3 4

Defect Length,

Failu

re P

ress

ure,

B31GM B31GDNVPCOORC


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0.40

0.50

0.60

0.70

0.80

0.90

1.00

0 1 2 3 4

Defect Length,

Failu

re P

ress

ure,

B31GM B31GDNVPCOORC



0.20

0.30

0.40

0.50

0.60

0.70

0.80

0.90

1.00

0 1 2 3 4

Defect Length,

Failu

re P

ress

ure,

B31GM B31GDNVPCOORC


Predicted Failure Pressure,

0.50

0.55

0.60

0.65

0.70

0.75

0.80

0.85

0.90

0.15 0.25 0.35 0.45 0.55 0.65 0.75 0.85

Defect Depth,

Failu

re P

ress

ure,

B31GM B31GDNVPCOORC

Figure 12 Predicted failure pressure for DtL =


0.30

0.40

0.50

0.60

0.70

0.80

0.90

0.15 0.25 0.35 0.45 0.55 0.65 0.75 0.85

Defect Depth,

Failu

re P

ress

ure,

B31GM B31GDNVPCOORC

Figure 13 Predicted failure pressure for DtL 2=


0.25

0.35

0.45

0.55

0.65

0.75

0.85

0.15 0.25 0.35 0.45 0.55 0.65 0.75 0.85

Defect Depth,

Failu

re P

ress

ure,

B31GM B31GDNVPCOORC



0.20

0.30

0.40

0.50

0.60

0.70

0.80

0.15 0.25 0.35 0.45 0.55 0.65 0.75 0.85

Defect Depth,

Failu

re P

ress

ure,

B31GM B31GDNVPCOORC


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5. CONCLUSION

It is concluded that the currently in use corrosion assessment methods are conservative. When pipeline operators use these codes for their fitness for service analysis, they are probably subjected either to unnecessary maintenance or to premature replacement of pipelines. Therefore, the development of less conservative corrosion assessment method based on burst test and intensive non linear finite element simulation is recommended for future work.

ACKNOWLEDGMENTS

The authors are thankful to Universiti Teknologi PETRONAS for providing facilities for the research. Deepest gratitude to PETRONAS Carigali Sdn Bhd, for providing after service pipelines and promised to sponsor further experimental and analytical studies in pipelines with real corrosion.

REFERENCE [1] Manual for determining the remaining strength of corroded pipelines. A supplement to ANSI/ASME B31 code for pressure piping. ASME B31G 1991; 1991.

[2] Bjornoy OH, Marley MJ. Assessment of Corroded Pipelines: Past, Present and Future. Proceedings of the eleventh (2001) International offshore

and polar engineeering conference, Stavanger, Norway: 2001. The International Society of offshore and polar engineering; 2001. p. 93-101.

[3] Cosham A. The Assessment of Corrosion in Pipelines-Guidance in the Pipeline. Pipeline Pigging and Integrity Management Conference. Amsterdam, the Netherlands; 2004.

[4] Cosham A, Hopkins P, Macdonald KA. Best practice for the assessment of defects in pipelines - Corrosion. engineering failure analysis 2007;14(7):1245-65.

[5] Szary T. The Finite Element Method Analysis for Assessing the Remaining Strength of Corroded Oil Field Casing and Tubing. Mechanical Engineering. Freiberg, Germany; 2006.

[6] Kiefner. KAPA 2006. Kiefner and Associates, Inc.; 2006.

[7] Recommended practice DNV-RP-F101. Corroded pipelines. DET NORSKE VERITAS; 2004.

[8] Cosham A, Hopkins P. An Overview of the Pipeline Defect Assessment Manual (PDAM). 4th International Pipeline Technology Conference. Ostende, Belgium; 2004.

[9] Choi JB, Goo BK, Kim JC, Kim YJ, Kim WS. Development of limit load solutions for corroded gas pipelines. internationa journal of pressure vessels and piping 2003;80:121-8.

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