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공학석사학위논문

Risk-Based Inspection Modeling for

Underground Pipelines

2016 년 8 월

서울대학교 대학원

화학생물공학부

Ezgi DARICI

Risk-Based Inspection Modeling for

Underground Pipelines

지도교수 한종훈

이 눈문을 공학석사학위 논문으로 제출함

2016 년 6 월

서울대학교 대학원

화학생물공학부

Ezgi DARICI

Ezgi DARICI 의 공학석사학위논문을 인준함

2015 년 6 월

위 원 장 _____________ (인)

부 위 원 장 _____________ (인)

위 원 _____________ (인)

i

Abstract

Underground pipeline systems carrying hazardous substances possess a

significant thread to surroundings unless a certain level of safety is provided.

The pipeline accidents range from small leaks to catastrophic explosions due to

which hundreds of people are dead and injured. In order to prevent these

accidents, all the countries should be responsible for developing their inspection

and maintenance programs and enforcing the pipeline owners to have safe

operation through national regulations. In this study, pipeline safety regulations

in Germany, US, and Spain are investigated, and a methodology to evaluate the

risk levels of pipelines is proposed based on Risk-Based Inspections and

Maintenance Procedures for European Industry (RIMAP). The underground

pipelines in Ulsan-Onsan Industrial Complex are evaluated using the proposed

model. The recommendations for Korean government to build their pipeline

safety regulations are also given considering the practices in Europe and US.

Keywords: Safety, Buried Pipelines, Risk Analysis, RBI, Pipeline Inspections

and Maintenance, Risk Modeling

Student Number: 2014-25246

ii

Contents

Chapter 1. Introduction ..................................................................................v

1.1 Research Motivation and Objectives .................................................1

1.2 Major pipeline accidents ...................................................................3

1.3 Outline of thesis ................................................................................9

Chapter 2. Buried Pipeline Corrosion & Maintenance ..............................10

2.1 Corrosion Theory ............................................................................10

2.1.1 Internal Corrosion .......................................................................... 11

2.1.2 Subsurface (External) Corrosion ...................................................13

2.2 Corrosion Prevention .......................................................................14

2.2.1 Internal Corrosion Preventions ......................................................14

2.2.2 External Corrosion Preventions .....................................................16

2.3 Pipeline Inspections .........................................................................18

2.3.1 Indirect Assessment .......................................................................20

2.3.2 Direct Assessment ..........................................................................24

Chapter 3. Risk-Based Inspection and Maintenance .................................30

3.1 Risk Based Inspection (RBI) Model .....................................................31

iii

3.1.1 Probability of Failure (PoF) ...........................................................32

3.1.2 Consequence of Failure (CoF) .......................................................39

3.1.3 Risk Determination ........................................................................47

3.2 Case Study ............................................................................................49

3.3 Discussions on the RBI Model .............................................................69

Chapter 4. Pipeline Regulations ...................................................................73

4.1 Pipeline Regulations in Germany .........................................................73

4.1.1 Operational Safety Management (BetrSichV) ...............................73

4.1.2 Ordinance on Systems for handling water-polluting substances

(WasgefStAnlV) .....................................................................................76

4.1.3 Sanctions When Legal Requirements Disobeyed ..........................80

4.1.4 Standards / Codes about Separation Distance and Depth of Pipelines

80

4.2 Risk Based Inspection (RBI) Approach in Germany ......................82

4.3 Recommendations for Korea ...........................................................83

Chapter 5. Conclusions .................................................................................85

References .......................................................................................................87

iv

List of Figures

Figure 1 Kaohsiung Propene Explosion Accident Site .....................................4

Figure 2 San Bruno Natural Gas Explosion Accident Site ...............................6

Figure 3 Ghislenghien Natural Gas Explosion Accident Site ...........................8

Figure 4 WHMIS Corrosion Pictogram .........................................................12

Figure 5 The galvanic corrosion cell .............................................................14

Figure 6 Evaluation of Pipeline Coatings .......................................................16

Figure 7 Polymeric Tape and Two-Layer Polyolefin Coatings ......................17

Figure 8 Pipeline Cathodic Protection with Impressed Current Rectifier .....18

Figure 9 CIPS Measurements .........................................................................21

Figure 10 Scheme of CIPS Technique ...........................................................21

Figure 11 Example CIPS Results ...................................................................22

Figure 12 Example DCVG Results ................................................................23

Figure 13 Probability of Failure Determination Scheme ................................32

Figure 14 CoF Determination Scheme ...........................................................40

Figure 15 CoF Level Determination Flow Chart ...........................................41

Figure 16 Risk Matrix ....................................................................................47

Figure 17 Risk Matrix for Each Area .............................................................68

file:///C:/Users/Ezgi1/Desktop/My_MS_Thesis.docx%23_Toc452579887

v

List of Tables

Table 1 Internal Corrosion Prevention Methods [16] .......................... 15

Table 2 Direct Assessment Procedure (*) ............................................ 26

Table 3 Defect Severity Criteria ........................................................... 37

Table 4 Direct Inspection Priority Determination Criteria .................. 38

Table 5 PoF Level Adjustment Criteria ................................................ 39

Table 6 Explanation of the Numerical Criteria Given in the Flow Chart

.............................................................................................................. 41

Table 7 Values of the Numerical Criteria [20] ..................................... 41

Table 8 Flammability Index Determination ......................................... 43

Table 9 Follow-up Actions based on Risk Matrix ................................ 48

Table 10 Target Area Description ......................................................... 50

Table 11 Area 1 Pipeline Information .................................................. 53






Table 17 Area 1 Pipelines PoF Calculation Results ............................. 58


vi




Table 22 Area 6 Pipeline PoF Calculation Results .............................. 62

Table 23 Area 1 Pipelines CoF Calculation Results ............................ 62






Table 29 Follow-up Actions based on the Risk Matrix Results ........... 68

Table 30 Categorization of Carried Fluids ........................................... 73

Table 31 Classification of Single Walled Pipelines ............................. 78

1

Chapter 1. Introduction

1.1 Research Motivation and Objectives

The underground pipelines carrying hazardous materials possess a great risk to

life, commodities, and environment. The possible accidents should be

prevented by regular inspections and renovations if necessary. However, since

the inspections are costly and time consuming, pipeline owners are not temped

to carry out the inspections without a strong driving force such as an actual

accident and/or law enforcement. As more years passed by since the installment

of the pipelines, more accidents started to occur. Consequently, people started

to pay more attention to pipeline inspection and maintenance to prevent further

damage. As such, most of the underground pipelines installed in Korea are

deteriorated more than 25 to 50 years, causing high risk of accidents. Despite

of the high risk, it is observed that the pipelines are not managed and inspected

well in Korea. They are either not inspected, or the previous inspection results

are not kept recorded to be used today, to evaluate the state of the pipelines.

Therefore, Korea needs to establish their pipeline regulations, enforcing the

pipeline owners to keep track of the pipeline state. In addition, a risk-based

model, which would consider the failure mechanisms such as corrosion, is

proposed since the inspection and maintenance approaches in industry have

been globally moving from prescriptive, time-based towards risk-based ones

2

from late 1990’s on. The reason for this change is that prescriptive inspection

periods do not consider the current state of the pipelines, which increases to risk

of an accident occurring until next inspections. Moreover, same inspection

period for all pipelines is inefficient in terms of cost and time since high risk

pipelines should be given priority for inspections. Therefore, in this study,

1. A risk-based pipeline inspection model is developed,

2. Follow-up actions and inspection types are investigated and discussed,

3. Regulations in Germany are studied and suggestions for Korean government

to improve pipeline safety are provided.

3

1.2 Major pipeline accidents

Case 1: Taiwan (Kaohsiung) Gas Explosions

Location: Cianjhen and Lingya districts of Kaohsiung, Taiwan

Date: 31 July 2014

Time: Initial reported gas leak: 8:46 p.m. (UTC+8) [1]

First explosion: 11:57 p.m. (UTC+8) [2]

Fatalities: 32 [3]

Injuries: 321 [3]

Cause: Explosions were caused by a propene leak, and the firefighters could

not extinguish the fires with water. Emergency workers had to wait until the gas

had burnt away after the supply was shut down. A 4-inch pipeline delivering

propene to Ren Da Industrial Park was found to encounter abnormal pressure

between 8:40 p.m. and 9:00 p.m. the night the gas leak was discovered [4]. 3.77

tons of propene leaked between 8:00 p.m. and 9:00 p.m. The company did not

shut down the pipe until 11:40 p.m., 16 minutes before the first gas explosion

occurred. The concentration of the propene at the explosion site was abnormally

high at 13,000ppm [5]. The pipelines had not been properly inspected for 24

years.

Event: Witnesses reported seeing fireballs soaring into the sky and flames

reaching 15 stories high. The blasts ripped up roads, trapped and overturned

cars and firetrucks, and caused a blackout to the electrical grid. About 6 km of

4

road length were damaged [6]. The explosions reportedly blew cars and

motorcycles high up in the air; some vehicles and victims were found at the

rooftops of buildings three or four stories high [7]. One street had been split

along its length, swallowing fire trucks and other vehicles.

Figure 1 Kaohsiung Propene Explosion Accident Site

Case 2: San Bruno Pipeline Explosion

Location: San Bruno, California, United States

Date: 9 September 2010

Time: 18:11 UTC-7

5

Fatalities: 8

Injuries: 58

Cause: During the days prior to the explosion, some residents reported

smelling natural gas in the area [8]. A source within PG&E reported a break in

natural gas line number 132 caused the explosion. The gas line is a large 30-

inch (76 cm) steel pipe. An inspection of the severed pipe chunk revealed that

it was made of several smaller sections that had been welded together and that

a seam ran its length. Newer pipelines are usually manufactured into the shape

needed for these applications, rather than having multiple weaker welded

sections that could potentially leak or break [9]. In January 2011, federal

investigators reported that they found numerous defective welds in the pipeline.

The thickness of the pipe varied, and some welds did not penetrate the pipes

completely. As PG&E increased the pressure in the pipes to meet growing

energy demand, the defective welds were further weakened until their failure.

As the pipeline was installed in 1956, modern testing methods such as X-rays

were not available to detect the problem at that time [10].

Event: A huge explosion occurred, causing fire, which quickly engulfed nearby

houses. The blaze was fed by a ruptured gas pipe, and large clouds of smoke

soared into the sky. It took 60 to 90 minutes to shut off the gas after the

explosion [11]. The explosion and resulting fire leveled 35 houses and damaged

many more. The explosion excavated an asymmetric crater 167 feet (51 m) long,

6

26 feet (7.9 m) wide and 40 feet (12 m) deep along the sidewalk of Glenview

Drive [12].

Figure 2 San Bruno Natural Gas Explosion Accident Site

Ghislenghien, Belgium (30 July 2004) [13]

- Rupture and ignition of a gas pipeline

- 24 dead, 132 injured

Event: The pipeline transported up to 1.6 million cubic meters of natural gas

between the terminal at Zeebrugge harbor and France. The pipeline operator

performed an emergency closure of the mainline valves, but given the distance

of more than 10 kilometers between the upstream and downstream valves, the

7

jet fire of the “line pack” lasted for almost 2 hours (line pack: the total volume

of gas in the pipeline in between two valves) [14].

Cause: Expert analysis showed that the leak occurred as consequence of

“external aggression”, i.e. the scratching of the pipe wall by a mechanical

excavator, with a wall thickness of 4mm instead of the nominal 10mm. It is

thought that damage to the pipeline occurred during the final stages of a car

park construction project. Damage to the pipeline probably occurred as a

mechanical soil stabilizer was driven over it or nearby. This resulted in several

evenly spaced (but not full depth) gouges in the steel wall of the pipeline. Two

weeks after the completion of the car park gas pressure was increased in the

pipeline, which then ruptured with the fault centered on a 350 mm long gouge

[14].

8

Figure 3 Ghislenghien Natural Gas Explosion Accident Site

Some Other Cases

The NTSB (National Transportation Safety Board, USA) investigates

and reports on all natural gas explosion accidents. In the past 25 years, there are

5 cases, NTSB (1987, 2003, 2005, 2011d), described large supply pipeline

ruptures with explosion craters of significant size. Those five explosions are

summarized briefly in the following table [15].

9

1.3 Outline of thesis

The thesis is divided into five chapters. Chapter 1 describes research

motivation and objectives of the thesis, and major pipeline accident cases in

order to give an idea about why this work is necessary.

Chapter 2 describes corrosion theory in general terms including two

corrosion types (internal and external), which play a major role on buried

pipeline failures. Then, corrosion prevention methodologies for both type of

corrosion are explained. The pipeline inspections, especially the ones carried

out in the scope of this work, to ensure safe operation are also explained in

Chapter 2.

Chapter 3 describes the necessity of Risk-Based Inspections and the

risk based inspection model developed in this work. The case study results for

Ulsan Onsan Industrial Complex buried pipelines are presented and finally the

facts and possible improvements about the model are discussed.

Chapter 4 is the summary of the research about the regulations in

especially Germany and other common and accepted practices in Europe and

US. Recommendations to improve pipeline safety in Korea are also provided

based on the practices in Germany and observations about how pipeline safety

is handled in Korea.

Lastly, Chapter 5 presents the summary of RBI model, findings of case

study and conclusion of the thesis.

10

Chapter 2. Buried Pipeline Corrosion &

Maintenance

2.1 Corrosion Theory

All pipelines, whether over or under the soil, or submerged in water,

are under the risk of corrosion if necessary precautions are not taken. Every

pipeline will eventually deteriorate, in case they are not maintained properly,

and become an unsafe mean for hazardous material transportation.

Corrosion in the context of this thesis refers to loss of metal from the

surface of a pipeline. Although it is usually a very slow process, it does require

efforts to halt or slow down the process to prevent disintegration/structural

integrity of the pipelines. Corrosion is one of the most familiar hazards

associated with the metal pipelines.

There are three common corrosion types observed for the pipelines.

These are atmospheric corrosion, internal corrosion, and subsurface corrosion.

The probability of atmospheric corrosion for buried pipelines is very small

when compared to the other types. Therefore, internal and subsurface corrosion

are studied in detail in this work. More detailed information on these two types

are summarized as following.

11

2.1.1 Internal Corrosion

Internal corrosion is caused by the interaction between the carried

product and inside pipe wall. The reaction usually does not caused by the

product itself but the impurities included in the product. For example,

hydrocarbons are inherently non-corrosive but inclusion of H2S, CO2, and

moisture can make them significantly corrosive. Therefore, for transportation

of upstream products, such as crude oil drained from a well, internal corrosion

is a great risk to the pipelines. On the other hand, for the downstream pipelines,

for which the products are pre-processed to remove the contaminants, internal

corrosion is not severe unless there is a fault in the pre-processing. For them,

internal corrosion can be kept under control by selecting the suitable type of

pipe material.

In order to determine if a certain product is inherently corrosive to

metal or not, Workplace Hazardous Materials Information System (WHMIS)

can be used as reference.

WHMIS is Canada’s national hazard communication standard.

WHMIS hazard classification appears in most of MSDSs. WHMIS utilizes

pictograms which are graphic images that immediately show the user of a

hazardous product and what type of hazard is present. Corrosiveness of a

product is indicated by a corrosion pictogram as shown below.

12

However, checking WHMIS categorization is not enough since all

pipelines carrying non-corrosive materials can suffer from corrosion in case

some impurities are introduced.

The factors affecting internal corrosion is well explained ‘Pipeline Risk

Management Manual’ by Muhlbauer as following [16].

Contamination in pipelines are classified into two groups.

1. Water-related contamination: water content, oxygen, pH, H2S, temperature,

chlorides

2. Solids-related contamination: MIC (Microbially Induced Corrosion),

suspended solids, sulfates, carbonates, etc.

In order to make a detailed assessment to estimate the degree of

corrosion, compositions of these contaminants in the pipelines are required. If

the compositions are known, corrosions rates can be determined using the

algorithms and tables given in API RP 581 ‘Risk Based Inspection Technology’.

Figure 4 WHMIS Corrosion Pictogram

13

Because the corrosion mechanisms are hard to analyze, the best source

for corrosion rates is experimental results rather than theoretical equations. If

inspection results for thickness loss does not exist for a particular system,

published experimental values can be checked as a second option. Some

experimental results are presented in literature such as Dechema and Sandvik

corrosion tables, which are important sources especially to evaluate the

compatibility of pipe materials with certain products.

In addition, rather than general corrosion, pitting type (localized)

corrosion forms a greater risk for the integrity of pipelines. Certain products at

certain operating conditions might cause pitting. It should be checked carefully

during inspections.

2.1.2 Subsurface (External) Corrosion

Subsurface corrosion occurs when the outer pipe wall is in contact with

the surrounding soil. Among the types of corrosion, external corrosion is

considered to be the most complex one since various corrosion mechanisms can

be active at the same time. The most common danger is from some form of the

galvanic corrosion as illustrated in Figure 5. When metals are in an electrolyte,

which is the soil in case of buried pipeline, anodic and cathodic regions form

on the metals. The locations where electron affinity is higher becomes the

cathode. If there is an electron flow between these regions, then metal will

14

dissolve at the anodes. The galvanic corrosion cells can form between the

regions with different electron affinities on the same pipeline, or between

different pipelines, and other buried facilities.

Figure 5 The galvanic corrosion cell [16]

2.2 Corrosion Prevention

All pipelines degrade due to corrosion if no precaution is taken. In the

following subsections, some common prevention methodologies are explained.

2.2.1 Internal Corrosion Preventions

For a corrosive product, the common corrosion prevention

methodologies, given in Table 1, can be considered.

15

Table 1 Internal Corrosion Prevention Methods [16]

Prevention

Methodology

Method Description

Internal

Monitoring

- By electronic probe that continuously transmits corrosion

potential measurements or by a coupon inserted into stream

that actually corrodes due to direct contact with the product

- By a test peace carefully removed from pipeline for

inspection

- By searching for corrosion products in pipeline filters or

during pigging operations

Inhibitor

Injection

- If the corrosion mechanism is well known, certain

chemicals can be injected to inhibit corrosion reactions

- Inhibitor combines with oxygen, preventing its reaction

with pipe wall

Internal

Coating

- Spray-on plastics, mortar, or concrete

- Insertion liners for existing pipelines

Pigging

- Used to clean pipelines

- Cannot be used for small diameter pipelines

16

2.2.2 External Corrosion Preventions

External corrosion prevention is usually provided by two layer

protection being ‘external coating’, ‘cathodic protection system’. As long as the

protection layers are sound, external corrosion does not occur no matter how

corrosive the soil is. The prevention methodologies are explained as following.

Coating over pipeline: Pipelines are covered with certain materials to cut the

connection between external surface of the pipes and the soil.

The product evolution for protection of steel pipes has migrated from

field applied asphalt and coal tar-based materials to the currently used high-

tech, field-applied and plant-applied coatings [17].

Figure 6 Evolution of Pipeline Coatings

The main generic types of pipeline coatings in use today include coal

tar enamel, polymeric tapes, fusion-bonded epoxy (FBE), spray-applied liquid

coatings, and two- and three-layer polyolefin coatings [17].

17

Figure 7 Polymeric Tape and Two-Layer Polyolefin Coatings

Cathodic Protection (CP): It is a method to make the pipe the cathode of a

galvanic cell by placing another metal around the pipeline, which has lower

electron affinity. The other metal is called as ‘sacrificial anode’ since it is

sacrificed to corrode instead of the pipeline material. The purpose is reversing

the flow of metal ions from pipe to soil in the absence of a sacrificial anode.

The system is illustrated in Figure 8.

There are two types of cathodic protection.

1. Galvanic (Passive) Cathodic Protection: By using only a sacrificial

anode, such as zinc, magnesium, aluminum, without any extra force to

accelerate electron flow.

2. Impressed Current Cathodic Protection: The system consist of anodes

connected to a DC power source, often a transformer-rectifier

connected to AC power, when the galvanic anodes cannot provide

enough current to the pipeline.

18

Figure 8 Pipeline Cathodic Protection with Impressed Current Rectifier [16]

2.3 Pipeline Inspections

When dealing with large number of pipelines, it is wise to group the

pipelines having similar environment such as passing under or around roads,

mountainous or flat areas, and whether in the water vicinity, etc. The reason is

that the inspection tools are not applicable to all type of pipelines and

surroundings. More information on inspection tool selection is given in

ANSI/NACE SP 0502-2010 Standard Practice, Pipeline External Corrosion

Direct Assessment (ECDA) Methodology.

19

As the first step of pipeline safety evaluations is the pipeline data

investigation. The required basic data are summarized as following:

- Pipe related (material, diameter, wall thickness, etc.)

- Construction related (Year installed, route maps, depths, clearances etc.)

- Soil/Environmental data (soil characteristics, land use, etc.)

- Corrosion control (coating, CP, etc.)

- Operational data (temperature, pressure, records on fluctuations)

- Previous inspection results (if exists)

The types of data to be collected are typically available in construction

records, operating and maintenance histories, alignment sheets, corrosion

survey records, other aboveground inspection records, and inspection reports

from prior integrity evaluations or maintenance actions.

According to ECDA, after collecting necessary data on the pipelines,

first applicable inspection tools are selected, and then indirect inspections,

using these tools, are carried out. According to indirect assessment (i.e.

inspections without excavations) results, pipelines are ranked to determine the

priority of the pipelines for direct assessment (The inspections done on exposed

pipelines). The details of this procedure are documented and publicly available

(ECDA by NACE).

20

2.3.1 Indirect Assessment

Indirect assessment refers to the inspections, which are carried out without

exposure of the pipelines, done from above surface.

ECDA does not utilize the results of a single indirect inspection method to analyze

level of risk, but it requires several types of inspection methods to be applied in a row.

It is a method, in which the pipeline segments, that show anomaly in the results of

various inspection methods, are determined to be the highest risk spots on a pipeline

and given the highest priority for direct inspections.

There are various indirect inspection tools, however the following three methods

that are applied in this work, will be explained in detail.

Close Interval Potential Survey, CIPS

Pulsed Direct-Current Voltage Gradient Method, DCVG

Soil Resistivity Measurements

Close Interval Potential Survey (CIPS): In order to determine the current state

of corrosion protection system, corrosion protection electric potential is measured with

5~10m intervals following the length of the pipeline from aboveground as shown in

Figure 9.

21

Figure 9 CIPS Measurements

Figure 10 Scheme of CIPS Technique [18]

Cathodically protected pipelines are equipped with permanent test

stations where electronic leads are attached to the pipeline to measure the pipe-

to-soil potential [18].

22

CIPS measurement is used to determine the effectiveness of CP system.

The cathodic potential criteria is -850mV. This potential should be sufficiently

cathodic to ensure adequate corrosion protection but not excessively cathodic

to produce coating damage and/or hydrogen embrittlement [16].

CIPS measurement results of some of the pipelines evaluated in this

study is presented in Figure 10. The red dotted line indicates the cathodic

voltage criteria (-850mV) whereas the other colored lines are potential

measurements along the length of pipelines. As seen here, one of the pipelines

has a lower value (absolute value) than the criteria, meaning that there is a

problem with the CP system at that portion of the particular pipeline.

Figure 11 Example CIPS Results

Distance (m)

Cat

ho

dic

Vo

ltag

e (m

V)

23

Direct Current Voltage Gradient (DCVG): It is a technique for coating

surveys on buried pipelines using a rectifier by turning it on/off with scheduled

intervals (1s on/0.5s off). It has been used for not only locating but also sizing

coating defects. The technique is fundamentally based on measuring the voltage

gradients in the soil above a cathodically protected pipeline. A distinctive

feature of this technique is that even small defects can be located accurately,

with a claimed accuracy of about 10 cm (4 inches) [19].

Based on DCVG measurements it is possible to compute a so-

called %IR value. The %IR value should be higher than 30% for a severe

coating defect.

Figure 12 Example DCVG Results

Distance (m)

%IR

24

Soil Resistivity Measurements: Soil resistivity is a function of soil moisture

and the concentrations of ionic soluble salts and is considered to be most

comprehensive indicator of a soil’s corrosiveness. Typically, the lower the

resistivity, the higher will be the corrosiveness. For a pipeline which is laid

under a soil with resistivity less than about 3,000-5,000Ω·m, soil corrosiveness

is evaluated to be high. Consequently, for those pipelines buried in a low

resistivity soil, in case electric anticorrosion is not properly working and if there

are defects in coating, high probability of corrosion should be considered. Soil

resistivity is measured using Wenner four-pin method.

For this project, Soil resistivity is measured for soil samples from 1~2m

depth which is the depth most of the pipelines are laid. Lowest and highest

resistivity measured are 1,686 Ω·cm and 15,309 Ω·cm, respectively.

2.3.2 Direct Assessment

Direct inspection is a method for evaluating the quality of the buried

pipelines, applied on the exposed pipelines after excavation, through direct

examination methods such as checking the degree of external corrosion and

measuring the pipe thicknesses. In contrast, indirect inspections are conducted

without excavation of the covering soil, in order to determine the cathodic

protection potentials, coating damages and soil corrosiveness. Based on indirect

25

inspection results, relatively weak points on the buried pipelines in terms of

external corrosion are evaluated.

The locations that are determined to have risk of external corrosion via

indirect inspections, are then inspected by direct methods in order to evaluate

the current condition and integrity of the pipelines. Based on indirect inspection

results, for the assessment of external corrosion risk, direct inspection is

conducted from the following standpoints.

1. If there is a point where coating defect is detected among the

locations of vulnerable cathodic protection Direct inspection is

carried out to evaluate external corrosion progress and integrity of

pipelines

2. If coating defect exists at a point where cathodic protection is good

and corrosion risk is low Direct inspection is carried out to

check if the points of coating damages are actually well protected

as estimated by indirect inspections.

Direct assessment was required also for checking internal corrosion and

weld quality, which cannot be evaluated by indirect methods. Therefore,

thickness measurements and non-destructive tests are carried out to determine

the existence of internal corrosion and welding quality, respectively.

26

The direct inspection procedure for the evaluation of Ulsan Industrial

Complex buried pipelines are summarized in the following Table 2 with the

illustrative pictures.

Table 2 Direct Assessment Procedure (*)

Main Steps

for Each

Procedure

Inspection Method

Grasping

excavation

target area

underground

pipeline

information

Pipe construction material, Pipe thickness, Year of construction, Study of

cathodic protection and related documents

Checking

whether

leakage

exists before

excavation

Selma (Gas leak detection) Composite Gas Leak Detection

Checking Gas Leakage Detection by Thermal Imaging

27

W whether

leakage

exists after

excavation

Buried

Pipeline

Installation

Status

Inspection

(Visual

Inspection)

Pipe laying depth and Clearance Measurements

External

Corrosion

Inspection

Buried Pipeline Soil Corrosion Measurements

Cathodic Protection Voltage and pH

Measurements

Pipeline Vicinity Soil Corrosion

Calculations

Pipe thickness and Surface Roughness Measurement

Pipe Thickness Measurement Surface Roughness Measurement

28

External

Corrosion

Inspection

Residual Strength Measurement

3D scanner measurement Pipe Residual Strength

Measurement

Pipeline

Material

analysis and

Weld

Inspection

Pipe Material Analysis Weld PAUT Inspection

Measurement by High-Performance

Ultrasound Imaging System Weld MT Inspection

29

(*) The inspections are carried out by CorRel Technonogy Co. Table 2 and

given indirect inspection result figures are formed based on the information

given in their report ‘Ulsan·Onsan Industrial Complex Underground Pipeline Safety

Inspection’.

30

Chapter 3. Risk-Based Inspection and

Maintenance

Risk based inspections aim to minimize the downtime of the systems

resulting from unexpected failures. Using a risk model, system units are

evaluated in terms of safety considering their current state, and then the units

are ranked from most to least risky according to the model results. Ranking is

then used to adjust the inspection intervals and to determine if renovations

required.

As for all risk models, risk has two components being the probability

and consequence. Probability can be determined using historical data and

statistics as well as future predictions. The definition of consequence if very

broad. A model can be built for health effects, environmental consequences, or

business interruption, or a combination of all. As the models, and the failure

modes that are considered might be different for each RBI model, different

models should not be expected to give the same results. In this work, health and

safety factors are considered for consequence determination. A risk-based

inspection model is built based on Risk-Based Inspection and Maintenance

Procedures (RIMAP) for European industries. A short information on RIMAP

and detailed description of the developed model will be given in this chapter.

31

RIMAP

Risk-Based Inspection and Maintenance Procedures (RIMAP) for

European industries has been developed through the collaboration of a number

of contributing partners in the Workshop consisted of recognized end users (e.g.

Exxon), suppliers (e.g. SIEMENS) and 3rd party organizations (TÜ V SÜ D but

also DNV, BV etc). RIMAP is not yet but soon to become a European standard.

The document is supposed to provide a common reference for

formulating the above policies and developing the corresponding inspection

and maintenance programs within different industrial sectors, such as oil

refineries, chemical and petrochemical plants, steel production and power

plants.

RIMAP document (RIMAP CEN WA-15740) is publically available

and can be referred to for more information. In few months, an updated version

is going to become a European standard as EN 16991.

3.1 Risk Based Inspection (RBI) Model

The components of risk, probability of failure (PoF) and consequence of

failure (CoF) are modeled. All pipelines are evaluated have PoF and CoF levels

from 1 to 5, and A to E, level 5 and E being the most severe case, respectively.

Then PoF and CoF levels are mapped on a risk matrix to determine the risk

levels. This process is explained in more detail in the following parts of this

chapter.

32

3.1.1 Probability of Failure (PoF)

Figure 13 Probability of Failure Determination Scheme

The failure mechanism that has an effect on probability of a pipeline

failure is determined to be corrosion. As explained in Chapter 2, there are two

types corrosion as internal and external corrosion. For external corrosion to

occur, all three conditions (coating defect, CP deficiency, corrosive soil) should

coexist. Therefore, at the beginning of the analysis, only internal corrosion is

considered for PoF determination, and then a criteria to incorporate external

corrosion is introduced.

PoF determination steps are schematized in Figure 13. There are three

main steps that are followed in the analysis:

1. Determination of the internal corrosion rates

2. Determination of the remaining life of the pipelines

3. Determination of PoF level

33

1. Internal Corrosion Rates: The best source for corrosion rates is

experimental results such as the thickness loss measurements (through direct

inspections) and internal monitoring results. If such experimental data do not

exist, then the published references can be checked for each fluid.

The possible data sources would be Dechema and Sandvik corrosion

tables. These data sources are also presenting experimental results. Although it

is impossible to get the exact corrosion rates for the steams in concern, they

provide a rough estimation (max. corrosion rates) for various fluids and they

examine the compatibility of the fluids with different pipe materials. The tables

provide corrosion rates considering the carried fluid (corrosiveness and

composition of contaminants), pipe material, and operating conditions

(temperature).

2. Remaining Life Analysis: Pipeline accidents occur because the pipe

walls gets thinner in time due to corrosion and once the thickness is too thin to

handle the internal stress (pressure), the pipeline fails. Remaining life depends

on remaining thickness of the pipe (time until the thickness reaches minimum

thickness) and corrosion rate.

The minimum thickness that a pipe can endure can be calculated using

the minimum design wall thickness formula for cylindrical shells given in

ASME.

34

𝑡𝑚𝑖𝑛 =𝑃𝐷

SE − 0.6P

Where tmin: Min. wall thickness (mm)

P: Pressure (bar)

D: Diameter of the pipeline (mm)

S: Maximum allowable stress (bar)

E: Joint efficiency

To be on the safe side, the usual practice is to take minimum thickness

as 2.5cm. If minimum thickness calculated by the formula is greater than 2.5,

then calculated value is accepted. Otherwise, tmin is assumed as 2.5cm.

Then the remaining life (RL) becomes:

RL =𝑡𝑛𝑜𝑚 − 𝑡𝑚𝑖𝑛 − 𝑦 ∗ 𝑟

𝑟

Where tnom: Nominal thickness (design wall thickness, mm)

tmin: Minimum thickness pipe can endure (mm)

y: Years passed since installation (years)

r: Corrosion rate (mm/years)

3. PoF Level Determination: The purpose is to ensure that no

accidents will occur until next inspections due to internal corrosion. Therefore,

35

the criteria is decided to be dependent on the relative value of inspection period

and remaining life.

PC =𝑇

𝑅𝐿

Where PC: Probability criteria

T: Inspection period

RL: Remaining life

Higher PoF levels indicates higher probabilities. For example, PoF 5

means that, since time until next inspections is equal to or larger than the time

remained until the pipeline fail due to corrosion, immediate actions (much

earlier inspections than planned) should be taken.

Incorporation of External Corrosion into PoF Model

Determination of probabilities based on only internal corrosion is

problematic due to following three reasons.

1. Internal corrosion is not a main failure mechanism. (Most of the

pipeline accidents occurred due to third party damages, welding

defects, and external corrosion in the history.)

2. It is essential to ensure the pipelines are protected against external

corrosion.

36

3. Considering only internal corrosion in the risk calculations might

cause the other failure mechanisms to be overlooked.

Therefore, external corrosion is incorporated into PoF model.

External corrosion occurs due to the contact with the surrounding soil.

Therefore, if the soil is corrosive, then there is higher risk of external corrosion.

However, almost all pipelines are protected against external corrosion through

2 layer protection system: coating and cathodic protection (CP) system. As long

as the protection means are defect free, corrosion does not occur no matter how

corrosive the soil is. Therefore, for external corrosion to occur, these three

problems (coating defect, CP deficiency, corrosive soil) should coexist.

Indirect assessment results are used to evaluate the external corrosion

risk of buried pipelines. DCVG inspections for detection of coating defects,

CIPS for CP system effectiveness check and soil resistivity measurements for

soil corrosiveness determination are incorporated into PoF model. The criteria

to evaluate the severity of defect indication for each inspection type is taken

from NACE ‘Pipeline External Corrosion Direct Assessment Methodology’

standard practice. The criteria is given in Table 3.

37

Table 3 Defect Severity Criteria

Inspection

Methodology

NI (No

Indication) MINOR MODERATE SEVERE

CIPS CP Potential

< -0.85V

0.85V≦Potential

< -0.75V

0.75V≦Potential

< -0.65V

Potential >

-0.65V

DCVG 1 > %IR 1 < %IR < 15% 15% < %IR <

30% %IR > 30%

Soil

Resistivity

(ρ, Ω․cm)

ρ > 20,000 7,000 < ρ <

20,000

3,000 < ρ <

7,000 ρ < 3,000

Then, based on the severity of the defects determined by the criteria in

Table 3, priorities for direct inspections are determined based on Table 4 as

given in NACE.

38

Table 4 Direct Inspection Priority Determination Criteria

As the result of the evaluation through Table 4, all pipelines are

evaluated in regards to the emergency of direct inspections as ‘immediate,

scheduled, monitoring, and no indication of external corrosion’. Immediate

means there is severe risk of external corrosion at that location so it should be

inspected immediately. ‘Scheduled’ is relatively lower risk, meaning that the

location should be inspected on a scheduled date although immediate direct

inspections are not necessary. ‘Monitoring’ means there is some risk of

corrosion at that location but external corrosion did not occur considerably.

CIPS

Severe Moderate Minor NI

Soil

Corrosiveness

Severe I S S M

Moderate I S M NI

Minor I S M NI

NI I S M NI

DCVG

Severe I S S M

Moderate I S M M

Minor I S M NI

NI S M M NI

*I: Immediate, S: Scheduled, M: Monitoring, NI: No Indication

39

Therefore, direct inspections are not required for now but the pipe should be

kept monitored. ‘No Indication’ means that there is no reason to think that the

external corrosion is occurring. Therefore, no actions are needed until the next

indirect inspections.

According to direct inspection priority criteria, previous PoF levels

calculated based on only internal corrosion are adjusted according to Table 5.

Table 5 PoF Level Adjustment Criteria

Direct Inspection Priority PoF Level Adjustment

Immediate PoF 5 (regardless of previous level)

Scheduled 2 levels up

Monitoring 1 level up

No Indication No change

3.1.2 Consequence of Failure (CoF)

For CoF considering safety and health, at least the following parameters

should be taken into account:

Flammability

Toxicity

Reactivity

Energy release (due to pressure or heat)

40

Inventory

Operating conditions

Fluid physical properties

Population Density

The consequence model suggested in this work based on RIMAP is

schematized in the following figure. The necessary data for analysis is given in

the scheme.

Figure 14 CoF Determination Scheme

There are four steps in determining CoF levels:

- Flammability Calculations

- Toxicity Calculations

- Inventory Consideration

- Pressure Risk Calculation

The results of the calculations given above are used to follow the scheme given

in Figure 15 and the criteria in Table 7 and 8.

41

Figure 15 CoF Level Determination Flow Chart [20]

Table 6 Explanation of the Numerical Criteria Given in the Flow Chart [20]

Criteria Explanation

F1-F4 Combustibility Criteria being boundary values of

the combustibility number

H1-H4 Toxicity criteria being boundary values of the

toxicity number

M1-M3 Criteria related to the mass of toxic substance

P1-P4 Criteria related to stored energy

Table 7 Values of the Numerical Criteria [20]

Criteria Level Value Criteria Level Value

Combustibility

(Cf)

F4 95

Inventory

(mh)

M3

500 F3 80 M2

F2 65 M1

F1 35

Toxicity (Ch)

H4 10

Pressure

Risk (X)

P4 20000

H3 8 P3 10000

H2 6 P2 900

H1 2 P1 100

42

The methodology for each calculation step is explained as following.

Step 1: Flammability Calculations (Cf, Combustibility Number)

The equation used to calculate combustibility number is given as below:

Cf = Nm (1+ke) (1+ kθ + kv + kp + kc + kq)

where Nm : Flammability Index,

ke : Enclosure Penalty

kθ : Temperature Penalty,

kv: Vacuum Penalty,

kp : Pressure Penalty,

kc : Cold Penalty,

kq: Quantity Penalty.

The flammability index (Nm) is determined according to the reactivity index

(Nr) and fire index (Nf) provided in NFPA 704 code based on the following

table.

43

Table 8 Flammability Index Determination

Nr

0 1 2 3 4

Nm

Nf

0 0 14 24 29 40

1 4 14 24 29 40

2 10 14 24 29 40

3 16 16 24 29 40

4 21 21 24 29 40

The penalty factors are the values ranging from zero to 1, multiplied with the

flammability index in order to account for the factors that would make a change

in the combustibility of a fluid. The criteria for determination of penalty factors

are given in ‘Dutch Rules for Pressure Vessels’. However, they are not shared

here to avoid confidentiality issues.

Enclosure Penalty (ke)

Since the enclosure causes accumulation of released substance in a small

volume, risk of fire is considered higher. All underground pipelines are assumed

enclosed since they are all buried under soil. Therefore, there is no case where

the enclosure penalty is zero.

44

Temperature Penalty (kθ):

High temperatures (relative to the fluid’s boiling point and flash point) are

penalized with higher penalty values.

Vacuum Penalty (kv)

The pressures less than atmospheric pressure are penalized. Such cases

usually do not exist for buried pipelines. Therefore, vacuum penalty is taken

zero.

Pressure Penalty (kp)

The equation used to calculate the pressure penalty is the following.

kp = k · log(pw+1bar)

Where k is a coefficient without unit and pw is the working pressure.

The coefficient k is again given in the Dutch Rules for pressure vessels.

Cold Penalty (kc)

Working temperatures and boiling points less than zero degree are penalized.

Quantity Penalty (kq)

Quantity penalty is considered in order to account for the amount of

combustible fluid released in case of an accident.

45

Step 2: Toxicity Calculations (Ch, Toxicity Number)

The toxicity number for each pipeline is calculated according to the

following equation.

Ch = Nh (1+ kθ + kv + kp + kc)

Where Nh is the health index, which can be taken from NFPA 704 code.

The penalty factors are the same as the ones in combustibility number

calculations. The difference between the two equations is that, enclosure

penalty is not considered for toxicity calculations.

Step 3: Inventory Calculations (mh)

Calculating the inventory is important since the consequence of the

accidents are strongly dependent on the released amount in case of an accident.

It is simply the mass of the fluid that is expected to be released during an

accident.

Since the inventory is limited through valves in an actual system,

ideally the locations of the valves should be known, and only the amount in

between those valves should be considered. However, since the valve locations

are not known for the Ulsan Industrial Complex case study, the inventories were

calculated considering the whole length of the pipelines.

Inventory is calculated by the multiplication of volume of pipeline in

between the valves and density of the carried fluid according to the following

46

formula.

Where D: Diameter of the pipelines (m),

L: Length of the pipelines (m),

ρ(pw,θw): Density of the fluid (kg/m3)

Density depends on working temperature (θw) and working pressure

(pw). Densities for calculated using Aspen Hysys physical properties tool for

the case study.

Step 4: Pressure Risk Calculations (X)

For flammable and toxic fluids, combustibility and toxicity numbers

(Steps 1, 2) are calculated to estimate the severity of their hazards. However,

the nonflammable and nontoxic fluids can also be hazardous in case of a

pressure burst since the people in the close vicinity of the accident location

might still get hurt due to the energy released in the moment of an explosion.

Therefore, pressure risk is calculated for nontoxic and nonflammable fluids in

order to account for the energy released due to a pressure burst.

A fluid is considered as nonflammable and nontoxic if Nf ≤1 and Nh ≤

1, respectively.

The equation used to calculate pressure risk is given in RIMAP as

following.

47

Where Pw: Working pressure (bar),

V: Volume of the pipeline (m3),

m: Inventory (kg),

T: Working Temperature – Boiling Point (oC).

CoF level determination: Once Flammability Number (Cf), toxicity number

(Ch), inventory (mh), and pressure risk (X) are calculated, CoF level is

determined by following the logic in Figure 15, and using the criteria given in

Table 5.

3.1.3 Risk Determination

Risk levels are determined by mapping PoF and CoF results into a risk

matrix as shown in the following figure.

PoF

5

4

3

2

1

A B C D E

CoF

Figure 16 Risk Matrix

48

The risk levels that each color indicates are as below.

Very High Risk

High Risk

Medium Risk

Low Risk

Very Low Risk

According to the risk levels determined based on a risk matrix, the

actions that should be taken for ensuring the safe operation of the pipelines are

also determined. As the risk goes higher, certain inspections and renewals

should be carried out within shorter periods. A suggestion for such follow-up

actions are given in Table 9. The inspection intervals should be reconsidered

based on the local conditions where this risk analysis will be used.

Table 9 Follow-up Actions based on Risk Matrix

Risk

Level

Inspection

Priority

Inspection

Methodology Inspection Interval

Urgent Direct

Immediate direct

inspections & New

interval determination

High Indirect & Direct Carry out the

inspections in 3 months

Medium Indirect & Direct Carry out the

inspections in 6 months

Low Indirect

Maximum inspection

interval (e.g. 5 years)

If the risk is very high at some locations of a pipeline, then those

locations should be inspected though direct methodologies to investigate the

state of these locations (i.e. the thickness loss). If these locations are

49

deteriorated as estimated through the risk matrix, then an appropriate renewal

technique (repairs) should be applied to these locations. If the defects are

properly repaired, then those locations can be considered to have low risk so

that the next inspection interval is determined accordingly.

The pipelines falling into the other risk categories are ranked according

to their risk levels and inspections are carried out with the intervals given in

Table 13. If the risk ‘low’ or very ‘very low’, then the inspections can be carried

out with maximum intervals.

If there is no recently recorded indirect inspection results for a pipeline,

then those pipelines are given high priority in the inspection ranking so that the

inspections are carried out as soon as possible. Then the risk is calculated again

incorporating the inspection results and the next interval timeline is determined

according to Table 16.

3.2 Case Study

The RBI model is applied to Ulsan Onsan Industrial Complex buried

pipelines. The evaluation of soundness of the underground pipeline system of

the industrial complex is decided to be performed by targeting exemplified

areas of the whole system rather than evaluating every single pipeline in the

system. Total of 6 target areas are determined based on considerations of

environmental conditions, population density, etc. These areas are explained in

50

Table 10 and shown in figures 16-1~16-6. For each area, an about 300m section

of each and all pipelines passing through, are evaluated in scope of this project.

Table 10 Target Area Description

Section Location Environment Target

Length (m)

Area 1 KP Chemicals Factory

Vicinity

mountainous,

paved road 300

Area 2 Waste Water Treatment

Facility, near watercourse

by a river,

unpaved road 300

Area 3 SK Chemical Synthesis NEP

Factory Vicinity

flatland, paved

road 300

Area 4 Crossroads Vicinity Highway flatland, paved

road 300

Area 5 Samsung Chemicals ~

FarmHannong Vicinity

seashore, paved

road 300

Area 6 Vopak Terminal Vicinity seashore, paved

road 300

Figure 16-1 Area 1

Figure 16-2 Area 2

51

Figure 16-3 Area 3

Figure 16-4 Area 4

Figure 16-5 Area 5

Figure 16-6 Area 6

As the first step of the analysis, basic pipeline information, such as

pipeline routes, depths, materials, carried fluids, diameters, thicknesses, etc. are

investigated. The pipeline information that are essential risk analysis are

summarized in Tables 11~16. The pipeline information given in this thesis are

artificial in order to avoid confidentiality issues. In the actual case, there are

more pipelines in each area and the pipeline information differs. These artificial

numbers used here serve the purpose of exemplifying how the model is applied

52

to underground pipelines and to illustrate what type of information needed for

the analysis. The indirect inspection methodologies (soil resistivity

measurements, CIPS, and DCVG) are applied to each pipeline (the actual

pipelines) in the defined areas.

53

Table 11 Area 1 Pipeline Information L

ine

No

Op

erati

ng

tim

e (y

)

Dia

met

er

(mm

)

Len

gth

(m)

Pip

e

Ma

teri

al

Co

ati

ng

Ma

teri

al

Dep

th (

m)

Ca

rrie

d

Flu

id

Op

erati

ng

Pre

ssu

re

Ra

ng

e

(ba

r)

1 39 100 1355 CS PE 1.1 Butadiene 19.6-68.6

2 29 100 1210 CS PE 1.1 SM (Styrene

Monomer) 9.8-19.6

3 10 400 645 CS PE 1.5 Natural gas 2.9-9.8

4 27 100 388 CS PE 1.7 Ethanol 19.6-68.6

5 27 100 3212 CS PE 1.9 Ammonia 19.6-68.6

6 17 150 2621 CS PE 1.4 Butadiene 9.8-19.6

7 3 700 1242 CS PE

2.4 Low steam

(water) 9.8-19.6

8 3 80 4731 CS PE

1.4 Low steam

(water) 2.9-9.8

9 19 100 927 CS PE 1.4 Acrylonitrile 9.8-19.6

10 38 40 2545 CS PE 1.5 Nitrogen 9.8-19.6

11 38 100 1205 CS PE 1.4 Propylene 19.6-68.6


13 38 100 2303 CS PE 1.3 Ammonia 19.6-68.6

14 25 100 1201

2 CS PE 1.5 Methanol 19.6-68.6

15 25 100 2209 CS PE 1.8 Hydrogen 19.6-68.6

16 25 150 2209 CS PE 1.8 Carbon

dioxide 19.6-68.6

17 25 100 1489 CS PE 1.5 Ethylhexanol 9.8-19.6

54


ine

No

Op

erati

ng

tim

e (y

)

Dia

met

er

(mm

)

Len

gth

(m)

Pip

e

Ma

teri

al

Co

ati

ng

Ma

teri

al

Dep

th (

m)

Ca

rrie

d

Flu

id

Op

erati

ng

Pre

ssu

re

Ra

ng

e

(ba

r)

1 24 100 2753 CS PE 1.7 Oxygen 19.6-68.6

2 24 200 2275 CS PE 1.7 Nitrogen 19.6-68.7

3 28 75 1755 CS PE 1.7 Hydrogen 19.6-68.8

Table 13 Area 3 Pipeline Information

Lin

e N

o

Op

erati

ng

tim

e (y

)

Dia

met

er

(mm

)

Len

gth

(m)

Pip

e

Mate

rial

Coati

ng

Mate

rial

Dep

th (

m)

Carr

ied

Flu

id

Op

erati

ng

Pre

ssu

re

Ran

ge

(bar)

1 30 150 2050 CS ASP 1.7 Xylene 9.8-19.6

2 30 150 749 CS ASP 1.4 Ethylene 19.6-68.6

3 30 100 750 CS ASP 1.4 Propylene

Oxide 9.8-19.6

4 19 150 820 CS PE 1.5 propylene 9.8-19.6

5 24 300 685 CS PE 1.4 nitrogen 9.8-19.7

6 24 200 646 CS PE 1.5 oxygen 9.8-19.8

7 16 300 681 CS PE 1.5 nitrogen 9.8-19.9

8 44 100 2527 CS ASP 1.1 nitrogen 9.8-19.6

9 44 100 2527 CS ASP 1.1 nitrogen 9.8-19.6

10 22 150 591 CS PE 1.1 nitrogen 9.8-19.6

55


ine

No

Op

erati

ng

tim

e (y

)

Dia

met

er

(mm

)

Len

gth

(m)

Pip

e

Ma

teri

al

Co

ati

ng

Ma

teri

al

Dep

th (

m)

Ca

rrie

d

Flu

id

Op

erati

ng

Pre

ssu

re

Ra

ng

e

(ba

r)

1 13 100 985 CS PE 1.8 p-Xylene 19.6-68.6

2 13 100 695 CS PE 2.2

SM

(Styrene

Monomer)

9.8-19.6

3 4 80 4731 CS PE 1.8 H2O 9.8-19.6

4 4 700 2246 CS PE 2.2 H2O 9.8-19.6

5 27 100 3452 CS PE 2.3 ammonia 19.6-68.6

6 27 100 3213 CS PE 1.9 ammonia 19.6-68.6

7 27 125 3196 CS PE 1.4 Benzene 19.6-68.6

8 17 150 2622 CS PE 1.4 Butadiene 9.8-19.6

9 38 40 2546 CS PE 1.5 nitrogen 9.8-19.6

10 38 100 3454 CS PE 1.6 propylene 19.6-68.6

11 25 100 87 CS PE 1.7 Hydrogen 19.6-68.6

12 25 75 87 CS PE 1.8 Hydrogen 19.6-68.6

13 25 150 87 CS PE 1.9 carbon

dioxide 19.6-68.6

56


ine

No

Op

erati

ng

tim

e (y

)

Dia

met

er

(mm

)

Len

gth

(m)

Pip

e

Ma

teri

al

Co

ati

ng

Ma

teri

al

Dep

th (

m)

Ca

rrie

d

Flu

id

Op

erati

ng

Pre

ssu

re

Ra

ng

e

(ba

r)

1 10 300 255 CS PE 1.5 natural gas 2.9-9.8

2 27 125 2706 CS PE 1.4 Benzene 19.6-68.6

3 18 100 98 CS PE 1.5 SM (Styrene

Monomer) 9.8-19.8

4 18 100 97 CS PE 1.5 SM (Styrene

Monomer) 9.8-19.9

5 18 100 97 CS PE 1.5 SM (Styrene

Monomer) 9.8-19.10

6 17 150 197 CS PE 1.7 Isononyl

alcohol 9.8-19.13


8 17 150 197 SSP PE 1.3 Acrylonitrile 9.8-19.16

9 17 100 197 CS PE 1.3 Butadiene 9.8-19.17

10 17 80 199 CS PE 1.7 nitrogen 9.8-19.18

11 39 100 1238 CS PE 1.4 Butadiene 19.6-68.6

12 32 100 133 CS PE 1.3 ammonia 19.6-68.6

13 29 100 267 CS PE 1.3 p-xylene 19.6-68.6

57


ine

No

Op

erati

ng

tim

e (y

)

Dia

met

er

(mm

)

Len

gth

(m)

Pip

e

Ma

teri

al

Co

ati

ng

Ma

teri

al

Dep

th (

m)

Ca

rrie

d

Flu

id

Op

erati

ng

Pre

ssu

re

Ra

ng

e

(ba

r)

1 18 300 570 CS PE 1.5 natural gas 2.9-9.8

PoF Calculations

PoF levels are determined as described in the first section of Chapter 3.

First, a prior PoF level is calculated through remaining life analysis considering

only internal corrosion. Then, external corrosion is incorporated into the model

through adjustments of the prior PoF levels considering the pipeline priority

determination criteria for direct inspections. However, indirect inspections are

carried out only for 300m distances for each pipeline in thus study and it is

concluded that there is ‘no indication’ of external corrosion on any spot of these

pipelines. The reason is that, although some locations having coating defects or

CP system deficiency are detected, none of them existed at the same spot.

Therefore, there were no changes in PoF levels after consideration of indirect

inspection results. PoF levels calculated through remaining life analysis are

given in Tables 17~22 for pipelines in each area.

58

Table 17 Area 1 Pipelines PoF Calculation Results

Ca

rrie

d F

luid

Ma

x.

Pre

ssu

re

(Mp

a)

Min

. A

llo

wa

ble

Th

ick

nes

s (m

m)

Des

ign

Th

ick

nes

s (m

m)

Fu

ture

All

ow

an

ce (

mm

)

Co

rro

sio

n R

ate

(mm

/y)

Rem

ain

ing

Lif

e

(RL

) (y

)

T/R

L

Po

F l

evel

Butadiene 68.6 2.56 6.02 3.46 0.03 99 0.02 1

SM (Styrene

Monomer) 19.6 0.72 6.02 3.52 0.11 3 0.67 2

Natural gas 9.8 1.43 9.53 7.03 0.03 271 0.01 1

Ethanol 68.6 2.56 6.02 3.46 0.03 111 0.02 1

Ammonia 68.6 2.56 6.02 3.46 0.10 8 0.26 1

Butadiene 19.6 1.07 7.11 4.61 0.03 167 0.01 1

Low steam

(water) 19.6 5.01 9.53 4.51 0.20 20 0.10

1

Low steam

(water) 0.1 0.03 5.49 2.99 0.20 12 0.17

1

Acrylonitrile 19.6 0.72 6.02 3.52 0.10 16 0.12 1

Nitrogen 19.6 0.29 3.68 1.18 0.03 9 0.22 1

Propylene 68.6 2.56 6.02 3.46 0.03 100 0.02 1

Acrylonitrile 68.6 2.56 6.02 3.46 0.10 3 0.58 2

Ammonia 68.6 2.56 6.02 3.46 0.10 3 0.58 2

Methanol 68.6 2.56 6.02 3.46 0.03 113 0.02 1

Hydrogen 68.6 2.56 6.02 3.46 0.03 113 0.02 1

Carbon

dioxide 68.6 3.84 7.11 3.27 0.03 106 0.02

1

Ethylhexanol 19.6 0.72 6.02 3.52 0.10 10 0.20 1

59


Ca

rrie

d F

luid

Ma

x.

Pre

ssu

re

(Mp

a)

Min

. A

llo

wa

ble

Th

ick

nes

s (m

m)

Des

ign

Th

ick

nes

s (m

m)

Fu

ture

All

ow

an

ce (

mm

)

Co

rro

sio

n R

ate

(mm

/y)

Rem

ain

ing

Lif

e

(RL

) (y

)

T/R

L

Po

F l

evel

Oxygen 6.86 2.56 6.02 3.46 0.03 114 0.02 1

Nitrogen 6.86 5.12 8.18 3.06 0.03 98 0.02 1

Hydrogen 6.86 1.92 5.16 2.66 0.03 78 0.03 1


Carr

ied

Flu

id

Max.

Pre

ssu

re

(Mp

a)

Min

. A

llow

ab

le

Th

ick

nes

s (m

m)

Des

ign

Th

ick

nes

s (m

m)

Fu

ture

All

ow

an

ce (

mm

)

Corr

osi

on

Rate

(mm

/y)

Rem

ain

ing L

ife

(RL

) (y

)

T/R

L

PoF

lev

el

Xylene 1.96 1.07 7.11 4.61 0.11 12 0.17 1

Ethylene 6.86 3.84 7.11 3.27 0.03 101 0.02 1

Propylene

Oxide 1.96 0.72 6.02 3.52 0.10 5 0.38

1

propylene 1.96 1.07 7.11 4.61 0.03 165 0.01 1

nitrogen 1.96 2.15 9.53 7.03 0.03 257 0.01 1

oxygen 1.96 1.43 8.18 5.68 0.03 203 0.01 1

nitrogen 1.96 2.15 9.53 7.03 0.03 265 0.01 1

nitrogen 1.96 0.72 6.02 3.50 0.03 97 0.02 1

nitrogen 1.96 0.72 6.02 3.50 0.03 97 0.02 1

nitrogen 1.96 1.07 7.10 4.60 0.03 162 0.01 1

60


Ca

rrie

d F

luid

Ma

x.

Pre

ssu

re

(Mp

a)

Min

. A

llo

wa

ble

Th

ick

nes

s (m

m)

Des

ign

Th

ick

nes

s (m

m)

Fu

ture

All

ow

an

ce (

mm

)

Co

rro

sio

n R

ate

(mm

/y)

Rem

ain

ing

Lif

e

(RL

) (y

)

T/R

L

Po

F l

evel

p-Xylene 6.86 2.56 6.02 3.46 0.11 18 0.11 1

SM (Styrene

Monomer) 1.96 0.72 6.02 3.52 0.11 19 0.11 1

H2O 0.1 0.03 5.49 2.99 0.15 16 0.13 1

H2O 1.96 5.01 9.53 4.51 0.15 26 0.08 1

ammonia 6.86 2.56 6.02 3.46 0.10 8 0.26 1

ammonia 6.86 2.56 6.02 3.46 0.10 8 0.26 1

Benzene 6.86 3.20 6.55 3.35 0.10 7 0.31 1

Butadiene 1.96 1.07 7.11 4.61 0.03 167 0.01 1

nitrogen 1.96 0.29 3.68 1.18 0.03 9 0.21 1

propylene 6.86 2.56 6.02 3.46 0.03 100 0.02 1

Hydrogen 6.86 2.56 6.02 3.46 0.03 113 0.02 1

Hydrogen 6.86 1.92 5.16 2.66 0.03 81 0.02 1

carbon

dioxide 6.86 3.84 7.11 3.27 0.03 106 0.02

1

61


Ca

rrie

d F

luid

Ma

x.

Pre

ssu

re

(Mp

a)

Min

. A

llo

wa

ble

Th

ick

nes

s (m

m)

Des

ign

Th

ick

nes

s (m

m)

Fu

ture

All

ow

an

ce (

mm

)

Co

rro

sio

n R

ate

(mm

/y)

Rem

ain

ing

Lif

e

(RL

) (y

)

T/R

L

Po

F l

evel

natural gas 0.98 1.07 9.53 7.03 0.03 271 0.01 1

Benzene 6.86 3.20 6.55 3.35 0.10 7 0.31 1

SM (Styrene

Monomer) 1.96 0.72 6.02 3.52 0.11 14 0.14

1

SM (Styrene

Monomer) 1.96 0.72 6.02 3.52 0.11 14 0.14

1

SM (Styrene

Monomer) 1.96 0.72 6.02 3.52 0.11 14 0.14

1

Isononyl

alcohol 1.96 1.07 7.11 4.61 0.10 29 0.07

1

Acrylonitrile 1.96 1.07 7.11 4.61 0.10 29 0.07 1

Acrylonitrile 1.96 1.29 7.11 4.61 0.10 29 0.07 1

Butadiene 1.96 0.72 6.02 3.52 0.03 124 0.02 1

nitrogen 1.96 0.57 5.49 2.99 0.03 102 0.02 1

Butadiene 6.86 2.56 6.02 3.46 0.03 99 0.02 1

ammonia 6.86 2.56 6.02 3.46 0.10 3 0.77 3

p-xylene 6.86 2.56 6.02 3.46 0.11 2 0.82 3

62

Table 22 Area 6 Pipeline PoF Calculation Results

Ca

rrie

d F

luid

Ma

x.

Pre

ssu

re

(Mp

a)

Min

. A

llo

wa

ble

Th

ick

nes

s (m

m)

Des

ign

Th

ick

nes

s (m

m)

Fu

ture

All

ow

an

ce (

mm

)

Co

rro

sio

n R

ate

(mm

/y)

Rem

ain

ing

Lif

e

(RL

) (y

)

T/R

L

Po

F l

evel

natural gas 0.98 1.07 9.53 7.03 0.03 274 0.01 1

CoF Calculations

CoF calculation results are summarized in Tables 23~28 for pipelines

in each area.

Table 23 Area 1 Pipelines CoF Calculation Results

Carr

ied

Flu

id

Inven

tory

(m³)

Den

sity

(kg/m

3)

Nm

Nh

Com

bu

sti-

bil

ity

Nu

mb

er

(cf)

T

oxic

ity

Nu

mb

er

(ch

)

Mass

(k

g)

CoF

Butadiene 10.64 637 29 2 82.21 4.82 6773 E

SM (Styrene

Monomer) 9.50 911 24 2 48.53 3.16 8654 C

Natural gas 81.05 7 21 1 49.13 2.14 532 C

Ethanol 3.05 805 16 0 37.24 0.00 2457 B

Ammonia 25.22 615 4 3 11.32 7.23 15521 D

Butadiene 46.31 630 29 2 82.37 4.36 29165 E

Low steam

(water) 477.82 1015 0 0 0.00 0.00 485149 A

Low steam

(water) 23.77 1015 0 0 0.00 0.00 24122 A

63

Acrylonitrile 7.28 808 30 4 65.85 7.31 5878 D

Nitrogen 3.20 23 0 0 0.00 0.00 73 B

Propylene 9.46 538 21 1 58.86 2.41 5089 D

Acrylonitrile 18.08 810 30 4 76.36 8.24 14649 E

Ammonia 18.08 615 4 3 11.16 7.23 11127 D

Methanol 94.30 800 16 1 44.05 2.06 75404 B

Hydrogen 17.34 6 21 0 57.05 0.00 100 D

Carbon

dioxide 39.03 854 0 1 0.00 2.41 33330 C

Ethylhexanol 11.70 839 14 2 28.43 3.16 9810 C

Table 24 Area 2 Pipelines CoF Calculation Results

Carr

ied

Flu

id

Inven

tory

(m³)

Den

sity

(kg/m

3)

Nm

Nh

Com

bu

sti-

bil

ity

Nu

mb

er

(cf)

T

oxic

ity

Nu

mb

er

(ch

)

Mass

(k

g)

CoF

Oxygen 21.61 92 0 0 0.00 0.00 1981 C

Nitrogen 71.46 80 0 0 0.00 0.00 5732 D

Hydrogen 7.75 6 21 0 58.79 0.00 45 D

64

Table 25 Area 3 Pipelines CoF Calculation Results C

arr

ied

Flu

id

Inv

ento

ry

(m³)

Den

sity

(kg

/m3

)

Nm

Nh

Co

mb

ust

i-

bil

ity

Nu

mb

er

(cf)

T

ox

icit

y

Nu

mb

er

(ch

)

Ma

ss (

kg

)

Co

F

Xylene 36.22 887 16 2 35.88 3.16 32134 C

Ethylene 13.23 1559 24 1 72.41 2.41 20625 E

Propylene

Oxide 5.89 836 21 2 45.61 3.66 4926 C

propylene 14.49 526 21 1 55.05 2.18 7624 D

nitrogen 48.40 23 0 0 0.00 0.00 1109 C

oxygen 20.31 26 0 0 0.00 0.00 532 C

nitrogen 48.15 23 0 0 0.00 0.00 1104 C

nitrogen 19.84 23 0 0 0.00 0.00 455 C

nitrogen 19.84 23 0 0 0.00 0.00 455 C

nitrogen 10.45 23 0 0 0.00 0.00 240 C

65


arr

ied

Flu

id

Inv

ento

ry

(m³)

Den

sity

(kg

/m3

)

Nm

Nh

Co

mb

ust

i-

bil

ity

Nu

mb

er

(cf)

T

ox

icit

y

Nu

mb

er

(ch

)

Ma

ss (

kg

)

Co

F

p-Xylene 7.85 872 16 2 35.60 3.62 6843 C

SM (Styrene

Monomer) 7.85 911 24 2 47.93 3.16 7149 C

H2O 5.02 1015 0 0 0.00 0.00 5098 A

H2O 384.65 1015 0 0 0.00 0.00 390553 A

ammonia 7.85 615 4 3 10.82 7.23 4831 D

ammonia 7.85 615 4 3 10.82 7.23 4831 D

Benzene 12.27 886 16 2 40.57 4.12 10873 C

Butadiene 17.66 630 29 2 77.48 4.36 11124 E

nitrogen 1.26 23 0 0 0.00 0.00 29 B

propylene 7.85 538 21 1 58.40 2.41 4221 D

Hydrogen 7.85 6 21 0 56.34 0.00 45 D

Hydrogen 4.42 6 21 0 55.92 0.00 25 D

carbon

dioxide 17.66 854 0 1 0.00 2.41 15084 C

66


arr

ied

Flu

id

Inv

ento

ry

(m³)

Den

sity

(kg

/m3

)

Nm

Nh

Co

mb

ust

i-

bil

ity

Nu

mb

er

(cf)

T

ox

icit

y

Nu

mb

er

(ch

)

Ma

ss (

kg

)

Co

F

natural gas 18.00 7 21 1 47.57 2.14 118 C

Benzene 33.19 886 16 2 43.27 4.12 29424 C

SM (Styrene

Monomer) 0.77 911 24 2 42.82 3.16 700 C

SM (Styrene

Monomer) 0.76 911 24 2 42.81 3.16 694 C

SM (Styrene

Monomer) 0.76 911 24 2 42.81 3.16 692 C

Isononyl

alcohol 3.49 828 10 0 18.98 0.00 2887 A

Acrylonitrile 3.50 808 30 4 63.64 7.31 2826 D

Acrylonitrile 3.49 808 30 4 63.64 7.31 2817 D

Butadiene 1.55 630 29 2 69.98 4.36 976 E

nitrogen 1.00 23 0 0 0.00 0.00 23 B

Butadiene 9.72 637 29 2 81.88 4.82 6186 E

ammonia 1.04 615 4 3 10.28 7.23 642 D

p-xylene 2.10 872 16 2 33.40 3.62 1827 C

67


arr

ied

Flu

id

Inv

ento

ry

(m³)

Den

sity

(kg

/m3

)

Nm

Nh

Co

mb

ust

i-

bil

ity

Nu

mb

er

(cf)

T

ox

icit

y

Nu

mb

er

(ch

)

Ma

ss (

kg

)

Co

F

natural gas 40.28 7 21 1 48.32 2.14 264 C

Interpretation of PoF and CoF Results on a Risk Matrix

PoF

5

4

3

2 1

1 2 3 3 4 2

A B C D E

CoF

Area 1

PoF

5

4

3

2

1 1 2

A B C D E

CoF

Area 2

PoF

5

4

3

2

1 8 1 1

A B C D E

CoF

Area 3

PoF

5

4

3

2

1 2 1 4 5 1

A B C D E

CoF

Area 4

68

PoF

5

4

3 1 1

2

1 1 1 5 2 2

A B C D E

CoF

Area 5

PoF

5

4

3

2

1 1

A B C D E

CoF

Area 6

Figure 17 Risk Matrix for Each Area

Table 29 Follow-up Actions based on the Risk Matrix Results

Risk

Levels

Number of

Pipelines List of Pipelines Actions

None -

Immediate direct

inspections & New

interval determination

None -

Schedule and carry

out direct inspections

in 3 months

8

Area 1: Pipe no 1, 12

Area 3: Pipe no 2

Area 4: Pipe no 8

Area 5: Pipe no 9, 11, 12, 13

Schedule and carry

out direct inspections

in 6 months

49 All the rest

Maximum inspection

interval (e.g. 5 years)-

Direct inspections not

required

69

As seen from the risk matrix results, there are no high risk pipelines

among Ulsan Onsan Industrial Complex Pipelines that are investigated in this

study. The main reason behind these results is that the indirect inspection results

came out to be safe against external corrosion. However, the inspections were

carried out only for 300 meters length of each pipeline. Since inspections

applied to only a part of pipelines, the results cannot represent the whole system.

Therefore, it is not safe to conclude that the pipelines are actually safe. Indirect

inspections should be applied to the whole length of pipelines and it should be

supplemented by direct inspections that are carried out especially where defects

are detected through indirect inspections and at stress intensifying locations

such as turns, in line equipment, and welded parts.

3.3 Discussions on the RBI Model

Determining inspection schedules through an RBI model is better than

having deterministic inspection intervals since RBI models require the pipeline

owners to investigate the current state of pipelines. On the other hand, the

factors considered in each RBI model might be different and such differences

might lead to completely different results. In this part of the thesis, the

developed model and possible improvements on the model will be discussed.

70

PoF Model

The probability of failure of a pipeline depends on various factors but

internal and external corrosion are preferred to be included in the model. The

reason is that, the other main failure mechanisms such as third party damages

and welding defects are not easy to incorporate into the model. Instead, it should

be made sure that such factors are not active. For example, the pipelines should

be installed below certain depths so that they will not be affected by the

activities above the soil such as high traffic load, construction activities, and

vibrations due to other loads. The pipeline locations should be well recorded so

that they are not hit accidentally during construction activities in the

surroundings. Welding defects are inspected during direct inspections by non-

destructive tests. It should also be checked during installations that weld defects

do not exist before burying the pipelines. If such precautions are taken before

and during installations, potential accidents will be prevented and incorporation

of these factors into PoF model will not be really necessary.

Using references for internal corrosion rates give conservative results

since those are the maximum corrosion rates indicating if the pipe material is

compatible with the carrie

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