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23rd World GAS Conference, Amsterdam 2006

C.P. data, CIPS & DCVG techniques: another way to p redict Corrosion on Gas Pipeline.

A.Taberkokt

ALGERIA

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ABSTRACT

One of the most important care of gas operators is how to prevent the presence of corrosion points on their metallic gas pipelines, and therefore repair them before they reach a critical threshold that could lead to an incident.

This prevention can be assured by inspecting the pipe wall thickness with an intelligent pig tool.

Indeed the evolution of the technology, allows the development of high resolution tools which locate corrosion points ( if they exist ) and restore them in three axial axis dimensions. The gas operators can then identify the critical corrosion points and undertake the appropriate actions to ensure a safe operation of its gas pipeline.

Solely, this alternative of inspection, is on one hand costly and on another hand, depends on

the technical characteristics of the pipe (diameter, thickness, bends.....), without taking into account the time parameter from the call of tender to the data acquisition. In addition to that, the gas operator has to prepare the required conditions before and during the pipe inspection (gas equipments to be replaced, relive of ballast industrial customers in certain cases due to technical reasons, repeating the inspection if some troubles appear in the acquisition data recorder ...).

Therefore, the gas operators can undertake another alternative which consists of using

electrical field survey methods: ON/OFF CIPS combined with DCVG measures over the buried gas pipeline. For which, he has to add historical data of cathodic protection parameters, such as soil resistivities, potential surveys, Off rectifiers time and any other parameters which favor the instability of the steel pipe wall thickness. The analysis of the obtained results leads in preventing the existence of the corrosion points. This alternative is undertaken whatever the gas pipeline characteristics are.

The present work shows us an experience done on a part of section of the gas pipeline ∅ 20’’

diameter and 77 Km length gas pipeline (from Relizane town to Sig ) using the two techniques : Inspection by intelligent pig tool and electrical field survey methods.

We focus our interest over the first ( 10 ) ten kilometers, cause it’s first the section in which

our previous study showed us to be the most probable affected part of the gas pipeline, and second because it’s the section which supports the high pressure levels (existence of the compressor station ).

The results of the both techniques were given; time and costs were evaluated showing the

positive and negative sides of the two alternatives. Finally conclusion and recommendations were done for gas operators, who are interested to inspire with this experiment.

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TABLE OF CONTENTS

1. Abstract

2. Introduction

3. Technical characteristics of the gas pipeline

4. Corrosion prediction using CP data and electrical fields surveys.

5. Inspection of the gas pipeline by intelligent tool.

6. Analysis and comparison of the MFL tool and On line surveys results

7. Conclusion.

8. References

9. Annexes

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1. INTRODUCTION

On 1977 the Algerian Gas & Electricity company SONELGAZ inherited the ∅ 20’’ Relizane – Maghnia high pressure gas pipeline, called ‘’∅ 20’’ Ouest’’. This pipe made off three sections coated with bitumen product, was strategic for the north west of Algeria, since it permitted the supply of natural gas to the towns situated in the neighboring of gas pipeline.

Unfortunately, our company received the gas pipeline in very bad conditions, which required a rehabilitation programs just after putting gas into the pipeline.

From these years a particular care was and is still given to the ‘’∅ 20’’ Ouest ‘’, by establishing special programs such as inspections by intelligent pig and rehabilitation, to satisfy the required rules of supplying natural gas in a safety condition.

From 1979 to 1995 our company has done:

- The change of 30 % of the total gas pipelines length, - Reparation of all the severe corrosion points, - Reparation of thousands defects coating.

On 1996, because of the possibility to feed a new customers, a ‘’power plant’’ situated at 70 Km far

the end of the network ( after the extension of the pipeline ) , we prepared a rehabilitation study which undertook actions to short , medium and long term.

Among these actions, we proposed to change the first 44 Km of the Relizane - Sig section, basing on cathodic protection parameters history, coating condition …. In addition, it’s the part of the gas pipeline which will support the highest pressures level.

The technical committee of our company didn’t accepted the proposal of the renovation, in fact, they agreed to undertake this action, only after inspecting the gas pipeline by the intelligent pig tool.

So we took the opportunity to investigate, over the first 10 Km of the gas pipeline’s first section* by using electrical field measurement methods ( DCVG & CIPS ),combined with the historical CP data parameters to predict where corrosion could take place and compare it with the results of the inspection by intelligent pig.

This report throws investigation results, pictures of our undertaken actions, in which time and costs were evaluated showing the positive and negative sides of the two alternatives, a conclusion and recommendations are done in such case, someone could inspire with this experiment.

* : the section is the one which support the high pressure levels 2 - TECHNICAL CHARACTERISTICS OF THE GAS PIPELINE:

The main characteristics of the gas pipeline were as follow: - Diameter: Ø 20’’ - Total length: 273,524 Km ( 265 Km initially ) - Thickness: 7.92 - 12.70 - 16 mm - Steel Grade: X 52 - Type of the coating: 88.920 Km coal tar enamel (new parts) and the rest is petroleum bitumen.

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3 - CORROSION PREDICTION USING CP DATA AND ELECTRIC AL FIELD

SURVEYS: 3 – 1 Choice of the area’s pipe to investigate

Starting from the acceptable basis that, containing external corrosion of buried metallic structures is possible only if two protection techniques are used. The first one is to assure the separation of the structure from the soil by applying an adequate coating. The second is applying cathodic protection ( CP ) to the structure, cause there in no coating which could insulate the structure from the soil at 100 % ( without taking into account that coating defects appear in time ).

Our work was then, to delineate the coating defects on the buried pipeline.

As we’ve seen in the introduction, we focus our work over the Relizane – Sig section. After analyzing the historical CP’s data, three areas of the gas pipeline knew a level of potentials (to the copper – copper sulfate half cell reference Cu/CuSO4), below the criterion protection.(see Fig. 1 ).

Three regions presented the same conditions to undertake investigations, we chose the first one cause as we said, it’s the part of the gas pipeline which supports the high pressure levels.

P.K. : Kilometer Point.

20'' Relizane-Sig On Potential 1995-1999

0

500

1000

1500

2000

2500

3000

3500

0 10 20 30 40 50 60 70 80P.K. [ Km ]

Pot

entia

l [ -

mV

]

Threshold of protectionOn Potential 95On Potential 97On Potential 99

0

50

100

150

200

250

300

350

400

450

0 10 20 30 40 50 60 70 80

Res

istiv

ity [ Ω

.m ]

Soil resistivity

GRD RELIZANE P.K. 0,000 GRA SIG

Area N° 1 Area N° 2 Area N° 3

Line breaks

Fig.1 Synoptic plan of Relizane – Sig section and i ts 1995-97-99 potential plots

: New parts of the pipe

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mV

ΩΩΩΩ

Pipe detection

ρ soil resistivity measurement DCVG measurement

CIPS measurement Test point

Half cell Cu/CuSO4

3-2 Coating defects research:

3-2-1 Principle of the survey methods:

Tow survey methods were used simultaneously, the measurement of the lateral voltage drop using two copper – copper sulfate half cell ( DCVG ) and the close order potential survey using only one half cell ( CIPS ) ( see Fig.2 ).

The measurements were done in ON-OFF ( by connecting a time contactor to the rectifier ), of course, prior to undertake these measurements the pipe’s location was done.

The measurements were taken each 5 meters ( when necessary it’s reduced to locate with accuracy the coating defect’s epicenter).

When an important defect is located it’s marked on a map (experience showed that stakes could easily be stolen).

At this time of these investigations we didn’t get a GPS equipment, which could gave a big hand to our work.

3 – 2 – 2 Interpretation of the results:

Thousands of data were gathered, to interpret easily the results we plotted (versus the distance covered):

- the On – Off potential of the pipeline ( P On and P Off ) - the gradient voltage difference VOn – VOff ( ∆ V ) or IR % (100x∆ V/∆ P ). It’s useful to remind that, when a direct current is applied to a pipeline, a voltage gradient is

established on the ground, due to the passage of the current through the soil to the bare steel exposed at the defect. Generally, the larger defect is, the greater the current flow and hence larger voltage gradient.

In the same manner we can use the % IR that represents the percentage of the applied potential (∆

P) which is lost on the fault position (∆ V) , and generally the IR % value increases with the increasing defect size/current requirement.

Fig. 2 Illustration of the combined methods CIPS & DCVG techniques

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Before giving the result of the coating survey it’s useful to define the categories of the coating

defects:

- 1st category means IR % greater or equal to 10 and less than 30. - 3rd category means IR % greater or equal to 50. - 2nd category is between 1st and 3rd ones.

The following table synthesizes the surveys results by pipe’s sections:

Number of defects coating Pipe sections

3rd category 2nd category 1st category P.K 0.2 TO P.K 1.45 0 03 17 P.K 1.45 TO P.K 3.30 0 0 06 P.K 4.4 TO P.K 5.44 22 28 73 P.K 5.8 TO P.K 6.8 26 31 86 P.K 6.9 TO P.K 7.99 37 16 17 P.K 8.0 TO P.K 9.2 61 81 54

The first attractive result is that the change of the sections during the 1st programme of gas

pipeline’s rehabilitation presents a few number of defects.

Once detecting the localisation coating defect, we start analysing them from the point of view of cathodic protection level ( see annexe I), and the soil aggressivity ( for the soil classification see table N°2 ), we can therefore predict the presence of the corrosion at the defect coating.

The following table shows an example of how the gathered data are arranged to make easier the

analysis:

3rd category IR % greater or equal to 50

Defects Distance Cathodic Prot. Soil Resistivity Pipe sections

Nbr distribution [ Km ] Level [ mV ] Ω.m 1 8.045 - 850 16 7 8.090 to 8.15 - 750 17 1 8.185 - 790 19 44 8.235 to 8.785 -920-570-740 19-25 1 8.835 - 860 28 3 8.86 to 8.88 -715 to - 800 30 3 8.925 to 8.935 -670 to -690 30

P.K 8.0 TO P.K 9.2 61

1 9 - 640 30

Of course, it’s important to recall that we need the historical CP data. For this purpose, we took the

last 08 years of the quarterly* ON potential surveys and the monthly* rectifier’s measurement reports, in addition to the ON-OFF potential surveys done on 1993-95-97 and 99 ( see Fig.1 for the years 95,97 and 99 ).

Here, it’s important to mention that a ‘’BANK’’ of PC data is vital for of any existing pipeline. As an

example of that, the part of the pipeline situated between P.K 02 and 06 was found protected when we did the surveys, but it was the one which was the most affected: lack of protection for the years 1994 and 1995 (we have reinforced the protection system by a new rectifier at P.K. 06 ) and subjugated to an aggressive soil. * : measurements are done by our regional teams.

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All the 3rd and 2nd categories coating defects were well analysed, and we have predicted the

possibility of the corrosion presence (with the ration of one corrosion point per one coating defect in which the corrosion process is likely to occur: we don’t have tools to predict more than one).

The corrosion prediction is given by section of the pipe as shown in the following table:

Pipe section Number of the Corrosion points predicted

P.K 0.2 TO P.K 1.45 00 P.K 1.45 TO P.K 3.30 00 P.K 4.4 TO P.K 5.44 48 P.K 5.8 TO P.K 6.8 25 P.K 6.9 TO P.K 7.99 30 P.K 8.0 TO P.K 9.2 91

The results given in the above table were obtained, after analysing point per point of the second

and third categories coating defects. As an example, the following table shows how the upper table is obtained.

Corrosion prediction Distance Soil Resistivity Pipe sections

Nbr distribution [ Km ] Ω.m 09 8 to 8.13 17 56 8.235 to 8.785 19-25 12 8.86 to 8.88 30 03 8.925 to 8.935 30 08 8.94 to 8.98 30 02 9 to9.005 30

P.K 8.0 to P.K 9.2 91

01 9.05 30

3 – 2 – 3 Cost of the survey operation:

The DCVG and CIPS surveys were done by our own company team. 04 people (among them two experts), undertook the investigations which spent 08 days ( in site ). The total cost of the operation is 4 K$. 4 – INSPECTION OF THE GAS PIPELINE BY THE INTELLIGE NT TOOL. 4 - 1 Principle of the inspection

The pipe inspection was done by the Magnetic flux leakage process, using a high resolution equipment with the range of accuracy for depth of defect up to ± 10%. The corrosion points were given in three axial axis dimensions. Many information were given concerning the corrosion point or the pipeline its self. ( see annexe). Fig. 2 shows how corrosion point is visualized in 3 D, by "zoom plot". The Red zones designate corrosion defects. 4 - 2 Time evaluation: from the call of tender to f inal results

More than one year from the tender of call to the reception of the inspection results ( the time include the tender launching, analysing the technical offers, asking the tenderer for details and additional information, commercial offer, preparation of the conditions to permit the inspection of the gas pipeline…………….).

Fig.2 Corrosion points

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4 - 3 Inspection results

The following table gives the corrosion number per sections of the pipeline.

Pipe section Number of the Corrosion points

P.K 0.2 TO P.K 1.45 17 P.K 1.45 TO P.K 3.30 24 P.K 3.30 TO 4.4 48 P.K 4.4 TO P.K 5.44 293 P.K 5.8 TO P.K 6.8 49 P.K 6.9 TO P.K 7.99 17 P.K 8.0 TO P.K 9.2 212

The following graph gives the distribution of the corrosion points for the 10 first kilometres : thickness loss versus distance:

0

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30

40

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60

70

80

90

0 1 2 3 4 5 6 7 8 9 10

Distance [ Km ]

% T

hick

ness

loss

Corrosion Points

Fig.3. Corrosion distribution: % thickness loss ver sus distance

4 - 4 Cost of the inspection

The total cost of the inspection was 577.8 K$

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5 - ANALYSIS AND COMPARISON OF THE MFL TOOL AND ON LINE SURVEYS RESULTS :

The following table synthesizes the corrosion points obtained by MFL tool inspection with the ones predicted by on line surveys methods:

Number of the Corrosion points Pipe section Inspection’s results Predicted by online surveys

N°1 P.K 0.2 TO P.K 1.45 17 00 N°2 P.K 1.45 TO P.K 3.30 24 00 N°3 P.K. 3.30 TO 4.40 48 00 N°4 P.K 4.4 TO P.K 5.44 293 48 N°5 P.K 5.8 TO P.K 6.8 49 25 N°6 P.K 6.9 TO P.K 7.99 17 30 N°7 P.K 8.0 TO P.K 9.2 212 91

At this step, if we had a GPS equipment the comparison of the two results would be very easy and accurate, because the measure of distance covered by the technician could never be equal to the one done by the intelligent pig. The P.K of the pipe’s special points and the test points helped us in some cases to correct our results.

As the work we’ve done for the corrosion prediction, we compare point per point the results obtained and listed in the above table.

As an example, the following table gives the way, of how we did the comparison for the pipe’s section N°7 :

Corrosion points Nbr distribution

Distance Observations Pipe sections

MFL Surveys MFL Surveys [ Km ] 00 09 8 to 8.13 Corros. at PK 7.8 and 7.9

170 56 8.235 to 8.785

00 12 8.86 to 8.88 00 03 8.925 to 8.935

08 8.94 to 8.98 Difference of 48 m 02 9 to 9.005 Difference of 28m

P.K 8.0 to P.K 9.2 212 91

06 01 9.05 Difference of 19m

If we neglect the number of the corrosion points, the first attractive result is, our prediction failed for

the first sections N° 1 and 2 (we predicted zero co rrosion point). In fact for the first sections, 15 corrosion points over the 17 (found), are located where we had found a coating defect of second category.

We also missed to predict corrosion on these parts of the pipe:

- P.K 3.30 to 4.4 : 48 corrosion points. 04 points with respectively metal loss of 25, 25, 22, 17 and 75 at the section P.K. 3.552 – 3.557. The rest are all less than 17 %.

- P.K. 9.674 to 9.804: 24 corrosion points with metal loss, less or equal to 13% of the thickness and 02 of respectively 22 and 17 %.

For the rest of our predictions, results showed that if we hadn’t got approximately the same P.K. of

the corrosion locations, we’re at least far from of 50 to 70 meters.

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Just after getting the MFL tool results, our company started the reparation of the most severe

corrosion points located at P.K. 8.775, this operation confirmed us that our result : coating defect location and the corrosion prediction.

The graphs given in the annexe show the distribution of the corrosion and coating defect versus the distance of the pipe, and give an overview what we’ve just explained. (they are better to evaluate rapidly the obtained results ) 6 – CONCLUSION.

There is no doubt that the best way to detect corrosion in pipeline is the inspection by intelligent tool, because the gas operator will know with accuracy the real condition of the pipe wall thickness and hence ensure a safe operation of its gas pipeline.

On other hand if the gas operator has a non-piggable pipelines or he wants to save money the on

line surveys ( GVDC – CIPS techniques ) gives good results, providing, to get first of all, a large ‘’BANK’’ of PC data, and an experiment technicians.

7 - REFERENCES

1. DR. J.M. Leeds “A critical review of the techniques used to delineate pipeline coating defects as a precursor to refurbishment”.

2. DR. J.M. Leeds “ The DC voltage gradient method for accurate delineation of coating defects

on buried pipelines” UK Corrosion 1990.

3. W.G.Von Baeckmane (1973)”Measurement and importance of the Off potential in applying

cathodic protection to pipeline’’ 12th WGC NICE73. 4. W.G.Von Baeckmane “Taschenbuch fur den kathodischen korrsionsschutz” .

5. C.Corradetti, E.Bini and D.Gentile “Results of ‘’IN SITU’’ coating integrity surveys as routine

control on new gas lines impact on gas line quality, design aspects and organization of the work.

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8 - ANNEXES

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Potential On Off Sample N°1

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500

1000

1500

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2500

3000

0,2 0,3 0,4 0,5 0,6 0,7 0,8 0,9 1 1,1 1,2 1,3 1,4

Distance [ Km ]

Pot

entia

l [ m

V ]

Potential ONPotential OffThreshold protection

IR %

-20

-10

0

10

20

30

40

50

60

0,2 0,3 0,4 0,5 0,6 0,7 0,8 0,9 1 1,1 1,2 1,3 1,4

Distance [ Km ]

IR %

IR %

Corrosion points

0

5

10

15

20

25

30

0,2 0,3 0,4 0,5 0,6 0,7 0,8 0,9 1 1,1 1,2 1,3 1,4

distance [ Km ]

% C

orro

sion

dep

th Corrosion points

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VOn-VOff

-60

-40

-20

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120

4,425 4,525 4,625 4,725 4,825 4,925 5,025 5,125 5,225

Distance [ Km ]

Vol

tage

Gra

dien

t [ -

mV

]

VOn-VOff

Corrosion points

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5

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40

4,425 4,525 4,625 4,725 4,825 4,925 5,025 5,125 5,225

distance [ Km ]

% C

orro

sion

dep

th

Corrosion points

Potential On-Off Sample N°2

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1600

4,425 4,525 4,625 4,725 4,825 4,925 5,025 5,125 5,225

distance [ Km ]

Pot

entia

l [ -m

V ]

Potential OnPotential OffThreshold protection

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Potentila On-Off Sample N°3

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200

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1000

1200

1400

8 8,2 8,4 8,6 8,8 9 9,2

Distance [ Km ]

Pot

entia

l [ -

mV

]

Potential OnPotentiel OffThreshold protection

IR %

-50

0

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250

8 8,2 8,4 8,6 8,8 9 9,2

Distance [ Km ]

IR %

IR %

Corrosion point

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8,0 8,2 8,4 8,6 8,8 9,0 9,2Distance [ Km ]

% C

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Corrosion point

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Contrôle De Canalisation

Algeria

20" VECTRA MFL Inspection ( 0157 )

Sonelgaz_Relazine to Sig (76.883km) Informations D'Ellipsoïde: WGS84

Date of Inspection: 25 September 1999 Méridien Central : 3°E Nombre De Zone: 31 N

BJ Process and Pipeline Services Ltd.

BJ Chainag

e (m)

Position Horloge

Épais. Paroi (mm)

Long. (mm)

Larg. (mm)

Prof. Max (%) Loc.

Longitude / Latitude (DMS)

4,493.55 05 : 30 7.92 40.1 27.2 15 EXT. N: 35 ° 42 ' 58.672 " E: 0 ° 32 '

9.728 "

4,493.55 04 : 15 7.92 26.3 27.2 11 EXT. N: 35 ° 42 ' 58.672 " E: 0 ° 32 '

9.728 "

4,493.56 03 : 45 7.92 15.1 19.6 22 EXT. N: 35 ° 42 ' 58.672 " E: 0 ° 32 '

9.728 "

4,493.57 03 : 15 7.92 40.0 145.1 35 EXT. N: 35 ° 42 ' 58.672 " E: 0 ° 32 '

9.727 "

4,493.58 02 : 45 7.92 17.8 25.7 35 EXT. N: 35 ° 42 ' 58.672 " E: 0 ° 32 '

9.727 "

4,493.58 03 : 15 7.92 32.9 42.3 16 EXT. N: 35 ° 42 ' 58.672 " E: 0 ° 32 '

9.727 "

4,493.60 08 : 30 7.92 23.0 28.7 10 EXT. N: 35 ° 42 ' 58.672 " E: 0 ° 32 '

9.726 "

4,493.60 07 : 15 7.92 98.0 60.5 26 EXT. N: 35 ° 42 ' 58.672 " E: 0 ° 32 '

9.726 "

8,774.09 05 : 30 7.92 12.8 24.2 14 EXT. N: 35 ° 43 ' 6.074 " E: 0 ° 29 '

20.181 "

8,774.10 06 : 00 7.92 14.0 18.1 16 EXT. N: 35 ° 43 ' 6.074 " E: 0 ° 29 '

20.181 "

8,774.11 06 : 00 7.92 86.0 157.2 35 EXT. N: 35 ° 43 ' 6.074 " E: 0 ° 29 '

20.180 "

8,774.13 06 : 00 7.92 15.8 24.2 20 EXT. N: 35 ° 43 ' 6.074 " E: 0 ° 29 '

20.180 "

8,774.14 06 : 00 7.92 38.0 51.4 15 EXT. N: 35 ° 43 ' 6.074 " E: 0 ° 29 '

20.179 "

8,774.14 05 : 30 7.92 12.9 25.7 20 EXT. N: 35 ° 43 ' 6.074 " E: 0 ° 29 '

20.179 " Sample of a part of the inspection’s results