1

Control Strategies

In Oil and Gas Pipelines

(PETROJET 15 years Projects Case History)

Nabil Hamdy

Cairo – Egypt

Coating Director & Certified Inspector

PETROJET - Engineering Department

E-mail: NabilHmdy@yahoo.com

Matrial.sector2@petrojet.com.eg

Cell Phone: +20 122 77 36 410

Office : +202 2625 3331

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ABSTRACT

Oil and gas still our main sources of energy, otherwise eco-compatible alternatives are

costly and their application is limited or they are economically valid but undesirable

owing to potential environmental risk factors like nuclear power which their use is

consequently limited in some countries.

In future, hydrogen may become a valid option, but for the time being, fuel demand is

satisfied by fossil resources that are being continually identified by technological

developments for prospecting in deep waters, thus putting off the time when they run

out.

Therefore we forced to face the challenge in design the most suitable strategy in

corrosion protection to pipelines used for hydrocarbons transport which will achieved

by the combination of a materials development and selection, protective coating

(factory coatings / field coatings) and cathodic protection (CP) to preserve the metal

exposed to corrosive environments and also in operation phase (corrosion monitoring /

inspection plan – maintenance plan).

Hence the effective protection strategy will depend upon the equilibrium between all

variables including: basic materials, coating condition and the CP level, in integrated

engineering process.

This study simply demonstrates the strategies used in corrosion protection for pipelines

during design / construction phases and discuss pipe coating in more details including

coating performance / coating properties / factors effect selection...etc. by PETROJET

during last 15 years.

Key-word: Pipeline, Coating, Corrosion, Protection,

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INTRODUCTION

Unprotected pipelines, whether buried in the ground, exposed to the atmosphere, or

submerged in deep sea, are susceptible to corrosion. Without proper maintenance,

every pipeline system will eventually deteriorate; also corrosion can weaken the

structural integrity of a pipeline and make it an unsafe vehicle for transporting

potentially hazardous materials.

However, technology exists to extend pipeline structural life indefinitely if applied

correctly and maintained consistently, although data management, system

quantification through the use of global positioning surveys, remote monitoring, and

electronic equipment developments have provided significant improvement in several

areas of pipeline corrosion maintenance, there have few basic changes in the approach

to the management of corrosion on pipelines until recently.

The use of integrated Corrosion control strategy for Pipelines is the most affective tolls

for corrosion protection in this very important sector.

1. Why Do We Control Pipeline Corrosion?

For many years, the frequent replacement of corroded pipelines was an unchallenged

cost where aggressive soil conditions promoted extensive external corrosion. External

corrosion of distribution systems leads to two major problems. The first problem is the

failure of the distribution system pipes. The second is the contaminations into the

distribution system. For internal corrosion each year, tens of millions of dollars are

expended to replace or repair pipes and vessels that suffer excessive localized metal

loss, stress corrosion cracking [SCC], or hydrogen embrittlement [HE]. When sulfide is

present, this type of brittle failure is known as sulfide stress cracking [SSC].

The corrosion-related cost to the transmission pipeline industry has recently determined

to be $5.4 to $8.6 billion U.S. dollars annually in the United State .This can

divided into the cost of failures, capital, and operations and maintenance (O&M) at

10%, 38%, and 52 %, respectively.

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Statistical data on incidents reported and has been analyzed - compared in order to find

out the main causes of failures:

Figure 1: Main Causes Failures on Steel Pipelines

To protect against external and internal corrosion (The oil industry contains a wide

variety of corrosive environments. Crude oil and gas commonly contain entrained

water, carbon dioxide [CO2], and hydrogen sulfide [H2S]. The transport of

these types of products always induces failures in the pipeline systems, and not less

frequently in the weld beads. ), a number of methods including coatings, cathodic

protection, lining and cleaning were used. This method can reduce effectively the

corrosion damage in pipeline, but it is a cost problem due to additional equipment for

installation. Moreover, corrosion problems still can occur on the system under certain

conditions.

Therefore, it has become urgent to have reliable systems for accurately measuring the

rate of corrosion in existing as well as new structures and for evaluating the

performance of corrosion protection.

2. Integrity Management Process:

Succeed strategies must depended on integrated management process for pipeline

system, including structural / containment function. And ability to constructed /

Corrosion : Internal - External 35%

Impacts : Mechanical - Thermal 15%

Other : 14%

Anchor : Off shore 12%

Nat. Hazard

: Environmental Impact 11%

Material : Selection for

construction 7%

Structural : Design 6%

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operated safely and withstand maximum work loads imposed during the lifecycle

(design life time).

The process as whole is long term and integrative process that involves planning,

execution, evaluation and documentation of:

- Integrity control activities which cover inspection, monitoring, testing, and

assessments.

- Integrity improvement activities which cover mitigation, intervention and repair

activities.

- Adapted detailed plans governed by the strategies and also risk based.

As the concept, design and construction phases reach their end, the development and

establishment of the integrity management system should be well on the way.

Transfer Phase including:

- Transfer of documents relevant for the operational phase ( DFO )

- Identification and cooperation with the project organization

- Resolve any engineering / technical information issues which are critical for take-

over.

- Training of operation staff.

- Detailed Plans to be established for hand over

- Organization structure to be issued

- Risk assessment plan / matrix

Operation Phase including:

- Operational control procedures and activities

- Start up and shutdown procedures

- Cleaning and maintenance, etc.

- Inspection, Monitoring and Testing

- Mitigation, Intervention and repair

- Storage and preservation of spare and contingency equipment

Design Extension: Must re-qualification re0assessmed of the design under any

changed in design conditions, a re-qualification may be triggered by a change in the

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original design basis, by not fulfilling the design basis or by mistakes or shortcomings

discovered during normal or abnormal operation. Possible causes may be:

- New Standard

- Change of premises

- Change of operational parameters

- Change of flow direction or fluids

- Deterioration mechanisms exceed the original assumption

- Extend design life

- Discover damages / Failures

INTEGRITY MANAGEMENT PROCESS IN LIFE CYCLE

PERSPECTIVE:

3. How Do We Control Pipeline Corrosion?

Corrosion control is an ongoing, dynamic integrated process. The keys to effective

corrosion control of pipelines are quality design and installation of equipment, use of

proper technologies, and ongoing maintenance and monitoring by trained professionals.

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An effective maintenance and monitoring program can be an operator's best insurance

against preventable corrosion related problems. Effective corrosion control can extend

the useful life of all pipelines. The increased risk of pipeline failure far outweighs the

costs associated with installing, monitoring, and maintaining corrosion control systems.

Preventing pipelines from deteriorating and failing will save money, preserve the

environment, and protect public safety.

The coating is the primary corrosion mitigation system and the CP is the supportive

system that protects the pipeline metal where the coating has failed. However, in spite

of all these precautions, a coating disbondment may locally occur. It leads to the

penetration and the stagnation of the electrolyte contained in the soil in confined space

between the coating and the pipeline. In the past few years, new techniques have

emerged to assist the corrosion engineer in the evaluation of the corrosion control of

their pipelines.

I- Corrosion Control System Monitoring:

Good, meaningful results can be gathered by taking measurements with DC voltage

gradient (DCVG) equipment to locate coating defects and then gauging the pipe-to-soil

potential and direction of current flow at the defect epicenter with a simple voltmeter

while the CP system is switched ON/OFF at the frequency used by the DCVG

technique. Once pinpointed, the defect severity is determined. The term "severity" is

preferred over "size" because, although related to the coating damage (size), the

electrical measurements taken, determined by the CP current flowing to individual

coating faults, are dominated by the nature and type of films on the exposed steel

surface.

Defect severity is expressed as a percentage (%IR) of the available CP (DCVG signal

amplitude) applied to the pipeline at the defect. Defects are located by examining the

voltage gradients in the soil above the pipeline, to which DC current is applied. By

examining the voltage gradients around the flaw, we can determine the shape of the

defect.

They can be isolated or continuous. Also, knowing the sense of the current flow to or

from, a defect it is possible to investigate their cathodic or anodic behavior under CP

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application. By measuring the DCVG pulsed signal at TP´s and its strength from the

pipe to remote earth it can be determined for each defect what is called its %IR. This

allows the DCVG to grade the severity of each defect according to the %IR and its

behavior. Coating defects are then classified in different categories, which will

determine the repair activity required. During the Integral Evaluation of the External

Corrosion System for Pipelines, IECCSP, the effect of other structures on the ECCSP,

such as: faulty insulating devices, defective test post, faulty transformer rectifiers,

anode beds, shorted casings in road crossing, etc., can be evaluated. Also, interference

with other structures was detected and their influence assessed. The IECCSP provides

an effective way to maintain the continuous, safe and maximum capacity operating

condition of the pipeline with minimum expenditure.

II- Pipeline External Corrosion Survey Inspection methods :

To achieve pipeline integrity with minimum expenditure and applying suitable

maintenance program must analyzing the results of following technique:

Direct Current Voltage Gradient Inspection [ DCVG ]

Close Interval Potential Survey [ CIPS ]

Continuous Soil Resistivity Evaluation [ CSRE ]

Corrosion Damage Monitoring of Buried Pipelines : Many tools used to monitoring

corrosion and detect its rates the modern corrosion sensor for detecting and monitoring

the external and internal corrosion damage of pipeline is Galvanic sensor ( copper-

pipeline steel / stainless steel - pipeline steel ) in which a good liner quantitative

relationship between the sensor output current and the corrosion rate of the pipeline

steel

Four common methods used to control corrosion on pipelines are protective coatings

and linings, cathodic protection, materials selection, and inhibitors.

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1- Coatings and linings are principal tools for defending against corrosion. They are

often applied in conjunction with cathodic protection systems to provide the most cost-

effective protection for pipelines.

2- Cathodic protection (CP) is a technology, which uses direct electrical current to

counteract the normal external corrosion of a metal pipeline. CP is used where all or

part of a pipeline is buried underground or submerged in water. On new pipelines, CP

can help prevent corrosion from starting; on existing pipelines; CP can help stop

existing corrosion from getting worse.

3- Materials selection refers to the selection and use of corrosion-resistant materials

such as stainless steels, plastics, and special alloys to enhance the lifespan of a structure

such as a pipeline. Materials selection personnel must consider the desired lifespan of

the structure as well as the environment in which the structure will exist.

4- Corrosion inhibitors are substances which, when added to a particular environment,

decrease the rate of attack of that environment on a material such as metal or steel

reinforced concrete. Corrosion inhibitors can extend the life of pipelines, prevent

system shutdowns and failures, and avoid product contamination.

Evaluating the environment in which a pipeline is or will be located is very important

to corrosion control, no matter which method or combination of methods is used.

Modifying the environment immediately surrounding a pipeline, such as reducing

moisture or improving drainage, can be a simple and effective way to reduce the

potential for corrosion.

Furthermore, using persons trained in corrosion control is crucial to the success of any

corrosion mitigation program. When pipeline operators assess risk, corrosion control

must be an integral part of their evaluation

III-Pipeline Coating Performance:

The relationship of the various components in pipeline project is well understood.

These include: cost estimation, engineering, design, easements, product contracts, steel

purchase/shipment, coating, installation, inspections, girth welds, line pipe testing and

commissioning, then day to day operation for life time and long term asset protection in

service. The coating plays a minor role in the scheme relating to the engineering and

construction phase, but a major role in asset integrity/operational phase, and can

influence cost greatly on a one time basis at the installation phase. Protection of the

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value as a pipeline asset by guaranteeing its integrity and safety well beyond its design

life is the ultimate function of the coating.

Pipeline Coating Design: It is most important to recognize that the coating material by

itself will not result in optimum corrosion protection of the pipeline. We must look at

the total integrated pipeline protection system which also includes:

Steel quality

Coating application

Applicator

Surface conditioning

Surface treatments

Design of the coating

CP system .

1. Characteristics of Pipelines

Uses and Types of Pipelines

Steel Pipelines: Onshore Construction

Steel Pipelines: Offshore Construction

Ductile Iron Pipes: Onshore Construction

2. Corrosion of Pipelines

Fundamentals of Pipeline Corrosion

Influence of Soil

Pipeline Corrosion Control

3. General Characteristics of Pipeline Coatings

Requirements of Pipeline Coatings

Generic Types of Pipeline Coatings

4. Failure of Pipeline Coatings

What constitutes a Pipeline Coating Failure?

The Consequences of Coating Failure

Mechanisms and Characteristics of Failure

Coating Failure Inspection

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5. The inspector's Responsibilities

Interpreting the Specification

Quality Control Tasks

Status of the Inspector

Reporting Procedures

6. Inspection Practices

Surface Preparation

Standard Inspection Tests

Holiday Detection

Thermit Welding

Pipe Storage and Handling Practices

7. Inspection of Plant-Applied Coatings

Extruded Polyethylene

Fusion Bonded Epoxy

Liquid Polymeric Coatings

Fusion Bonded Polyethylene

Coal Tar Enamel

8. Inspection of Field-Applied Coatings

Heat Shrink Products

Fusion Bonded Epoxy

Liquid-Applied Polymeric Coatings

Coal Tar Enamel

Wrapping Materials

9. Marine pipeline Coatings

Seawater Corrosion

Marine Coating Selection and Performance

Special Application and Quality Control Procedures

Concrete Weight Coatings

Installation of Cathodic Protection Anodes

Some Physical Data of Overall System

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A - Overview of System:

Pipeline overall map (e.g., a geological survey map) on which is indicated the

following:

The pipelines under study,

All parallel or roughly parallel high voltage circuits which come within 1 km of

the pipelines,

All other pipelines feeding or being fed by the pipeline under study,

All exposed structures, such as valve sites, pig launchers & receivers, M&R

stations compressor stations, and other such facilities on the pipelines listed

above,

All insulating flanges on the pipelines listed above,

All anode beds on the pipelines listed above,

Other pipelines which are parallel to the pipelines under study for significant

distances (i.e., on the order of ½ km or more), or which cross them, or

which come within 10 m of them,

All electric substations and generating plants within 300 m of the pipelines under

study or fed by the pipelines under study.

Electric substations of both ends of each high voltage circuit shown on the map.

Note: It is important to study the pipeline of interest as part of a system and not

in isolation: AC interference does not recognize changes in pipeline ownership

nor is it necessarily blocked by an insulating flange. Include in the drawing

therefore, all parts of the pipeline network which is under the influence of high

voltage power line circuits and show all circuits which are in proximity with the

pipeline network.

B - Details of System Layout:

Plan view drawings of the system described in Item (A) above, allowing lengths and

separation distances of all power lines and pipelines to be easily determined. In

particular, please provide, for each power line structure (i.e., tower or pole), the

following:

Separation distance of the pipeline under study from the center of the structure,

Separation distance of the pipeline under study from the edge of the structure

(e.g., from the outside of the nearest tower leg). Also, for all substations within 300

m of pipeline or generating plants fed by the pipeline, indicate the location of the

pipeline on a layout drawing of the entire facility.

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C - Pipeline Dimensions:

Indicate the burial depth, the diameter and the wall thickness of the pipelines and

the width of the bottom of the pipeline trench, for new construction.

D - Soil Resistivity Data:

Soil resistivity measurements should be made using frequency-selective equipment

and the Winner method at spicing spanning the range of 0.1 to 100 m at: All

exposed structures (since gradient control grids may be necessary): e.g., at all valve

sites, pig launchers, pig receivers, metering and regulating stations, compressor

stations, etc.;

Locations where one or more power lines deviate away significantly from the

pipeline or vice-versa, at phase transposition locations, at power line crossings, and

at intervals along the parallelism (so that the performance of mitigating wires can be

assessed);

Locations where the pipeline is particularly close to power line structures or

grounds, including substation and power plant locations (for conductive coupling

calculations). SES can provide specifications and training to ensure that these

measurements are made properly.

Note: Since the safety of the mitigation designs and their cost are highly dependent

on the soil data, it is essential that these measurements be made by well trained

personnel.

E - Exposed Structures:

Drawings of valve sites, pig launchers & receivers, metering and regulating stations

and other exposed locations located along the pipeline under study or at its

extremities. These drawings should clearly indicate the fence line, the locations and

dimensions of gates, the property boundaries (i.e., the maximum extent of any

gradient control grid which may be required), the locations and diameters of

structures protruding out of the ground.

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Note: For sites requiring protection, safety considerations often require that gradient

control conductors extend at least 1 m beyond the fence line: it is therefore best that

the fence line be at least 1 m within the property line so that gradient control grid

conductors do not encroach on adjacent property. Furthermore, a layer of crushed

rock may be required to extend

F - Electrical Data:

Coating Resistance. An estimate or a measured value for the coating resistance of

the pipeline, as installed. Note that a factory value is of no value here because

damage to the coating during handling and installation reduces the coating

resistance by several orders of magnitude from the factory value. Typical values lie

in the range of 6,000 ohm-m² - 140,000 ohm-m² or less, with the lower values being

highly dependent on the local soil resist

Anode Beds. For each anode bed identified, indicate its physical dimensions,

configuration of anodes (diameter, length, spacing, horizontal/vertical orientation)

and how the anodes are interconnected (with bare or insulated leads). If the ground

resistances of the beds are known, please provide them.

4. Conclusion:

To reduce the overall risk to the integrity of a pipeline system all available data should

be utilized. The maximum effect is achieved only when the data are analyzed

considering their co-dependencies, including : pipeline overall steadies and

engineering works , pipeline coating design , effective CP system , pipeline operating

and maintenance procedures an schedules , good inspections and continually.

We need more cooperation done in Egyptian Oil & Gas sector (Owners, Engineering,

Research Centers, Constructions, Operations and Maintenances) for build up an

effected integrated corrosion control flexible strategy / plans and developing new

systems applicable for Egyptian case.

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1

Gas Pipelines

( NATIONAL GAS

NETWORK )

ON SHORE

from

24"

to 4

2"

more

than 1

000 k

m

3LPE

EXT.

EPOXY

INT.

HSS PE

GA

SC

O

2008

3LPE

EXT.

EPOXY

INT.

HSS PE 2012

2 Crude Oil Pipelines ON SHORE

from

12"

to 2

4"

more

than 3

00 k

m

PUF

EXT.

INSUL.

EPOXY

PUF

HSS 60

PPC

2008

PUF

EXT.

INSUL.

EPOXY

PUF

HSS 60

2012

3 Gas Pipelines ON SHORE

from

12"

to 2

4"

more

than 2

50 k

m

3LPE

3LPP

EXT.

HSS PE 3L

KPC

2008

HSS PE 2L 2012

Attachments:

MAIN PETOJT PIPELINE PROJECTS COATING

15 YEARS SUMMARY

EGYPT Projects:

16

1

Greater

NEEM

Crude Oil

Pipeline

ON

SHORE 16" 100 km

3LPP

EXT. HSS PP 3L

Greater Nile Petroleum

Operating Company

2005

2006

SUDAN Projects:

OMAN Projects

1

Hubara to

Marmul &

Harweel to

Marmul

Pipelines

ON

HORE

16"

160

km

EXT.

INTER.

HSS PE

3L

HDPE

Liner

Petroleum

Development

Oman (PDO)

2009

18" 2010

JOURDAN Projects:

1

Jordanian Gas

Transmission

Pipeline (Arab

Gas Pipeline –

Stage II)

ON

SHORE 36"

400

km

3LPE

EXT.

HSS PE

3L

Jordanian

Egyptian Fajr

for Natural Gas

Transmission &

Supplies Ltd.

(FAJR

2004

2005

Algeria Project

1 GK3 Gas Pipelines LOT

1 & LOT 2 gas Pipeline

ON

SHORE 48"

450

km

3LPE

EXT.

PU

Resin

Sonatrach TRC

2008

2010

2 Haoud El Hamra?Skikda

(NK1) Crude Oil Pipeline

ON

SHORE 30"

650

km

3LPE

EXT.

PU

Resin Sonatrach TRC

2006

2008

3 ROM BEN Gas Pipeline ON

SHORE 12"

55

km

3LPE

EXT.

HSS

PE

3L

Sonatrach TRC

/ AGIP 2010

4

El Merk Oil Field

Development Pipeline

Works (LOTS 3 & 4)

ON

SHORE

2"-

4'

- 6

" -

8"

-

10

"

235

km

EXT. CAT

PE Groupement

Berkine

(JV of Sonatrach

and Anadarko)

2010

EXT. CAT

PP 2012

17

LIBYA Projects:

1 Sharara Mellitah Crude

Oil Pipeline

ON

SHORE

30" 725

km EXT.

HSS

PE 3L Eni Oil - Libya

2004

30" 2005

2 Tobruk – Sareer Pipeline ON

SHORE

20" 80

km

EXT. CAT

PE Arabian Gulf Oil

Company

(AGOC)

2008

20" EXT. CAT

PE 2009

3 INTSAR SARIER

pipeline

ON

SHORE 20"

225

km EXT.

HSS

PE 3L GPCOEW

2010

2012

KSA Projects

1 Nuayyiem ASL Crude

Increment Pipelines

ON

SHORE 16"

139

km EXT.

VISCOELASTIC+

PE CAT ARAMCO 2008

2

Manifa Field Development

- Crude & Water Injection

Pipelines

ON

SHORE 20"

100

km EXT.

VISCOELASTIC+

PE CAT

ARAMCO

2011

ON

SHORE 12"

50

km

EXT.+

INT.

FBE EXT.

EPOXY INT. 2013

3 JUBIL AH CRUDE OIL

PIPELINE

ON

SHORE 24"

50

km EXT.

VISCOELASTIC+

PE CAT ARAMCO 2010

AUE Projects:

1 HABSHAN 5

UTILITIES

ON

SHORE

24 34 km EXT. HSS PP 3L

GASCO

2010

30 35 km EXT. HSS PP 3L

2011 36

18

km EXT.

HSS PP

3L

36 41

km EXT.

HSS PE

3L

18

IRAQ Projects:

1 16" / 200

KM

Khor El Zubair El

Nassrya

ON

SHORE 16

200

km EXT.

HSS PE

2L OPC 2014

2 6

PIPELINES Basra Rehab.

ON

SHORE

40

km EXT.

HSS PE

2L BGC 2015