Tài liệu PIPELINE PIGGING TECHNOLOGY- P12 pdf

CALCULATING THE FAILURE PRESSURE OFCORROSION IN PIPELINES Structural defects which exceed code tolerances can be assessed using fitness-for-purpose methods.. The ANSI/ASME B31 Code [5] f

Fig.9 Metal-loss readings along a channel.

metal loss readings (see Fig.7) can be identified These spools can then be

closely scrutinised during a second run, and the reported corrosion can also

be assessed using the methods detailed later

Repeat inspections

Following a repeat inspection, inspection data will be available for the

entire pipeline (e.g Fig.3(b)) and individual spools, Fig.8; the most

severely-corroding spools can be determined using the type of procedure used in Fig.8

Care should be taken in assessing the metal-loss readings from spools; this is

because corrosion can be preferential, so that corrosion rates determined

from mean metal-loss readings around the circumference of the pipe (Fig.3(b))

and along the axis of the pipe (Fig.9) can be misleading Similarly, when

determining corrosion rates at specific areas of corrosion (i.e pits), care

should be taken in allowing for general wall thickness corrosion as well as pit

corrosion, Fig 10

Fig 10 Pit model and the effect of corrosion.

CALCULATING THE FAILURE PRESSURE OF

CORROSION IN PIPELINES

Structural defects which exceed code tolerances can be assessed using

fitness-for-purpose methods These methods are well-documented[10], and

have been used extensively in pipeline welding codes[ll] The ANSI/ASME

B31 Code [5] for pressure piping contains a supplement[12] which allows

pipeline corrosion to be assessed using fitness-for-purpose methods These

methods are considered acceptable and applicable to pipeline defects

The failure stress of corrosion in a pipeline can be calculated from [1-3]:

Of = 1.15 SMYS (1 - X) {1 - X (M'1) }•' (1)

and

M = 1 + {0.4 (2c/(Rt)V4)2 p (2)where X = d/t or A/Ao

of = hoop stress at failure

R = pipe radius

A = 2c x t2c = defect length

t = wall thickness

Ao = defect aread° = defect depthSMYS = specified minimum yield strengthThis criterion is nearly 20 years old, but a recent review[13] of failure

criteria for defects in pressurized cylinders concluded it was the most

accurate Various Folios factors, M, are used in the literature but they are all

very similar, with Eqn(2) the most conservative [13]

The accuracy of this criterion can be evaluated by comparing predicted

failure pressures with actual failure pressures of full-scale tests on corroded

pipe [2,14] The predicted failure pressures are dependent on the use of:

(i) either maximum defect depth (d) or actual defect area (A); and

(ii) actual yield stress (CT) or SMYS in the failure criterion

The most accurate predictions are obtained using defect area and actual

yield stress [3] The most inaccurate (and most conservative) predictions are

obtained using SMYS and maximum defect depth Using the data in Refs 2 and

14, it is possible to calculate safety factors that, when applied to Eqn(l), will

give safe (95% confidence level*) predictions Ref.3 suggests that a safety

factor of 0.97 should be applied to Eqn(l) and recommends the use of SMYS

and maximum defect depth

SAFETY FACTORS ON FAILURE PRESSURES

The end product of a fitness-for-purpose calculation is a failure pressure for

a defect Factors should then be applied to the failure pressure to

accommo-date uncertainties in the fitness-for-purpose analysis and also in the operation

of the pipeline (e.g surges) A safety-factor philosophy directly related to

code requirements can be proposed[3] Summarizing:

maximum operating pressure, Po = SM x SF x Pf (3)

where Pf = predicted failure pressure of corrosion (Eqn(l));

SM = safety margin related to pipeline codes; and

SF = safety factor to accommodate errors in failure criteria

A value of SF = 0.97 is recommended to give a 95% confidence level on

failure predictions

SM is obtained by considering the design and hydrotest pressures specified

in pipeline codes Most codes, e.g IP6[15], have a maximum design pressure

of 72% SMYS and a hydrotest pressure in excess of 90% SMYS If we assume

that a defect-free pipeline will fail when the hoop stress reaches flow stress

C 1.15 x SMYS)[2], we obtain the following safety margins (Fig 11):

hydrotest** safety margin = 0.72/0.90 = 0.8

defect-free pipeline safety margin = 0.72/1.15 = 0.63

Thus a new IP6 pipeline will have a safety margin between 0.8 (guaranteed

by the hydrotest) and 0.63 This latter defect-free safety margin is optimistic

because an operational pipeline, with its fittings, bends, etc., cannot be

expected to withstand a stress of 115% SMYS

* The use of a 95% confidence level (mean minus 2 standard deviations) in failure calculations bos

been accepted as good practice for many years, with its adoption in BSI PD6493[10], the major defect

assessment code The design curve (in effect the 'fracture' curve) in BSIPD6493 is a 95% lower confidence

level on a large full-scale test data base.

** Care should be taken in calculating these margins, as hydrotest and operating stress levels can be

based on minimum or nominal wall thickness.

Fig 11 Safety margins in IP6[15] pipeline code.

An intermediate safety margin of 0.72 is obtained by using the SMYS:

'SMYS' safety margin = 0.72/1.00 = 0.72

This safety margin is arbitrary and cannot be related to the IP6 code, but

it is directly related to a pipeline property, SMYS, and is the margin resulting

from a hydrotest to 100% SMYS level Therefore, three overall safety factors

(SM x SF) in Eqn(3) can be proposed:

(IP6)'Hydrotest' =0.8x0.97 =0.78 4(a)

'SMYS' =0.72x0.97 =0.70 4(b)

'Defect Free' =0.63x0.97 =0.61 4(c)

These safety factors are then applied to Eqns(l) and (2) to obtain a safe

operating pressure; Fig 12 presents Eqns(l) and (2) graphically The above

safety factors relate to the assessment methods and relevant codes; they do

not take into account detection limits, tolerances, etc

Fig.l2(a) (top) Failure of pipe-wall defects in pressurized

linepipe[l,2].

Flg.l2(b) (bottom) Failure of infinitely-long defects in pressurized

linepipe.

A METHODOLOGY

The above sections can be combined to develop a methodology for

assessing the significance of corrosion in pipelines The methodology can be

divided into three parts:

1 processing corrosion data;

2 modelling corrosion;

3 deriving acceptable defect curves with safety factors

Processing corrosion data

Figs 3-10 give methods of obtaining corrosion rates and highlighting

suspect spools from on-line inspection data

For a single on-line inspection, a 'weak link' approach is recommended

This means determining the most severe defect in a pipeline and the

significance of this defect governs the pipeline integrity In practice, a

number of defects, of different sizes and shapes, will be reported that are

above agreed defect reporting levels As the failure stress of corrosion is

related to both corrosion length and depth, it is necessary to determine the

significance of all these defects (e.g Fig.4)

Repeat inspections may allow an estimate of corrosion rate; Figs 3-6 give

methods of determining this rate

Modelling corrosion

A high-resolution magnetic-based on-line inspection can give a reliable

estimate of corrosion size For a single inspection, the maximum size of the

corrosion should be used in setting defect acceptance levels; this means that

all defects are conservatively modelled as 'flat-bottomed' (see Eqns(l) and

(2)) Additionally, it may be necessary to take account of inspection tool sizing

tolerances in the depth and length inputs into Eqns(l) and (2)

For repeat inspections, it maybe necessary to model the corrosion rate as

well as the defect size A variety of models are possible; Fig 13 gives three

examples of modelling corrosion and corrosion rate In practice, it may be

necessary to evaluate all such models and take lower bound values Modelling

of pitting corrosion and rates is given in Fig.10

Fig 13 Modelling of pipe-body corrosion.

Fig.l4(a) (top) Failure pressure of corrosion defect with time.

Fig.l4(b) (bottom) Operating pressures and inspection

requirements in corroding pipelines.

Fig 15 Defect assessment methodology.

Deriving acceptable defect curves

The equations necessary for deriving acceptable corrosion defect curves

are given above (or the acceptance levels in the ANSI/ASME Code[12] can be

adopted) The selection of safety factors for use in Eqn(l) will be the

responsibility of the pipeline operator, but the hydrotest safety factor has the

advantage of being directly related to code and pre-service requirements In

some codes (particularly for oil pipelines) the hydrotest level is relatively low

(e.g IP6[12]), and it may be better to use a higher hydrotest level in deriving

a safety margin, e.g 100% SMYS as used in the ANSI/ASME B31A Code [5], [ 12],

to ensure a reasonable safety factor

Deriving repeat inspection intervals

The acceptable defect curves can be used during repeat inspections

These can be combined with corrosion rate data to predict increases in

corrosion depth with time, Fig I4(a) The curves, with safety factors included,

can also be used to both predict when any downrating of operating pressure

is needed or when it would be necessary to re-inspect the line to avoid

downrating, Fig.l4(b)

CONCLUDING REMARKS

A defect assessment methodology for corroded pipelines, based on the

above sections, can be proposed Fig 15 summarizes the methodology, and it

is recommended that this type of methodology is applied to future

assess-ments of corroded pipelines It can be applied to pipelines containing limited

corrosion or extensive corrosion However, there are some limitations, and

these are listed in Ref.3 For example, the interaction of neighbouring

corrosion pits is not well understood However, the methodology will be

applicable to most corrosion types, despite these limitations

It should be emphasized that a defect assessment is only as good as the

defect inspection report If the report is inaccurate, the defect assessment will

be inaccurate Therefore, a reliable, accurate inspection tool is required if the

above methodology is to be applied These tools can be expensive, but they

allow defect assessments which avoid expensive repairs to the pipeline

The author would like to thank British Gas pic for permission to publish

this paper, and all his colleagues at the Engineering Research Station and the

On-line Inspection Centre who have contributed to the paper

REFERENCES

1 J.F.Keifner etal., 1973 Failure stress levels of flaws in pressurized cylinders.

ASTM STP 536, pp 461-481

2 R.W.E.Shannon, 1974 The failure behaviour of line pipe defects JntJPress

Vess and Piping, 2, pp 243-255.

3 P.Hopkins, 1990 Interpretation of metal loss as repair or replacement

during pipeline refurbishment Proc European Pipeline Rehabilitation

Seminar, London, May, Paper 8

4 Anon., 1983 Procedures for inspection and repair of damaged steel

pipelines designed to operate at pressures-above 7 bar BGC/PS/P11, Dec

5 Anon., 1979 Liquid petroleum transportation piping system ANSI/ASME B

31.4, Chapter VII, pp 52-59

6 R.Gribben, 1989 New rules to improve safety of oil and gas pipelines The

Daily Telegraph, UK, 20 June.

7 J.Keen, 1990 Corrosion forces repairs to oil pipelines US Today, 5

February

8 BJ.Parry and D.G.Jones, 1988 On-line inspection - state of the art and

reasons why Gas Transportation Symposium, January, Haugesund,

Nor-way

9 R.W.E.Shannon, 1985 On-line inspection of offshore pipelines Middle East

Oil Technical Conference, SPE 1985, Bahrain, March, Paper SPE 13684

10 Anon., 1980 Guidance on some methods for the derivation of acceptance

levels for defects in fusion welded joints BSIPD 6493

11 R.I.Coote etal, 1988 Alternative girth weld acceptance standards in the

Canadian gas pipeline code 3rd Int Conf on Welding and Performance of

Pipelines The Welding Institute, London, November, Paper 21

12 Anon., 1984 Manual for determining the remaining strength of corroded

pipelines ANSI/ASME B.31 G-1984, ASME

13 A.G.Miller, 1988 Review of limit loads of structures containing defects Int

J of Pressure Vess and Piping, 32, Nos.1-4, p!95.

14 J.F.Kiefner, 1971 Investigation of the behaviour of corroded linepipe.

Phases I-IH, Battelle Report 216, Sept 1970 to July 1971

15 Anon., 1982 Pipeline safety code Part 6 (IP6) of Institute of Petroleum's

Model Code of Practice in the Petroleum Industry, 4th edn.

BI-DIRECnONAL ULTRASONIC PIGGING: OPERATIONAL EXPERIENCE

HAVING SUCCESSFULLY inspected a 48-in 11-km offshore pipeline using

a bi-directionally-travelling ultrasonic inspection pig, NKK has proven its

technological ability to provide valid data for efficient, cost-saving

mainte-nance

INTRODUCTION

The natural environment will be severely affected in the event of a leak

from an offshore crude-oil loading pipeline To prevent such leakage due to

corrosion, an inspection of the development of pipeline corrosion by means

of an inspection pig is effective Most offshore loading pipelines are installed

between the shore with storage tanks, and the PLEM (pipeline-end manifold)

on the sea bottom, permitting connection to a tanker via a flexible rubber

hose At present, however, difficulties are always encountered in carrying out

the inspection of offshore pipelines by means of an inspection pig, because

the structure of the offshore crude-oil loading line is not suited for installing

a launcher or a receiver

NKK has developed an inspection pig that makes it possible to inspect the

state of corrosion of a pipeline by travelling bi-directionally in the line

provided there is a sufficiently-large area at the shore end of the line to install

a launcher/receiver

This paper outlines how the inspection of the inside of an offshore pipeline

was conducted by a bi-directional ultrasonic inspection pig currently in use

in Japan

Fig.2 Diagram of the bi-directional ultrasonic pig.

Fig.l Offshore pipeline overview.

PIPELINE, PIG AND OTHER DETAILS

A 48-in diameter crude-oil loading offshore pipeline with an approximate

length of 11km was required to be inspected (see Fig.l)

Pipeline details

Nominal diameters: 42-48in

Fluids: crude oil, product oil, seawater, fresh water

Fluid pressure: 10 kg/cm2 and less

Fluid temperature: normal temperature

Bend radius of pipe: 1.5 times pipe diameter

Specification of inspection pig

Type: ultrasonic

Measuring method: inspection of inside wall and outside surface

for corrosionTotal number of sensors: 240

Travelling method: bi-directional

Weight: 1,800kg

Overall length: 2.125m

Data analysis system

Inspection data from the designated areas can be regenerated by an on-site

data-analysis system The data regenerated is output to a monitor display in the

form of a picture image as if seen from inside the pipeline Following analysis

on the monitor display, data for the whole line is transferred to an engineering

work station at the NKK Engineering Centre, where a complete and detailed

analysis is conducted, using reporting formats such as tabulating corrosion,

and providing a planar view (plane pattern), a longitudinal cross-section, a

circumferential cross-section, a contour map, and a colour planar view Fig.3

shows the data-analysis system

Reporting formats

With an internal, natural corrosion sample patched on the NKK test loop,

the detection capability of the bi-directional ultrasonic inspection pig has